10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2018

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	I.R.S. Employer Identification Number
001-08489	DOMINION ENERGY, INC.	54-1229715
000-55337	VIRGINIA ELECTRIC AND POWER COMPANY	54-0418825
001-37591	DOMINION ENERGY GAS HOLDINGS, LLC	46-3639580
	VIRGINIA (State or other jurisdiction of incorporation or organization)
	120 TREDEGAR STREET RICHMOND, VIRGINIA (Address of principal executive offices)	23219 (Zip Code)
	(804) 819-2000 (Registrants’ telephone number)

Securities registered pursuant to Section 12(b) of the Act:

Registrant	Title of Each Class	Name of Each Exchange on Which Registered
DOMINION ENERGY, INC.	Common Stock, no par value	New York Stock Exchange
	2016 Series A 6.75% Corporate Units	New York Stock Exchange
	2016 Series A 5.25% Enhanced Junior Subordinated Notes	New York Stock Exchange
DOMINION ENERGY GAS HOLDINGS, LLC	2014 Series C 4.6% Senior Notes	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

VIRGINIA ELECTRIC AND POWER COMPANY

Common Stock, no par value

DOMINION ENERGY GAS HOLDINGS, LLC

Limited Liability Company Membership Interests

Indicate by check mark whether the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.

Dominion Energy, Inc.    Yes  ☒    No  ☐        Virginia Electric and Power Company    Yes  ☒    No  ☐        Dominion Energy Gas Holdings, LLC    Yes  ☒    No  ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Dominion Energy, Inc.    Yes  ☐    No  ☒        Virginia Electric and Power Company    Yes   ☐    No  ☒        Dominion Energy Gas Holdings, LLC    Yes  ☐    No  ☒

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 Energy, Inc.    Yes  ☒    No  ☐    Virginia Electric and Power Company    Yes  ☒    No  ☐     Dominion Energy Gas Holdings, LLC     Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).

Dominion Energy, Inc.    Yes  ☒    No  ☐        Virginia Electric and Power Company    Yes  ☒    No  ☐        Dominion Energy Gas Holdings, LLC    Yes  ☒    No  ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Dominion Energy, Inc.    ☒        Virginia Electric and Power Company    ☒        Dominion Energy Gas Holdings, LLC    ☒

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

Dominion Energy, Inc.

Large accelerated filer  ☒	Accelerated filer  ☐	Non-accelerated filer  ☐	Smaller reporting company  ☐
			Emerging growth company  ☐

Virginia Electric and Power Company

Large accelerated filer  ☐	Accelerated filer  ☐	Non-accelerated filer  ☒	Smaller reporting company  ☐
			Emerging growth company  ☐

Dominion Energy Gas Holdings, LLC

Large accelerated filer  ☐	Accelerated filer  ☐	Non-accelerated filer  ☒	Smaller reporting company  ☐
			Emerging growth company  ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

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

Dominion Energy, Inc.    Yes  ☐    No  ☒        Virginia Electric and Power Company    Yes  ☐    No  ☒        Dominion Energy Gas Holdings, LLC    Yes  ☐    No  ☒

The aggregate market value of Dominion Energy, Inc. common stock held by non-affiliates of Dominion Energy was approximately $44.4 billion based on the closing price of Dominion Energy’s common stock as reported on the New York Stock Exchange as of the last day of Dominion Energy’s most recently completed second fiscal quarter. Dominion Energy is the sole holder of Virginia Electric and Power Company common stock. At February 15, 2019, Dominion Energy had 799,314,079 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding. Dominion Energy, Inc. holds all of the membership interests of Dominion Energy Gas Holdings, LLC.

DOCUMENT INCORPORATED BY REFERENCE.

Portions of Dominion Energy’s 2019 Proxy Statement are incorporated by reference in Part III.

This combined Form 10-K represents separate filings by Dominion Energy, Inc., Virginia Electric and Power Company and Dominion Energy 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 Energy Gas Holdings, LLC make no representations as to the information relating to Dominion Energy, Inc.’s other operations.

VIRGINIA ELECTRIC AND POWER COMPANY AND DOMINION ENERGY GAS HOLDINGS, LLC MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND (b) OF FORM 10-K AND ARE FILING THIS FORM 10-K UNDER THE REDUCED DISCLOSURE FORMAT.

Dominion Energy, Inc., Virginia Electric and

Power Company and Dominion Energy Gas Holdings, LLC

Item Number		Page Number
	Glossary of Terms	3
Part I
1.	Business	8
1A.	Risk Factors	29
1B.	Unresolved Staff Comments	37
2.	Properties	38
3.	Legal Proceedings	43
4.	Mine Safety Disclosures	43
	Executive Officers of Dominion Energy	44
Part II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	45
6.	Selected Financial Data	46
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	47
7A.	Quantitative and Qualitative Disclosures About Market Risk	66
8.	Financial Statements and Supplementary Data	69
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	192
9A.	Controls and Procedures	192
9B.	Other Information	195
Part III
10.	Directors, Executive Officers and Corporate Governance	196
11.	Executive Compensation	196
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	196
13.	Certain Relationships and Related Transactions, and Director Independence	196
14.	Principal Accountant Fees and Services	197
Part IV
15.	Exhibits and Financial Statement Schedules	198
16.	Form 10-K Summary	205

2

Glossary of Terms

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

Abbreviation or Acronym	Definition
2013 Equity Units	Dominion Energy’s 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013
2014 Equity Units	Dominion Energy’s 2014 Series A Equity Units issued in July 2014
2016 Equity Units	Dominion Energy’s 2016 Series A Equity Units issued in August 2016
2017 Tax Reform Act	An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (previously known as The Tax Cuts and Jobs Act) enacted on December 22, 2017
2019 Proxy Statement	Dominion Energy 2019 Proxy Statement, File No. 001-08489
ABO	Accumulated benefit obligation
AFUDC	Allowance for funds used during construction
Align RNG	Align RNG, LLC, a joint venture between Dominion Energy and Smithfield Foods, Inc.
AMI	Advanced Metering Infrastructure
AMR	Automated meter reading program deployed by East Ohio
AOCI	Accumulated other comprehensive income (loss)
ARO	Asset retirement obligation
Atlantic Coast Pipeline	Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion Energy, Duke and Southern Company Gas
Atlantic Coast Pipeline Project	The approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina which will be owned by Dominion Energy, Duke and Southern Company Gas and constructed and operated by DETI
BACT	Best available control technology
Bankruptcy Court	U.S. Bankruptcy Court for the Southern District of New York
bcf	Billion cubic feet
bcfe	Billion cubic feet equivalent
Bear Garden	A 590 MW combined-cycle, natural gas-fired power station in Buckingham County, Virginia
BGEPA Blue Racer	Bald and Golden Eagle Protection Act Blue Racer Midstream, LLC, a joint venture between Caiman and FR BR Holdings, LLC effective December 2018
BP	BP Wind Energy North America Inc.
Brunswick County	A 1,376 MW combined-cycle, natural gas-fired power station in Brunswick County, Virginia
CAA	Clean Air Act
Caiman	Caiman Energy II, LLC
CAISO	California ISO
CAO	Chief Accounting Officer
CCR	Coal combustion residual
CEA	Commodity Exchange Act
CEO	Chief Executive Officer
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund
CFO	Chief Financial Officer
CGN Committee	Compensation, Governance and Nominating Committee of Dominion Energy’s Board of Directors
Clean Power Plan	Regulations issued by the EPA in August 2015 for states to follow in developing plans to reduce CO2 emissions from existing fossil fuel-fired electric generating units, stayed by the U.S. Supreme Court in February 2016 pending resolution of court challenges by certain states
CNG	Consolidated Natural Gas Company
CO2	Carbon dioxide
Colonial Trail West	An approximately 142 MW proposed utility-scale solar power station located in Surry County, Virginia
Companies	Dominion Energy, Virginia Power and Dominion Energy 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
Corporate Unit	A stock purchase contract and 1/20 or 1/40 interest in a RSN issued by Dominion Energy
Cove Point	Dominion Energy Cove Point LNG, LP
Cove Point Holdings	Cove Point GP Holding Company, LLC
Cove Point LNG Facility	An LNG terminalling and storage facility located on the Chesapeake Bay in Lusby, Maryland owned by Cove Point
Cove Point Pipeline	A 136-mile natural gas pipeline owned by Cove Point that connects the Cove Point LNG Facility to interstate natural gas pipelines
CPCN	Certificate of Public Convenience and Necessity
CWA	Clean Water Act
DECG	Dominion Energy Carolina Gas Transmission, LLC
DES	Dominion Energy Services, Inc.
DETI	Dominion Energy Transmission, Inc.
DGI	Dominion Generation, Inc.

3

Abbreviation or Acronym	Definition
DGP	Dominion Gathering and Processing, Inc.
Dodd-Frank Act	The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOE	U.S. Department of Energy
Dominion Energy	The legal entity, Dominion Energy, Inc., one or more of its consolidated subsidiaries (other than Virginia Power and Dominion Energy Gas) or operating segments, or the entirety of Dominion Energy, Inc. and its consolidated subsidiaries
Dominion Energy Direct®	A dividend reinvestment and open enrollment direct stock purchase plan
Dominion Energy Gas	The legal entity, Dominion Energy Gas Holdings, LLC, one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion Energy Gas Holdings, LLC and its consolidated subsidiaries
Dominion Energy Midstream	The legal entity, Dominion Energy Midstream Partners, LP, one or more of its consolidated subsidiaries, Cove Point Holdings, Iroquois GP Holding Company, LLC, DECG and Dominion Energy Questar Pipeline (beginning December 1, 2016), or the entirety of Dominion Energy Midstream Partners, LP and its consolidated subsidiaries
Dominion Energy Questar	The legal entity, Dominion Energy Questar Corporation, one or more of its consolidated subsidiaries, or the entirety of Dominion Energy Questar Corporation and its consolidated subsidiaries
Dominion Energy Questar Combination	Dominion Energy’s acquisition of Dominion Energy Questar completed on September 16, 2016 pursuant to the terms of the agreement and plan of merger entered on January 31, 2016
Dominion Energy Questar Pipeline	Dominion Energy Questar Pipeline, LLC, one or more of its consolidated subsidiaries, or the entirety of Dominion Energy Questar Pipeline, LLC and its consolidated subsidiaries
Dominion Iroquois	Dominion Iroquois, Inc., which, effective May 2016, holds a 24.07% noncontrolling partnership interest in Iroquois
DSM	Demand-side management
Dth	Dekatherm
Duke	The legal entity, Duke Energy Corporation, one or more of its consolidated subsidiaries or operating segments, or the entirety of Duke Energy Corporation and its consolidated subsidiaries
Eagle Solar	Eagle Solar, LLC, a wholly-owned subsidiary of DGI
East Ohio	The East Ohio Gas Company, doing business as Dominion Energy Ohio
Eastern Market Access Project	Project to provide 294,000 Dths/day of transportation service to help meet demand for natural gas for Washington Gas Light Company, a local gas utility serving customers in D.C., Virginia and Maryland, and Mattawoman Energy, LLC for its new electric power generation facility to be built in Maryland
Energy Choice	Program authorized by the Ohio Commission which provides energy customers with the ability to shop for energy options from a group of suppliers certified by the Ohio Commission
EPA	U.S. Environmental Protection Agency
EPACT	Energy Policy Act of 2005
EPS	Earnings per share
ERISA	Employee Retirement Income Security Act of 1974
ERO	Electric Reliability Organization
ESA Excess Tax Benefits	Endangered Species Act Benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation
Fairless	Fairless power station
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FILOT	Fee in lieu of taxes
Fitch	Fitch Ratings Ltd.
Four Brothers	Four Brothers Solar, LLC, a limited liability company owned by Dominion Energy and Four Brothers Holdings, LLC, a subsidiary of GIP effective August 2018
Fowler Ridge	Fowler I Holdings LLC, a wind-turbine facility joint venture with BP in Benton County, Indiana
FTRs	Financial transmission rights
GAAP	U.S. generally accepted accounting principles
Gal	Gallon
Gas Infrastructure	Gas Infrastructure Group operating segment
GENCO	South Carolina Generating Company, Inc.
GHG	Greenhouse gas
GIP	The legal entity, Global Infrastructure Partners, one or more of its consolidated subsidiaries (including, effective August 2018, Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC, and Iron Springs Renewables, LLC) or operating segments, or the entirety of Global Infrastructure Partners and its consolidated subsidiaries
Granite Mountain	Granite Mountain Holdings, LLC, a limited liability company owned by Dominion Energy and Granite Mountain Renewables, LLC, a subsidiary of GIP effective August 2018
Green Mountain	Green Mountain Power Corporation
GreenHat	GreenHat Energy, LLC

4

Abbreviation or Acronym	Definition
Greensville County	A 1,588 MW combined-cycle, natural gas-fired power station in Greensville County, Virginia
GTSA	Virginia Grid Transformation and Security Act of 2018
Hastings	A natural gas processing and fractionation facility located near Pine Grove, West 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 Energy West Virginia
Idaho Commission	Idaho Public Utilities Commission
IRCA	Intercompany revolving credit agreement
Iron Springs	Iron Springs Holdings, LLC, a limited liability company owned by Dominion Energy and Iron Springs Renewables, LLC, a subsidiary of GIP effective August 2018
Iroquois	Iroquois Gas Transmission System, L.P.
IRS	Internal Revenue Service
ISO	Independent system operator
ISO-NE	ISO New England
July 2016 hybrids	Dominion Energy’s 2016 Series A Enhanced Junior Subordinated Notes due 2076
June 2006 hybrids	Dominion Energy’s 2006 Series A Enhanced Junior Subordinated Notes due 2066
Kewaunee	Kewaunee nuclear power station
kV	Kilovolt
Liability Management Exercise	Dominion Energy exercise in 2014 to redeem certain debt and preferred securities
LIBOR	London Interbank Offered Rate
LIFO	Last-in-first-out inventory method
Liquefaction Project	A natural gas export/liquefaction facility at Cove Point
LNG	Liquefied natural gas
Local 50	International Brotherhood of Electrical Workers Local 50
Local 69	Local 69, Utility Workers Union of America, United Gas Workers
LTIP	Long-term incentive program
Manchester	Manchester power station
Massachusetts Municipal	Massachusetts Municipal Wholesale Electric Company
MATS	Utility Mercury and Air Toxics Standard Rule
MBTA mcf	Migratory Bird Treaty Act of 1918 Thousand cubic feet
mcfe	Thousand cubic feet equivalent
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MGD	Million gallons a day
Millstone	Millstone nuclear power station
Moody’s	Moody’s Investors Service
Mtpa	Million metric tons per annum
MW	Megawatt
MWh	Megawatt hour
Natural Gas Rate Stabilization Act	Legislation effective February 16, 2005 designed to improve and maintain natural gas service infrastructure to meet the needs of customers in South Carolina
NAV	Net asset value
NedPower	NedPower Mount Storm LLC, a wind-turbine facility joint venture between Dominion Energy and Shell in Grant County, West Virginia
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Corporation
NG	Collectively, North East Transmission Co., Inc. and National Grid IGTS Corp.
NGL	Natural gas liquid
NJNR	NJNR Pipeline Company
NND Project	V.C. Summer units 2 and 3 new nuclear development project under which SCANA and Santee Cooper undertook to construct two Westinghouse AP1000 Advanced Passive Safety nuclear units in Jenkinsville, South Carolina
North Anna	North Anna nuclear power station
North Carolina Commission	North Carolina Utilities Commission
Northern System	Collection of 131 miles of various diameter natural gas pipelines in Ohio
NOX	Nitrogen oxide
NRC	U.S. Nuclear Regulatory Commission
NRG	The legal entity, NRG Energy, Inc., one or more of its consolidated subsidiaries (including, effective November 2016 through August 2018, Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC and Iron Springs Renewables, LLC) or operating segments, or the entirety of NRG Energy, Inc. and its consolidated subsidiaries

5

Abbreviation or Acronym	Definition
NSPS	New Source Performance Standards
NYSE	New York Stock Exchange
October 2014 hybrids	Dominion Energy’s 2014 Series A Enhanced Junior Subordinated Notes due 2054
ODEC	Old Dominion Electric Cooperative
Ohio Commission	Public Utilities Commission of Ohio
Order 1000	Order issued by FERC adopting new requirements for electric transmission planning, cost allocation and development
Philadelphia Utility Index	Philadelphia Stock Exchange Utility Index
PHMSA	Pipeline and Hazardous Materials Safety Administration
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.
Power Delivery	Power Delivery Group operating segment
Power Generation	Power Generation Group operating segment
ppb	Parts-per-billion
PREP	Pipeline Replacement and Expansion Program, a program of replacing, upgrading and expanding natural gas utility infrastructure deployed by Hope
PSD	Prevention of significant deterioration
PSNC	Public Service Company of North Carolina, Incorporated
Questar Gas	Questar Gas Company, doing business as Dominion Energy Utah, Dominion Energy Wyoming and Dominion Energy Idaho
RCC	Replacement Capital Covenant
Regulation Act	Legislation effective July 1, 2007, that amended the Virginia Electric Utility Restructuring Act and fuel factor statute, which legislation is also known as the Virginia Electric Utility Regulation Act, as amended in 2015 and 2018
RGGI	Regional Greenhouse Gas Initiative
RICO	Racketeer Influenced and Corrupt Organizations Act
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 E	A rate adjustment clause associated with the recovery of costs related to certain capital projects at Virginia Power’s electric generating stations to comply with federal and state environmental laws and regulations
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 U	A rate adjustment clause associated with the recovery of costs of new underground distribution facilities
Rider US-2	A rate adjustment clause associated with the recovery of costs related to Woodland, Scott Solar and Whitehouse
Rider US-3	A rate adjustment clause associated with the recovery of costs related to Colonial Trail West and Spring Grove 1
Rider W	A rate adjustment clause associated with the recovery of costs related to Warren County
Riders C1A and C2A	Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in DSM cases
ROE	Return on equity
ROIC	Return on invested capital
RSN	Remarketable subordinated note
RTEP	Regional transmission expansion plan
RTO	Regional transmission organization
SAFSTOR	A method of nuclear decommissioning, as defined by the NRC, in which a nuclear facility is placed and maintained in a condition that allows the facility to be safely stored and subsequently decontaminated to levels that permit release for unrestricted use
SAIDI	System Average Interruption Duration Index, metric used to measure electric service reliability
SBL Holdco	SBL Holdco, LLC, a wholly-owned subsidiary of DGI
Santee Cooper	South Carolina Public Service Authority
SCANA	The legal entity, SCANA Corporation, one or more of its consolidated subsidiaries or operating segments, or the entirety of SCANA Corporation and its consolidated subsidiaries

6

Abbreviation or Acronym	Definition
SCANA Combination	Dominion Energy’s acquisition of SCANA completed on January 1, 2019 pursuant to the terms of the SCANA Merger Agreement
SCANA Merger Agreement	Agreement and plan of merger entered on January 2, 2018 between Dominion Energy and SCANA
SCANA Merger Approval Order	Final order issued by the South Carolina Commission on December 21, 2018 setting forth its approval of the SCANA Combination
SCDHEC	South Carolina Department of Health and Environmental Control
SCDOR	South Carolina Department of Revenue
SCE&G	The legal entity, South Carolina Electric & Gas Company, its consolidated subsidiaries or operating segments, or the entirety of South Carolina Electric & Gas Company and its consolidated subsidiaries
Scott Solar	A 17 MW utility-scale solar power station in Powhatan County, VA
SEC	U.S. Securities and Exchange Commission
SEMI	SCANA Energy Marketing, Inc.
September 2006 hybrids	Dominion Energy’s 2006 Series B Enhanced Junior Subordinated Notes due 2066
SERC	Southeast Electric Reliability Council
Shell	Shell WindEnergy, Inc.
SO2	Sulfur dioxide
Southeast Energy	Southeast Energy Group operating segment
South Carolina Commission	South Carolina Public Service Commission
Spring Grove 1	An approximately 98 MW proposed utility-scale solar power station located in Surry County, Virginia
Standard & Poor’s	Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.
Summer	V.C. Summer nuclear power station
SunEdison	The legal entity, SunEdison, Inc., one or more of its consolidated subsidiaries (including, through November 2016, Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC and Iron Springs Renewables, LLC) or operating segments, or the entirety of SunEdison, Inc. and its consolidated subsidiaries
Surry	Surry nuclear power station
Terra Nova Renewable Partners	A partnership comprised primarily of 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
Transco	Transcontinental Gas Pipe Line Company, LLC
TSR	Total shareholder return
UEX Rider	Uncollectible Expense Rider deployed by East Ohio
Utah Commission	Public Service Commission of Utah
VDEQ	Virginia Department of Environmental Quality
VEBA	Voluntary Employees’ Beneficiary Association
VIE	Variable interest entity
Virginia City Hybrid Energy Center	A 610 MW baseload carbon-capture compatible, clean coal powered electric generation facility in Wise County, Virginia
Virginia Commission	Virginia State Corporation Commission
Virginia Power	The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments, or the entirety of Virginia Electric and Power Company and its consolidated subsidiaries
VOC	Volatile organic compounds
Warren County	A 1,350 MW combined-cycle, natural gas-fired power station in Warren County, Virginia
WECTEC	WECTEC Global Project Services, Inc. (formerly known as Stone & Webster, Inc.), a wholly-owned subsidiary of Westinghouse
West Virginia Commission	Public Service Commission of West Virginia
Western System	Collection of 212 miles of various diameter natural gas pipelines and three compressor stations in Ohio
Westinghouse	Westinghouse Electric Company LLC
Wexpro	The legal entity, Wexpro Company, one or more of its consolidated subsidiaries, or the entirety of Wexpro Company and its consolidated subsidiaries
Wexpro Agreement	An agreement effective August 1981, which sets forth the rights of Questar Gas to receive certain benefits from Wexpro’s operations, including cost-of-service gas
Wexpro II Agreement	An agreement with the states of Utah and Wyoming modeled after the Wexpro Agreement that allows for the addition of properties under the cost-of-service methodology for the benefit of Questar Gas customers
Whitehouse	A 20 MW utility-scale solar power station in Louisa County, VA
White River Hub	White River Hub, LLC
Woodland	A 19 MW utility-scale solar power station in Isle of Wight County, VA
Wyoming Commission	Wyoming Public Service Commission

7

Part I

Item 1. Business

GENERAL

Dominion Energy, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Dominion Energy’s strategy is to be a leading sustainable provider of electricity, natural gas and related services to customers primarily in the eastern and Rocky Mountain regions of the U.S. As of December 31, 2018, Dominion Energy’s portfolio of assets included approximately 26,000 MW of electric generating capacity, 6,700 miles of electric transmission lines, 58,300 miles of electric distribution lines, 14,800 miles of natural gas transmission, gathering and storage pipelines and 52,300 miles of gas distribution pipeline, exclusive of service lines. As of December 31, 2018, Dominion Energy served more than 5 million utility and retail energy customers and operated one of the nation’s largest underground natural gas storage systems, with approximately 1 trillion cubic feet of storage capacity.

In January 2019, Dominion Energy completed the SCANA Combination in a stock-for-stock merger valued at $13.4 billion. SCANA is primarily engaged in the generation, transmission and distribution of electricity in the central, southern and southwestern portions of South Carolina and in the distribution of natural gas in North Carolina and South Carolina. In addition, SCANA markets natural gas to retail customers in the southeast U.S. Following the completion of the SCANA Combination, Dominion Energy’s portfolio of assets includes approximately 32,000 MW of electric generating capacity, 10,200 miles of electric transmission lines, 84,800 miles of electric distribution lines, 15,900 miles of natural gas transmission, gathering and storage pipelines and 92,900 miles of gas distribution pipeline, exclusive of service lines. Dominion Energy operates approximately 1 trillion cubic feet of natural gas storage capacity and serves nearly 7.5 million utility and retail energy customers. SCANA operates as a wholly-owned subsidiary of Dominion Energy. SCANA and one of its wholly-owned subsidiaries, SCE&G, are currently SEC registrants. SCANA and SCE&G file a combined Form 10-K, which is not combined herein.

Dominion Energy continues to focus on expanding and improving its regulated and long-term contracted electric and natural gas businesses while transitioning to a cleaner energy future. The capital investment program for 2019 through 2023 includes a focus on upgrading the electric grid in Virginia through investments in additional renewable generation facilities, strategic undergrounding, energy conservation programs and smart-grid devices. Renewable generation facilities are expected to include investments in utility-scale solar and offshore wind projects. In addition, Dominion Energy is currently seeking, or intends to seek, license extensions for its regulated nuclear power stations in Virginia. Other drivers for the capital investment program include the construction of infrastructure to handle the increase in natural gas production from the Marcellus and Utica Shale formations, including investing in Atlantic Coast Pipeline which is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, to increase natural gas supplies in the region. Dominion Energy also plans to upgrade its gas and electric transmission and distribution networks and meet environmental requirements and standards set by various regulatory bodies.

Dominion Energy has transitioned over the past decade to a more regulated, less volatile earnings mix as evidenced by its capital investments in regulated infrastructure, including the SCANA Combination and Dominion Energy Questar Combination, and in infrastructure whose output is sold under long-term purchase agreements, as well as the sales of certain merchant generating facilities and equity method investments in 2018 and the electric retail energy marketing business in March 2014. Dominion Energy expects approximately 95% of earnings from its primary operating segments to come from regulated and long-term contracted businesses. Dominion Energy’s nonregulated operations include merchant generation, energy marketing and price risk management activities and natural gas retail energy marketing operations. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Energy Gas.

Virginia Power, headquartered in Richmond, Virginia and incorporated in Virginia in 1909 as a Virginia public service corporation, is a wholly-owned subsidiary of Dominion Energy and a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and North Carolina. In Virginia, Virginia Power conducts business under the name “Dominion Energy Virginia” and primarily serves retail customers. In North Carolina, it conducts business under the name “Dominion Energy North Carolina” and serves retail customers located in the northeastern region of the state, excluding certain municipalities. In addition, Virginia Power sells and transmits electricity at wholesale prices to rural electric cooperatives, municipalities and into wholesale electricity markets. All of Virginia Power’s stock is owned by Dominion Energy.

Dominion Energy Gas, a limited liability company formed in September 2013, is a wholly-owned subsidiary of Dominion Energy and a holding company. It serves as the intermediate parent company for certain of Dominion Energy’s regulated natural gas operating subsidiaries, which conduct 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 Energy Gas’ principal wholly-owned subsidiaries are DETI, East Ohio, DGP and Dominion Iroquois. DETI is an interstate natural gas transmission pipeline company serving a broad mix of customers such as local gas distribution companies, marketers, interstate and intrastate pipelines, electric power generators and natural gas producers. The DETI system links to other major pipelines and markets in the mid-Atlantic, Northeast, and Midwest including Dominion Energy’s Cove Point Pipeline. DETI also operates one of the largest underground natural gas storage systems in the U.S. In August 2016, DETI transferred its gathering and processing facilities to DGP. East Ohio is a regulated natural gas distribution operation serving residential, commercial and industrial gas sales and transportation customers. Its service territory includes Cleveland, Akron, Canton, Youngstown and other eastern and western Ohio communities. At December 31, 2018, Dominion Energy Gas holds a 24.07% noncontrolling partnership interest in Iroquois, a FERC-regulated interstate natural gas pipeline in New York and Connecticut. All of Dominion Energy Gas’ membership interests are owned by Dominion Energy.

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

EMPLOYEES

Immediately following the SCANA Combination, Dominion Energy had approximately 21,300 full-time employees, of which approximately 6,200 are subject to collective bargaining agreements, including approximately 6,800 full-time employees at Virginia Power, of which approximately 2,900 are subject to collective bargaining agreements and approximately 3,100 full-time employees at Dominion Energy Gas, of which approximately 2,100 are subject to collective bargaining agreements.

WHERE YOU CAN FIND MORE INFORMATION ABOUT THE COMPANIES

The Companies file their annual, quarterly and current reports, proxy statements and other information with the SEC. Their SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov.

The Companies make their SEC filings available, free of charge, including the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, through Dominion Energy’s website, http://www.dominionenergy.com, as soon as reasonably practicable after filing or furnishing the material to the SEC. Information contained on Dominion Energy’s website, including but not limited to reports mentioned in Environmental Strategy, is not incorporated by reference in this report.

ACQUISITIONS AND DISPOSITIONS

The following are significant acquisitions and divestitures by the Companies during the last five years.

ACQUISITION OF SCANA

In January 2019, Dominion Energy and SCANA completed a stock-for-stock merger valued at $13.4 billion, inclusive of SCANA’s outstanding debt, which totaled $6.9 billion at closing. Following completion of the SCANA Combination, SCANA operates as a wholly-owned subsidiary of Dominion Energy. In connection with the SCANA Combination, SCE&G will provide refunds and restitution of $2.0 billion over 20 years with capital support from Dominion Energy that, along with the benefit of the 2017 Tax Reform Act, is expected to result in an approximate 15% reduction to SCE&G electric service customers’ bills, compared to May 2017, as well as exclude from rate recovery $2.4 billion of costs related to the NND Project and $180 million of costs associated with the purchase of the Columbia Energy Center power station. See Note 3 to the Consolidated Financial Statements for additional information.

PURCHASE OF DOMINION ENERGY MIDSTREAM UNITS

In January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned

by Dominion Energy through the issuance of 22.5 million common shares. See Note 19 to the Consolidated Financial Statements for additional information.

SALE OF CERTAIN MERCHANT GENERATION FACILITIES

In December 2018, Dominion Energy completed the sale of Fairless and Manchester for total consideration of $1.2 billion, subject to customary closing adjustments. See Note 10 to the Consolidated Financial Statements for additional information.

SALE OF INTEREST IN BLUE RACER

In December 2018, Dominion Energy completed the sale of its 50% limited partner interest in Blue Racer for total consideration of $1.2 billion. In addition, the purchaser agreed to pay additional consideration contingent upon the achievement of certain financial performance milestones of Blue Racer from 2019 through 2021. See Note 9 to the Consolidated Financial Statements for additional information.

ACQUISITION OF DOMINION ENERGY QUESTAR

In September 2016, Dominion Energy completed the Dominion Energy Questar Combination for total consideration of $4.4 billion and Dominion Energy Questar became a wholly-owned subsidiary of Dominion Energy. See Note 3 to the Consolidated Financial Statements for additional information.

ACQUISITION OF WHOLLY-OWNED MERCHANT SOLAR PROJECTS

Throughout 2017, Dominion Energy completed the acquisition of various wholly-owned merchant solar projects in California, North Carolina and Virginia for $356 million. The projects cost $541 million to construct, including the initial acquisition cost, and generate 259 MW.

Throughout 2016, Dominion Energy completed the acquisition of various wholly-owned merchant solar projects in North Carolina, South Carolina and Virginia for $32 million. The projects cost $421 million to construct, including the initial acquisition cost, and generate 221 MW.

Throughout 2015, Dominion Energy completed the acquisition of various wholly-owned merchant solar projects in California and Virginia for $381 million. The projects cost $588 million to construct, including the initial acquisition cost, and generate 182 MW.

Throughout 2014, Dominion Energy completed the acquisition of various wholly-owned solar development projects in California for $200 million. The projects cost $578 million to construct, including the initial acquisition cost, and generate 179 MW.

See Note 3 to the Consolidated Financial Statements for additional information.

ACQUISITION OF VIRGINIA POWER SOLAR PROJECTS

In 2018, Virginia Power entered into agreements to acquire two solar development projects in North Carolina and Virginia. The projects are expected to close in 2019 and 2020 with a total expected cost of $250 million once constructed, including the initial acquisition cost, and will generate approximately 155 MW combined.

In 2017, Virginia Power entered into agreements to acquire two solar development projects in North Carolina. The first proj-

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ect closed in 2018 and the second is expected to close in 2019 with a total expected cost of $280 million once constructed, including the initial acquisition cost, and will generate approximately 155 MW combined.

See Note 10 to the Consolidated Financial Statements for additional information.

SALE OF CERTAIN RETAIL ENERGY MARKETING ASSETS

In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy marketing operations for total consideration of $143 million, subject to customary approvals and certain adjustments. In December 2017, the first phase of the agreement closed for $79 million. In October 2018, the second phase of the agreement closed for $63 million. Pursuant to the agreement, Dominion Energy entered into a commission agreement with the buyer upon the first closing in December 2017, under which the buyer will pay a commission in connection with the right to use Dominion Energy’s brand in marketing materials and other services over a ten-year term. See Note 10 to the Consolidated Financial Statements for additional information.

ASSIGNMENT OF TOWER RENTAL PORTFOLIO

Virginia Power rents space on certain of its electric transmission towers to various wireless carriers for communications antennas and other equipment. In March 2017, Virginia Power sold its rental portfolio to Vertical Bridge Towers II, LLC for $91 million in cash. See Note 10 to the Consolidated Financial Statements for additional information.

ACQUISITION OF NON-WHOLLY-OWNED MERCHANT SOLAR PROJECTS

In 2015, Dominion Energy acquired 50% of the units in Four Brothers and Three Cedars from SunEdison for $107 million. In November 2016, NRG acquired the 50% of units in Four Brothers and Three Cedars previously held by SunEdison. In August 2018, NRG’s ownership in Four Brothers and Three Cedars was transferred to GIP. The facilities began commercial operations in the third quarter of 2016, with generating capacity of 530 MW, at a cost of $1.1 billion. See Note 3 to the Consolidated Financial Statements for additional information.

SALE OF INTEREST IN MERCHANT SOLAR PROJECTS

In September 2015, Dominion Energy signed an agreement to sell a noncontrolling interest (consisting of 33% of the equity interests) in all of its then wholly-owned merchant solar projects, 24 solar projects totaling 425 MW, to SunEdison. 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. See Note 3 to the Consolidated Financial Statements for additional information.

DOMINION ENERGY MIDSTREAM ACQUISITION OF INTEREST IN IROQUOIS

In September 2015, Dominion Energy Midstream acquired from NG and NJNR a 25.93% noncontrolling partnership interest in Iroquois. The investment was recorded at $216 million based on

the value of Dominion Energy Midstream’s common units at closing. The common units issued to NG and NJNR are reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements.

ACQUISITION OF DECG

In January 2015, Dominion Energy completed the acquisition of 100% of the equity interests of DECG from SCANA for $497 million in cash, as adjusted for working capital.

ASSIGNMENTS OF SHALE DEVELOPMENT RIGHTS

In December 2013, Dominion Energy Gas closed on agreements with natural gas producers to convey over time approximately 100,000 acres of Marcellus Shale development rights underneath several natural gas storage fields. The agreements provided for payments to Dominion Energy 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 that acreage. In March 2015, Dominion Energy Gas and a natural gas producer closed on an amendment to a December 2013 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 of previously deferred revenue. In April 2016, Dominion Energy 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 of previously deferred revenue. In August 2017, Dominion Energy Gas and a natural gas producer signed an amendment to the agreement, which included the finalization of contractual matters on previous conveyances, the conveyance of Dominion Energy Gas’ remaining 68% interest in approximately 70,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. As a result of this amendment, Dominion Energy Gas received total consideration of $130 million, with $65 million received in November 2017 and $65 million received in September 2018 in connection with the final conveyance.

In March 2015, Dominion Energy 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.

In September 2015, Dominion Energy Gas closed on an agreement with a natural gas producer to convey approximately 16,000 acres of Utica and Point Pleasant Shale development rights underneath one of its natural gas storage fields. The agreement provided for a payment to Dominion Energy Gas, subject to customary adjustments, of $52 million and an overriding royalty interest in gas produced from the acreage.

In November 2014, Dominion Energy 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. The agreement provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $120 million over a period of four years, and an overriding royalty interest in gas

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produced from the acreage. In January 2018, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the conveyance of Dominion Energy Gas’ remaining 50% interest in approximately 18,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage for proceeds of $28 million.

See Note 10 to the Consolidated Financial Statements for additional information on certain of these sales of Marcellus acreage.

SALE OF ELECTRIC RETAIL ENERGY MARKETING BUSINESS

In March 2014, Dominion Energy completed the sale of its electric retail energy marketing business. The proceeds were $187 million, net of transaction costs.

SALE OF PIPELINES AND PIPELINE SYSTEMS

In March 2014, Dominion Energy Gas sold the Northern System to an affiliate that subsequently sold the Northern System to Blue Racer for consideration of $84 million. Dominion Energy Gas’ consideration consisted of $17 million in cash proceeds and the extinguishment of affiliated current borrowings of $67 million and Dominion Energy’s consideration consisted of cash proceeds of $84 million.

OPERATING SEGMENTS

Effective January 2019, Dominion Energy manages its daily operations through four primary operating segments: Power Delivery, Power Generation, Gas Infrastructure and Southeast Energy. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt). In addition, Corporate and Other includes specific items attributable to Dominion Energy’s other operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.

Virginia Power manages its daily operations through two primary operating segments: Power Delivery and Power Generation. It also reports a Corporate and Other segment that 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.

Dominion Energy Gas manages its daily operations through its primary operating segment: Gas Infrastructure. It also reports a Corporate and Other segment that primarily includes specific items attributable to its 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 Energy Gas as a result of Dominion Energy’s basis in the net assets contributed.

While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by the Companies and their respective legal subsidiaries.

A description of the operations included in the Companies’ primary operating segments is as follows:

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

(1) Includes remaining producer services activities.

(2) Consists of the operations of SCANA.

Power Delivery

The Power Delivery Operating Segment of Dominion Energy and Virginia Power includes Virginia Power’s regulated electric transmission and distribution (including customer service) operations, which serve approximately 2.6 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.

Power Delivery’s investment plan includes spending approximately $10.0 billion from 2019 through 2023 to upgrade or add new transmission, including RTEP projects, and distribution lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability and regulatory compliance. The proposed electric delivery infrastructure projects are intended to address both continued customer growth and increases in electricity consumption which are partially driven by new and larger data center customers. Additionally, Power Delivery has created a ten-year plan to transform its electric grid into a smarter, stronger and greener grid. This plan will address the structural limitations of Virginia Power’s distribution grid in a systematic manner in order to recognize and accommodate fundamental changes and requirements in the energy industry. The objective is to address both customer and system needs by (i) achieving even higher levels of reliability and resiliency against natural and man-made threats, (ii) leveraging technology to enhance the customer experience and improve the

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operation of the system and (iii) safely and effectively integrating new utility-scale renewable generation and storage as well as customer–level distributed energy resources such as rooftop solar and battery storage.

Revenue provided by electric distribution operations is based primarily on rates established by state regulatory authorities and state law. Approximately 85% of revenue comes from serving Virginia jurisdictional customers. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures. Operationally, electric distribution continues to focus on improving service levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 134 minutes for the three- year average ending 2018, up from the previous three-year average of 125 minutes primarily due to increased storm activity during the year. In the future, safety, electric service reliability, outage durations and customer service will remain key focus areas for electric distribution.

Revenue provided by Virginia Power’s electric transmission operations is based primarily on rates approved by FERC. The profitability of this business is dependent on its ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings primarily results from changes in rates and the timing of property additions, retirements and depreciation.

Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into PJM wholesale electricity markets. Consistent with the increased authority given to NERC by EPACT, Virginia Power’s electric transmission operations are committed to meeting NERC standards, modernizing its infrastructure and maintaining superior system reliability. Virginia Power’s electric transmission operations will continue to focus on safety, operational performance, NERC compliance and execution of PJM’s RTEP.

COMPETITION

There is no competition for electric distribution service within Virginia Power’s service territory in Virginia and North Carolina and no such competition is currently permitted. Historically, since its electric transmission facilities are integrated into PJM and electric transmission services are administered by PJM, there was no competition in relation to transmission service provided to customers within the PJM region. However, competition from non-incumbent PJM transmission owners for development, construction and ownership of certain transmission facilities in Virginia Power’s service territory is permitted pursuant to Order 1000, subject to state and local siting and permitting approvals. This could result in additional competition to build and own transmission infrastructure in Virginia Power’s service area in the future and could allow Dominion Energy to seek opportunities to build and own facilities in other service territories.

REGULATION

Virginia Power’s electric distribution service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia and North Carolina Commissions. Virginia Power’s wholesale electric transmission rates, tariffs and terms of service

are subject to regulation by FERC. Electric transmission siting authority remains the jurisdiction of the Virginia and North Carolina Commissions. However, EPACT provides FERC with certain backstop authority for transmission siting. See State Regulations and Federal Regulations in Regulation and Note 13 to the Consolidated Financial Statements for additional information.

PROPERTIES

For a description of Dominion Energy and Virginia Power’s existing transmission facilities see Item 2. Properties.

As a part of PJM’s RTEP process, PJM authorized the following material reliability projects (including Virginia Power’s estimated cost):

• Surry-to-Skiffes Creek-to-Whealton ($435 million);

• Idylwood substation ($110 million);

• Dooms-to-Lexington ($130 million);

• Warrenton (including Remington CT-to-Warrenton, Vint Hill-to-Wheeler-to-Gainesville, and Vint Hill and Wheeler switching stations) ($120 million);

• Remington/Gordonsville/Pratts Area Improvement (including Remington-to-Gordonsville, and new Gordonsville substation transformer) ($115 million);

• Gainesville-to-Haymarket ($180 million);

• Cunningham-to-Dooms ($65 million);

• Carson-to-Rogers Road ($55 million);

• Dooms-to-Valley ($65 million);

• Mt. Storm-to-Valley ($285 million);

• Glebe substation and North Potomac Yard terminal station underground ($125 million); and

• Idylwood-to-Tysons ($125 million).

In addition, in December 2017, the Virginia Commission granted Virginia Power a CPCN to rebuild and operate in Lancaster County, Virginia and Middlesex County, Virginia, approximately 2 miles of existing 115 kV transmission lines to be constructed under the Rappahannock River between Harmony Village Substation and White Stone Substation. The total estimated cost of the project is approximately $105 million.

Virginia Power is investing in transmission substation physical security and expects to invest an additional $150 million to $200 million through 2023 to strengthen its electrical system to better protect critical equipment, enhance its spare equipment process and create multiple levels of security.

For a description of Dominion Energy and Virginia Power’s existing distribution facilities see Item 2. Properties.

Virginia legislation provides for the recovery of costs, subject to approval by the Virginia Commission, for Virginia Power to move approximately 4,000 miles of electric distribution lines underground. The program is designed to reduce restoration outage time by moving Virginia Power’s most outage-prone overhead distribution lines underground, has an annual investment cap of approximately $175 million and is expected to be completed by 2028. The Virginia Commission has approved three phases of the program encompassing approximately 1,100 miles of converted lines and $422 million in capital spending (with $404 million recoverable through Rider U).

See Note 13 to the Consolidated Financial Statements for more information.

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SOURCES OF ENERGY SUPPLY

Power Delivery’s supply of electricity to serve Virginia Power customers is produced or procured by Power Generation. See Power Generation for additional information.

SEASONALITY

Power Delivery’s earnings vary seasonally as a result of the impact of changes in temperature, the impact of storms and other catastrophic weather events, and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs, respectively. An increase in heating degree days for Power Delivery’s electric utility-related operations does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials and because alternative heating sources are more readily available.

Power Generation

The Power Generation Operating Segment of Virginia Power includes the generation operations of the Virginia Power regulated electric utility and its related energy supply operations. Virginia Power’s utility generation operations primarily serve the supply requirements for Power Delivery’s utility customers. Virginia Power’s non-jurisdictional operations serve certain large-scale customers.

The Power Generation Operating Segment of Dominion Energy includes Virginia Power’s generation facilities and its related energy supply operations as well as the generation operations of Dominion Energy’s merchant fleet and energy marketing and price risk management activities for these assets.

Power Generation’s investment plan includes spending approximately $10.3 billion from 2019 through 2023 to maintain existing and construct new generation capacity to meet growing electricity demand within its service territory and maintain reliability. The most significant investments are expanding the renewable generation asset portfolio and the subsequent license renewal projects seeking 20-year license extensions for the regulated nuclear power stations in Virginia. See Properties and Environmental Strategy for additional information on this and other utility projects.

In addition, Dominion Energy’s merchant generation fleet includes numerous renewable generation facilities, including solar generation and wind facilities in operation or development in ten states, including Virginia. The output of these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. See Notes 3 and 10 to the Consolidated Financial Statements for additional information regarding certain solar projects.

Earnings for the Power Generation Operating Segment of Virginia Power primarily result from the sale of electricity generated by its utility fleet. Revenue is based primarily on rates established by state regulatory authorities and state law. Approximately 76% of revenue comes from serving Virginia jurisdictional customers. Base rates for the Virginia jurisdiction are set using a modified cost-of-service rate model, and are generally designed to allow an opportunity to recover the cost of providing utility service and earn a reasonable return on investments used to provide that service. Earnings variability may arise when revenues are impacted by

factors not reflected in current rates, such as the impact of weather on customers’ demand for services. Likewise, earnings may reflect variations in the timing or nature of expenses as compared to those contemplated in current rates, such as labor and benefit costs, capacity expenses, and the timing, duration and costs of scheduled and unscheduled outages. The cost of fuel and purchased power is generally collected through fuel cost-recovery mechanisms established by regulators and does not materially impact net income. The cost of new generation facilities is generally recovered through rate adjustment clauses in Virginia. Variability in earnings from rate adjustment clauses reflects changes in the authorized ROE and the carrying amount of these facilities, which are largely driven by the timing and amount of capital investments, as well as depreciation. See Note 13 to the Consolidated Financial Statements for additional information.

The Power Generation Operating Segment of Dominion Energy derives its earnings primarily from the sale of electricity generated by Virginia Power’s utility and Dominion Energy’s merchant generation assets, as well as from associated capacity and ancillary services. Variability in earnings provided by Dominion Energy’s nonrenewable merchant assets relates to changes in market-based prices received for electricity and capacity. Market-based prices for electricity are largely dependent on commodity prices and the demand for electricity. Capacity prices are dependent upon resource requirements in relation to the supply available (both existing and new) in the forward capacity auctions, which are held approximately three years in advance of the associated delivery year. Dominion Energy manages the electric price volatility of its merchant generation fleet by hedging a substantial portion of its expected near-term energy sales with derivative instruments. Variability also results from changes in weather, the cost of fuel consumed, labor and benefits and the timing, duration and costs of scheduled and unscheduled outages.

COMPETITION

Power Generation Operating Segment—Dominion Energy and Virginia Power

Virginia Power’s generation operations are not subject to significant competition as only a limited number of its Virginia jurisdictional electric utility customers have retail choice. See Electric under State Regulations in Regulation for more information. Currently, North Carolina does not offer retail choice to electric customers.

Virginia Power’s non-jurisdictional operations are not currently subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 16 to 25 years. However, in the future, such operations may compete with other power generation facilities to serve certain large-scale customers after the power purchase agreements expire.

Power Generation Operating Segment—Dominion Energy

Power Generation’s renewable generation projects are not currently subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. Competition for the merchant fleet is impacted by electricity and fuel prices, new market entrants, construction by others of generating assets and transmission capacity, technological

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advances in power generation, the actions of environmental and other regulatory authorities and other factors. These competitive factors may negatively impact the merchant fleet’s ability to profit from the sale of electricity and related products and services.

Unlike Power Generation’s regulated generation fleet, its merchant generation fleet is dependent on its ability to operate in a competitive environment and does not have a predetermined rate structure that provides for a rate of return on its capital investments. Power Generation’s nonrenewable merchant assets operate within functioning RTOs and primarily compete on the basis of price. Competitors include other generating assets bidding to operate within the RTOs. Power Generation’s nonrenewable merchant units compete in the wholesale market with other generators to sell a variety of products including energy, capacity and ancillary services. It is difficult to compare various types of generation given the wide range of fuels, fuel procurement strategies, efficiencies and operating characteristics of the fleet within any given RTO. However, Dominion Energy applies its expertise in operations, dispatch and risk management to maximize the degree to which its nonrenewable merchant fleet is competitive compared to similar assets within the region.

In November 2017, Connecticut adopted the Act Concerning Zero Carbon Solicitation and Procurement, which allows nuclear generating facilities to compete for power purchase agreements in a state sponsored procurement for electricity. In February 2018, Connecticut regulators recommended pursuing the procurement and, in May 2018, issued a request for proposals. Millstone participated in the state sponsored procurement for electricity. In December 2018, Connecticut’s Public Utility Regulatory Authority confirmed that Millstone should be considered an “existing resource confirmed at risk” in the state’s Department of Energy and Environmental Protection zero carbon procurement. Being considered “at risk” allows the Department of Energy and Environmental Protection to consider factors other than price, such as environmental and economic benefits, when evaluating Dominion Energy’s bids. Also in December 2018, Millstone was awarded the right to negotiate a ten-year agreement for nine million MWh per year. Dominion Energy continues to engage with applicable parties in Connecticut to ensure pricing that recognizes Millstone’s environmental and economic benefits.

REGULATION

Virginia Power and Dominion Energy’s generation fleet are subject to regulation by FERC, the NRC, the EPA, the DOE, the Army Corps of Engineers and other federal, state and local authorities. Virginia Power’s utility generation fleet is also subject to regulation by the Virginia and North Carolina Commissions. See Regulation, Future Issues and Other Matters in Item 7. MD&A and Notes 13 and 22 to the Consolidated Financial Statements for more information.

PROPERTIES

For a listing of Dominion Energy and Virginia Power’s existing generation facilities, see Item 2. Properties.

Virginia Power is developing, financing and constructing new generation capacity to meet growing electricity demand within its service territory. Significant projects under construction or development are set forth below:

• Virginia Power plans to acquire or construct certain solar facilities in Virginia and North Carolina. See Notes 10 and 13 to the Consolidated Financial Statements for more information.

• Virginia Power continues to consider the construction of a third nuclear unit at a site located at North Anna. See Future Issues and Other Matters in Item 7 for more information on this project.

• Virginia Power is considering the construction of an up to $2 billion hydroelectric pumped storage facility in Southwest Virginia.

• In November 2018, Virginia Power received approval from the Virginia Commission to develop two 6 MW wind turbines off the coast of Virginia for the Coastal Virginia Offshore Wind project. The project is expected to cost approximately $300 million and to be in service in late 2020.

SOURCES OF ENERGY SUPPLY

Power Generation Operating Segment—Dominion Energy and Virginia Power

Power Generation uses a variety of fuels to power its electric generation and purchases power for utility system load requirements and to satisfy physical forward sale requirements, as described below. Some of these agreements have fixed commitments and are included as contractual obligations in Future Cash Payments for Contractual Obligations and Planned Capital Expenditures in Item 7. MD&A.

Nuclear Fuel—Power Generation primarily utilizes long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent on the market environment. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal cost and inventory levels.

Fossil Fuel—Power Generation primarily utilizes natural gas and coal in its fossil fuel plants. All recent fossil fuel plant construction for Power Generation involves natural gas generation.

Power Generation’s natural gas and oil supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, purchases from local producers in the Appalachian area and Marcellus and Utica regions, purchases from gas marketers and withdrawals from underground storage fields owned by Dominion Energy or third parties. Power Generation manages a portfolio of natural gas transportation contracts (capacity) that provides for reliable natural gas deliveries to its gas turbine fleet, while minimizing costs.

Power Generation’s coal supply is obtained through long-term contracts and short-term spot agreements from domestic suppliers.

Biomass—Power Generation’s biomass supply is obtained through long-term contracts and short-term spot agreements from local suppliers.

Purchased Power—Power Generation purchases electricity from the PJM spot market and through power purchase agree-

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ments with other suppliers to provide for utility system load requirements.

Power Generation also occasionally purchases electricity from the ISO-NE spot market to satisfy physical forward sale requirements as part of its merchant generation operations.

Power Generation Operating Segment—Virginia Power

Presented below is a summary of Virginia Power’s actual system output by energy source:

Source	2018			2017			2016
Natural gas		33	%		32	%		31	%
Nuclear(1)		29			32			31
Purchased power, net		19			14			8
Coal(2)		13			17			24
Other(3)		6			5			6
Total		100	%		100	%		100	%

(1) Excludes ODEC’s 11.6% ownership interest in North Anna.

(2) Excludes ODEC’s 50.0% ownership interest in the Clover power station.

(3) Includes oil, hydro, biomass and solar.

SEASONALITY

Power Generation Operating Segment—Dominion Energy and Virginia Power

Sales of electricity for Power Generation typically vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. See Power Delivery-Seasonality above for additional considerations that also apply to Power Generation.

NUCLEAR DECOMMISSIONING

Power Generation Operating Segment—Dominion Energy and Virginia Power

Virginia Power has a total of four licensed, operating nuclear reactors at Surry and North Anna in Virginia.

Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers are placed into trusts and are invested to fund the expected future costs of decommissioning the Surry and North Anna units.

Virginia Power believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects the long-term investment horizon, since the units will not be decommissioned for decades, and a positive long-term outlook for trust fund investment returns. Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial

assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC.

The estimated cost to decommission Virginia Power’s four nuclear units is reflected in the table below and is primarily based upon site-specific studies completed in 2014. These cost studies are generally completed every four to five years. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire.

Under the current operating licenses, Virginia Power is scheduled to decommission the Surry and North Anna units during the period 2032 to 2078. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. Virginia Power has filed an application with the NRC to renew operating licenses for Surry for an additional 20 years. Under its current licenses, the two nuclear units are allowed to generate electricity through 2032 and 2033. A relicensing would extend their lives through 2052 and 2053. Virginia Power expects to submit a license extension application for the two units at North Anna in 2020. Between the four units, Virginia Power estimates that it could spend approximately $3 billion to $4 billion over the next several years on the relicensing process. The existing regulatory framework in Virginia provides rate recovery mechanisms for such costs.

Power Generation Operating Segment—Dominion Energy

In addition to the four nuclear units discussed above, Dominion Energy has two licensed, operating nuclear reactors at Millstone in Connecticut. A third Millstone unit ceased operations before Dominion Energy acquired the power station. In May 2013, Dominion Energy ceased operations at its single Kewaunee unit in Wisconsin and commenced decommissioning activities using the SAFSTOR methodology. The planned decommissioning completion date is 2073, which is within the NRC allowed 60-year window.

As part of Dominion Energy’s acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Any funds remaining in Kewaunee’s trust after decommissioning is completed are required to be refunded to Wisconsin ratepayers. Dominion Energy believes that the amounts currently available in the decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Dominion Energy will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. The estimated cost to decommission Dominion Energy’s eight units is reflected in the table below and is primarily based upon site-specific studies completed for Surry, North Anna and Millstone in 2014 and for Kewaunee in 2018.

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The estimated decommissioning costs and license expiration dates for the nuclear units owned by Dominion Energy and Virginia Power are shown in the following table:

	NRC license expiration year		Most recent cost estimate (2018 dollars)(1)		Funds in trusts at December 31, 2018		2018 contributions to trusts
(dollars in millions)
Surry
Unit 1		2032	$	624		$   669		$  —
Unit 2		2033		646		660		—
North Anna
Unit 1(2)		2038		534		536		—
Unit 2(2)		2040		547		504		—
Total (Virginia Power)				2,351		2,369		—
Millstone
Unit 1(3)		N/A		381		509		—
Unit 2		2035		587		672		—
Unit 3(4)		2045		713		664		—
Kewaunee
Unit 1(5)		N/A		574		724		—
Total (Dominion Energy)			$	4,606		$4,938		$  —

(1) The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on Dominion Energy and Virginia Power’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Dominion Energy and Virginia Power’s nuclear decommissioning AROs.

(2) North Anna is jointly owned by Virginia Power (88.4%) and ODEC (11.6%). However, Virginia Power is responsible for 89.26% of the decommissioning obligation. Amounts reflect 89.26% of the decommissioning cost for both of North Anna’s units.

(3) Unit 1 permanently ceased operations in 1998, before Dominion Energy’s acquisition of Millstone.

(4) Millstone Unit 3 is jointly owned by Dominion Energy Nuclear Connecticut, Inc., with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain. Decommissioning cost is shown at Dominion Energy’s ownership percentage. At December 31, 2018, the minority owners held $41 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.

(5) Permanently ceased operations in 2013.

Also see Notes 14 and 22 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively, and Note 9 to the Consolidated Financial Statements for information about nuclear decommissioning trust investments.

Gas Infrastructure

The Gas Infrastructure Operating Segment of Dominion Energy Gas includes certain of Dominion Energy’s regulated natural gas operations. DETI, the gas transmission pipeline and storage business, serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. East Ohio, the primary gas distribution business of Dominion Energy Gas, serves residential, commercial and industrial gas sales, transportation and gathering service customers primarily in Ohio. DGP conducts gas gathering and processing activities, which include the sale of extracted products at market rates, primarily in West Virginia, Ohio and Pennsylvania. Dominion Iroquois holds a 24.07% noncontrolling partnership interest in Iroquois, which provides service to local gas distribution companies, electric utilities and electric power

generators, as well as marketers and other end users, through interconnecting pipelines and exchanges primarily in New York.

The Gas Infrastructure Operating Segment of Dominion Energy includes Dominion Energy Gas’ regulated natural gas operations as well as LNG operations, Dominion Energy Questar operations, Hope’s gas distribution operations in West Virginia, DECG’s FERC-regulated interstate natural gas transportation services in South Carolina and southeastern Georgia and nonregulated retail natural gas marketing, as well as Dominion Energy’s investments in Atlantic Coast Pipeline and Iroquois. See Properties and Investments below for additional information regarding the Atlantic Coast Pipeline investment. Dominion Energy’s LNG operations involve the import, export and storage of LNG at Cove Point, transportation of regasified LNG to the interstate pipeline grid and mid-Atlantic and Northeast markets and liquefaction of natural gas for export as LNG.

In September 2016, Dominion Energy completed the Dominion Energy Questar Combination and Dominion Energy Questar, a Rockies-based integrated natural gas company consisting of Questar Gas, Wexpro and Dominion Energy Questar Pipeline, became a wholly-owned subsidiary of Dominion Energy. Questar Gas’ regulated gas distribution operations serves customers in Utah, southwestern Wyoming and southeastern Idaho. Wexpro develops and produces natural gas from reserves supplied to Questar Gas under a cost-of-service framework. Dominion Energy Questar Pipeline provides FERC-regulated interstate natural gas transportation and storage services in Utah, Wyoming and western Colorado. See Acquisitions and Dispositions above and Note 3 to the Consolidated Financial Statements for a description of the Dominion Energy Questar Combination.

Gas Infrastructure’s investment plan includes spending approximately $8.5 billion from 2019 through 2023 to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability. Demand for natural gas is expected to continue to grow as initiatives to transition to gas from more carbon-intensive fuels are implemented. This plan includes Dominion Energy’s portion of spending for the Atlantic Coast Pipeline Project.

Earnings for the Gas Infrastructure Operating Segment of Dominion Energy Gas primarily result from rates established by FERC and the Ohio Commission. The profitability of this business is dependent on Dominion Energy Gas’ ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, which are dependent on weather, changes in commodity prices and the economy.

Approximately 92% of DETI’s transmission capacity is subscribed including 86% under long-term contracts (two years or greater) and 6% on a year-to-year basis. DETI’s storage services are 100% subscribed with long-term contracts.

Revenue from processing and fractionation operations largely results from the sale of commodities at market prices. For DGP’s processing plants, Dominion Energy Gas receives the wet gas product from producers and may retain the extracted NGLs as compensation for its services. This exposes Dominion Energy Gas to commodity price risk for the value of the spread between the NGL products and natural gas. In addition, Dominion Energy

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Gas has volumetric risk as the majority of customers receiving these services are not required to deliver minimum quantities of gas.

East Ohio utilizes a straight-fixed-variable rate design for a majority of its customers. Under this rate design, East Ohio recovers a large portion of its fixed operating costs through a flat monthly charge accompanied by a reduced volumetric base delivery rate. Accordingly, East Ohio’s revenue is less impacted by weather-related fluctuations in natural gas consumption than under the traditional rate design.

Earnings for the Gas Infrastructure Operating Segment of Dominion Energy primarily include the results of rates established by FERC and the Ohio, West Virginia, Utah, Wyoming and Idaho Commissions. Additionally, Dominion Energy receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain LNG storage and terminalling services. The Liquefaction Project has a firm contracted capacity for LNG loading onto ships of approximately 4.6 Mtpa (0.66 Bcfe/day), under normal operating conditions and after accounting for maintenance downtime and other losses. Dominion Energy Questar Pipeline and DECG’s revenues are primarily derived from reservation charges for firm transportation and storage services as provided for in their FERC-approved tariffs. Revenue provided by Questar Gas’ operations is based primarily on rates established by the Utah and Wyoming Commissions. The Idaho Commission has contracted with the Utah Commission for rate oversight of Questar Gas operations in a small area of southeastern Idaho. Hope’s gas distribution operations in West Virginia serve residential, commercial, sale for resale and industrial gas sales, transportation and gathering service customers. Revenue provided by Hope’s operations is based primarily on rates established by the West Virginia Commission. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their capital investments. Variability in earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, which are dependent on weather, changes in commodity prices and the economy.

COMPETITION

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

Dominion Energy Gas’ natural gas transmission operations compete with domestic and Canadian pipeline companies. Dominion Energy Gas also competes with gas marketers seeking to provide or arrange transportation, storage and other services. Alternative fuel sources, such as oil or coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain long-line pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enable Dominion Energy to tailor its services to meet the needs of individual customers.

DGP’s processing and fractionation operations face competition in obtaining natural gas supplies for its processing and related

services. Numerous factors impact any given customer’s choice of processing services provider, including the location of the facilities, efficiency and reliability of operations, and the pricing arrangements offered.

In Ohio, there has been no legislation enacted to require supplier choice for natural gas distribution consumers. However, East Ohio has offered an Energy Choice program to residential and commercial customers since October 2000. East Ohio has since taken various steps approved by the Ohio Commission toward exiting the merchant function, including restructuring its commodity service and placing Energy Choice-eligible customers in a direct retail relationship with participating suppliers. Further, in April 2013, East Ohio fully exited the merchant function for its nonresidential customers, which are now required to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2018, approximately 1.1 million of East Ohio’s 1.2 million Ohio customers were participating in the Energy Choice program.

Gas Infrastructure Operating Segment—Dominion Energy

Questar Gas and Hope do not currently face direct competition from other distributors of natural gas for residential and commercial customers in their service territories as state regulations in Utah, Wyoming and Idaho for Questar Gas, and West Virginia for Hope, do not allow customers to choose their provider at this time. See State Regulations in Regulation for additional information.

Cove Point’s gas transportation, LNG import and storage operations, as well as the Liquefaction Project’s capacity are contracted primarily under long-term fixed reservation fee agreements. However, in the future Cove Point may compete with other independent terminal operators as well as major oil and gas companies on the basis of terminal location, services provided and price. Competition from terminal operators primarily comes from refiners and distribution companies with marketing and trading arms. In addition, Cove Point’s Liquefaction Project may face competition on a global scale as international customers explore other options to meet their energy needs.

Dominion Energy Questar Pipeline and DECG’s pipeline systems generate a substantial portion of their revenue from long-term firm contracts for transportation services and are therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, Dominion Energy Questar Pipeline’s pipeline system faces competitive pressures from similar facilities that serve the Rocky Mountain region and DECG’s pipeline system faces competitive pressures from similar facilities that serve the South Carolina and southeastern Georgia area in terms of location, rates, terms of service, and flexibility and reliability of service.

Dominion Energy’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy markets for natural gas, and provides service to approximately 380,000 customer accounts in five states. The heaviest concentration of customers in these markets is located in states where utilities have the advantage of long-standing commitment to customer choice, primarily Ohio and Pennsylvania.

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REGULATION

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

Dominion Energy Gas’ natural gas transmission and storage operations are regulated primarily by FERC. East Ohio’s gas distribution operations, including the rates that it may charge to customers, are regulated by the Ohio Commission. See State Regulations and Federal Regulations in Regulation for more information.

Gas Infrastructure Operating Segment—Dominion Energy

Cove Point’s transportation, LNG import and storage operations and Dominion Energy Questar Pipeline and DECG’s operations are regulated primarily by FERC. Questar Gas’ distribution operations, including the rates it may charge customers, are regulated by the Utah, Wyoming and Idaho Commissions. Hope’s gas distribution operations, including the rates that it may charge customers, are regulated by the West Virginia Commission. See State Regulations and Federal Regulations in Regulation for more information.

PROPERTIES

For a description of Dominion Energy and Dominion Energy Gas’ existing facilities see Item 2. Properties.

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

Dominion Energy Gas has the following significant projects under construction or development to better serve customers or expand its service offerings within its service territory.

In August 2018, DETI executed a binding precedent agreement with a customer for the West Loop project. The project is expected to cost approximately $95 million and provide 150,000 Dths per day of firm transportation service from Pennsylvania to Ohio for delivery to a proposed combined-cycle, natural gas-fired electric power generation facility to be located in Columbiana County, Ohio. In December 2018, DETI filed an application to request FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service by the end of 2021.

In January 2018, DETI filed an application to request FERC authorization to construct and operate certain facilities located in Ohio and Pennsylvania for the Sweden Valley project. The project is expected to cost approximately $50 million and provide 120,000 Dths per day of firm transportation service from Pennsylvania to Ohio for delivery to Transco. The project’s capacity is fully subscribed pursuant to a precedent agreement with one customer and is expected to be placed into service in the fourth quarter of 2019.

In December 2014, DETI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header project, a project to provide approximately 1,500,000 Dths per day of firm transportation service to various customers. During the third and fourth quarters of 2018, a FERC stop work order together with delays in obtaining permits necessary for construction and delays in construction due to judicial actions impacted the cost and schedule for the project. As a result, project cost estimates have increased from between $550 million to $600 million to between

$650 million to $700 million, excluding financing costs. DETI anticipates a late 2020 in-service date.

In 2008, East Ohio began PIR, aimed at replacing approximately 4,100 miles of its pipeline system at a cost of $2.7 billion. In 2011, approval was obtained to include an additional 1,450 miles and to increase annual capital investment to meet the program goal. The program will replace approximately 25% of the pipeline system and is anticipated to take place over a total of 25 years. In September 2016, East Ohio received approval to extend the PIR program for an additional five years and to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio. Costs associated with calendar year 2016 investment will be recovered under the existing terms. In April 2018, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2017 costs. The filing reflects gross plant investment for 2017 of $204 million, cumulative gross plant investment of $1.4 billion and a revenue requirement of $165 million.

Gas Infrastructure Operating Segment—Dominion Energy

Dominion Energy has the following significant projects under construction or development.

Cove Point—In June 2015, Cove Point executed binding agreements with two customers for the approximately $150 million Eastern Market Access Project. In January 2018, Cove Point received FERC authorization to construct and operate the project facilities, which are expected to be placed into service in the second half of 2019. In October 2018, Cove Point announced it was evaluating alternatives to a proposed Charles County, Maryland compressor station that was initially part of this project and in December 2018, after working with project customers for alternative solutions, decided not to pursue further construction at this location resulting in a revised project cost estimate of approximately $45 million.

Questar Gas—In 2010, Questar Gas began replacing aging high pressure infrastructure under a cost-tracking mechanism that allows it to place into rate base and earn a return on capital expenditures associated with a multi-year natural gas infrastructure-replacement program upon the completion of each project. At that time, the commission-allowed annual spending in the replacement program was approximately $55 million.

In its 2014 Utah general rate case, Questar Gas received approval to include intermediate high pressure infrastructure in the replacement program and increase the annual spending limit to approximately $65 million, adjusted annually using a gross domestic product inflation factor. At that time, 420 miles of high pressure pipe and 70 miles of intermediate high pressure pipe were identified to be replaced in the program over a 17-year period. Questar Gas has spent about $65 million each year through 2018 under this program. The program is evaluated in each Utah general rate case. The next Utah general rate case is anticipated to occur in 2019.

INVESTMENTS

Iroquois—In September 2015, Dominion Energy, through Dominion Energy Midstream, acquired an additional 25.93% interest in Iroquois. Dominion Energy Gas holds a 24.07% interest with TransCanada holding a 50% interest. Iroquois owns and

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operates a 416-mile FERC regulated interstate natural gas pipeline providing service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end-users, through interconnecting pipelines and exchanges. Iroquois’ pipeline extends from the U.S.-Canadian border at Waddington, New York through the state of Connecticut to South Commack, Long Island, New York and continuing on from Northport, Long Island, New York through the Long Island Sound to Hunts Point, Bronx, New York. See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Iroquois.

Atlantic Coast Pipeline—In September 2014, Dominion Energy, along with Duke and Southern Company Gas, announced the formation of Atlantic Coast Pipeline. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion Energy an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. The members hold the following membership interests: Dominion Energy, 48%; Duke, 47%; and Southern Company Gas, 5%. Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. See Future Issues and Other Matters in Item 7 for information on estimated project costs and in-service date and Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Atlantic Coast Pipeline.

Align RNG—In November 2018, Dominion Energy announced the formation of Align RNG, an equal partnership with Smithfield Foods, Inc. Align RNG expects to invest $250 million to develop assets to capture methane from hog farms across Virginia, North Carolina and Utah and convert it into pipeline quality natural gas.

SOURCES OF ENERGY SUPPLY

Dominion Energy and Dominion Energy Gas’ natural gas supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area, gas marketers and, for Questar Gas specifically, from Wexpro and other producers in the Rocky Mountain region. Wexpro’s gas development and production operations serve the majority of Questar Gas’ gas supply requirements in accordance with the Wexpro Agreement and the Wexpro II Agreement, comprehensive agreements with the states of Utah and Wyoming. Dominion Energy and Dominion Energy Gas’ large underground natural gas storage network and the location of their pipeline systems are a significant link between the country’s major interstate gas pipelines and large markets in the Northeast, mid-Atlantic and Rocky Mountain regions. Dominion Energy and Dominion Energy Gas’ pipelines are part of an interconnected gas transmission system, which provides access to supplies nationwide for local distribution companies, marketers, power generators and industrial and commercial customers.

Dominion Energy and Dominion Energy Gas’ underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Northeast, mid-Atlantic, Midwest and Rocky Mountain regions. In addition,

storage capacity is an important element in the effective management of both gas supply and pipeline transmission capacity.

The supply of gas to serve Dominion Energy’s retail energy marketing customers is procured through Dominion Energy’s energy marketing group and market wholesalers.

SEASONALITY

Gas Infrastructure’s natural gas distribution business earnings vary seasonally, as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Historically, the majority of these earnings have been generated during the heating season, which is generally from November to March; however, implementation of rate mechanisms in Ohio for East Ohio, and Utah, Wyoming and Idaho for Questar Gas and transportation services provided to gas producers and electric power generators at East Ohio have reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion Energy’s gas transmission and storage business can also be weather sensitive. Earnings are also impacted by changes in commodity prices driven by seasonal weather changes, the effects of unusual weather events on operations and the economy.

The earnings of Dominion Energy’s retail energy marketing operations also vary seasonally. Generally, the demand for gas peaks during the winter months to meet heating needs.

Southeast Energy

The Southeast Energy Operating Segment of Dominion Energy, established in January 2019, includes the generation, transmission and distribution of electricity through SCE&G, the distribution of natural gas through SCE&G and PSNC and the marketing of natural gas to retail customers through SEMI.

SCE&G is engaged in the generation, transmission and distribution of electricity to approximately 730,000 customers in the central, southern and southwestern portions of South Carolina. Additionally, SCE&G and PSNC sell natural gas to approximately 960,000 residential, commercial and industrial customers in South Carolina and North Carolina. SEMI markets natural gas and provides energy-related services, selling natural gas to approximately 420,000 customers in the southeast U.S.

Southeast Energy’s investment plan includes spending approximately $4.6 billion from 2019 through 2023 to upgrade or add new equipment and infrastructure in response to increasing customer growth and demand and an effort to maintain reliability for customers.

Revenue provided by SCE&G’s electric distribution operations is based primarily on rates established by state regulatory authorities and state law. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures.

SCE&G’s electric transmission operations serve its electric distribution operations as well as certain wholesale customers. Revenue provided by such electric transmission operations is primarily based on a FERC-approved formula rate mechanism under SCE&G’s open access transmission tariff.

Revenue provided by SCE&G’s electric generation operations is primarily derived from the sale of electricity generated by its utility generation assets and is based on rates established by state regulatory authorities and state law. Variability in earnings may arise when revenues are impacted by factors not reflected in current rates, such as the impact of weather, or the timing and nature of expenses or outages.

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Revenue provided by SCE&G and PSNC’s natural gas distribution operations primarily results from rates established by the South Carolina and North Carolina Commissions, respectively. Variability in earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, the availability and prices of alternative fuels and the economy.

SCE&G is a member of the Virginia-Carolinas Reliability Group, one of several geographic divisions within the SERC Reliability Corporation. The SERC Reliability Corporation is one of seven regional entities with delegated authority from NERC for the purpose of proposing and enforcing reliability standards approved by NERC.

COMPETITION

There is no competition for electric distribution or generation service within SCE&G’s service territory in South Carolina and no such competition is currently permitted. However, competition from third-party owners for development, construction and ownership of certain transmission facilities in SCE&G’s service territory is permitted pursuant to Order 1000, subject to state and local siting and permitting approvals. This could result in additional competition to build and own transmission infrastructure in SCE&G’s service area in the future.

Competition in Southeast Energy’s natural gas distribution operations is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and the ability to retain large commercial and industrial customers.

Southeast Energy’s marketing services for natural gas and other energy-related services face competition from affiliates of large energy companies and electric membership cooperatives, among others. The ability of Southeast Energy to maintain its market share primarily depends on the prices it charges customers relative to the prices charged by its competitors and its ability to provide high levels of customer service.

REGULATION

SCE&G’s electric distribution service, including the rates it may charge to jurisdictional customers, is subject to regulation by the South Carolina Commission. SCE&G’s electric generation operations are subject to regulation by the South Carolina Commission, FERC, the NRC, the EPA, the DOE and various other federal, state and local authorities. SCE&G’s electric transmission service is primarily regulated by FERC and the DOE. SCE&G and PSNC’s gas distribution operations are subject to regulation by the South Carolina and North Carolina Commissions, respectively, as well as PHMSA, the U.S. Department of Transportation, the South Carolina Office of Regulatory Staff and the North Carolina Commission for enforcement of federal and state pipeline safety requirements in their respective service territories. SEMI’s energy marketing activities are subject to regulation by the Georgia Public Service Commission as to retail prices for customers served under regulated provider contracts and FERC.

See State Regulations and Federal Regulations in Regulation for more information.

PROPERTIES

For a listing of existing property and facilities associated with Southeast Energy at January 1, 2019, see Item 2. Properties.

The following material reliability projects are currently under construction or development at SCE&G:

In response to revised Effluent Limitations Guidelines mandated by the EPA, SCE&G intends to upgrade the wastewater discharge filtration systems at the Williams and Wateree coal-fired generation facilities. The scope and scheduling of these projects is dependent on the finalization of the Effluent Limitations Guidelines, but is expected to cost approximately $250 million and be placed into service by the end of 2025.

In an effort to maintain the reliability and safety of the baghouse at its Cope coal-fired generation facility, SCE&G is currently replacing the existing carbon steel baghouse structure with a corrosion resistant material to address corrosion issues resulting from the dry scrubber system. The project is estimated to cost approximately $40 million and be placed into service by the end of 2020.

The following material reliability projects are currently under construction or development at PSNC:

PSNC plans to construct approximately 38 miles of transmission pipeline between Franklinton, North Carolina and Clayton, North Carolina, which will improve system reliability and provide the capacity necessary to support the growing natural gas demand in PSNC’s service territory. The project is expected to cost approximately $130 million and provide approximately 170,000 Dths per day. The project is expected to be placed into service in 2020.

PSNC is constructing a high-pressure distribution pipeline that will ultimately span 35 miles between Forest City, North Carolina and Marion, North Carolina, which will provide enhanced system reliability and safety. The project is expected to cost approximately $60 million and provide approximately 60,000 Dths per day. The project is expected to be placed into service in late 2019.

SOURCES OF ENERGY SUPPLY

Southeast Energy uses a variety of fuels to power its electric generation and purchases power for utility system load requirements. Presented below is a summary of SCANA’s actual system output by energy source :

Source	2018
Natural gas		37	%
Coal		35
Nuclear(1)		20
Other(2)		8
Total		100	%

(1) Excludes Santee Cooper’s 33.3% undivided ownership interest in Summer.

(2) Includes hydro, biomass and solar.

Natural gas—SCE&G purchases natural gas under contracts with producers and marketers on both a short-term and long-term basis at market-based prices. The gas is delivered to South Carolina through firm transportation agreements with various

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counterparties, which expire between 2019 and 2084. PSNC purchases natural gas under contracts with producers and marketers on a short-term basis at market-based prices and on a long-term basis for reliability assurance at first of the month index prices plus a reservation charge in certain cases. The gas is delivered to North Carolina through transportation agreements with Transco, which expire at various dates through 2031.

Coal—Southeast Energy primarily obtains coal through short-term and long-term contracts with suppliers located in eastern Kentucky, Tennessee, Virginia and West Virginia. These contracts provide for approximately 2.1 million tons annually. These contracts expire at various times through 2020. Spot market purchases may occur when needed or when prices are believed to be favorable.

Nuclear—Southeast Energy primarily utilizes long-term contracts to support its nuclear fuel requirements. SCE&G, for itself and as agent for Santee Cooper, and Westinghouse are parties to a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, SCE&G supplies enriched products to Westinghouse, who in turn supplies nuclear fuel assemblies for Summer. Westinghouse is SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements through 2033.

In addition, SCE&G has contracts covering its nuclear fuel needs for uranium, conversion services and enrichment services. These contracts have varying expiration dates through 2024. SCE&G believes that it will be able to renew these contracts as they expire or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services and that sufficient capacity for nuclear fuel supplies and processing exists to allow for normal operations of its nuclear generating unit. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal fuel and inventory levels.

SEASONALITY

Southeast Energy’s electric operations vary seasonally as a result of the impact of changes in temperature, the impact of storms and other catastrophic weather events and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree days does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials and because alternative heating sources are more readily available.

Southeast Energy’s gas operations vary seasonally as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. The majority of these earnings are generated during the heating season, which is generally from November to March; however, North Carolina and South Carolina have certain mechanisms designed to reduce the impact of weather-related fluctuations.

The earnings of Southeast Energy’s natural gas marketing operations also vary seasonally, and generally peak during the winter months to meet heating needs.

NUCLEAR DECOMMISSIONING

SCE&G has a two-thirds interest in one licensed, operating nuclear reactor at Summer in South Carolina.

Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. Amounts collected by ratepayers are placed into trusts and are invested to fund the expected future costs of decommissioning Summer.

SCE&G believes that the decommissioning funds and their expected earnings will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to this trust, if such future collections and contributions are required. SCE&G will continue to monitor this trust to ensure that it meets the NRC minimum financial assurance requirements, which may include, if needed, the use of Dominion Energy guarantees, surety bonding or other financial instruments recognized by the NRC.

The current estimated cost to SCE&G to decommission Summer is $626 million (stated in 2018 dollars), which is primarily based upon site-specific studies completed in 2016. These cost studies are generally completed every four to five years. Santee Cooper is responsible for the remaining 33.3% of decommissioning costs, proportionate with its ownership in Summer. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating license expires. The cost estimate reflects reductions for the expected future recovery of certain spent nuclear fuel costs based on SCE&G’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in SCANA’s nuclear decommissioning ARO. Currently, SCE&G has $190 million in a trust for its proportionate share of these decommissioning activities.

Under the current operating license, SCE&G is scheduled to decommission Summer in 2042. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. SCE&G is considering an operating license renewal for Summer.

Corporate and Other

Corporate and Other Segment-Virginia Power and Dominion Energy Gas

Virginia Power and Dominion Energy Gas’ Corporate and Other segments primarily include certain specific items attributable to their operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.

Corporate and Other Segment-Dominion Energy

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

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REGULATION

The Companies are subject to regulation by various federal, state and local authorities, including the state commissions of Virginia, North Carolina, South Carolina, Ohio, West Virginia, Georgia, Utah, Wyoming and Idaho, SEC, FERC, EPA, DOE, NRC, Army Corps of Engineers and the U.S. Department of Transportation.

State Regulations

ELECTRIC

Virginia Power and SCE&G’s electric utility retail services are subject to regulation by the Virginia and North Carolina Commissions and the South Carolina Commission, respectively.

Virginia Power and SCE&G hold CPCNs which authorize them to maintain and operate their electric facilities now in operation and to sell electricity to customers. However, Virginia Power and SCE&G may not construct generating facilities or large capacity transmission lines without the prior approval of various state and federal government agencies. In addition, the Virginia Commission and the North Carolina Commission regulate Virginia Power’s and the South Carolina Commission regulates SCE&G’s transactions with affiliates and transfers of certain facilities. The Virginia, North Carolina and South Carolina Commissions also regulate the issuance of certain securities.

Electric Regulation in Virginia

The Regulation Act instituted a cost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers.

The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, including pumped hydroelectricity generation and storage facilities as well as extensions of operating licenses of nuclear power generation facilities, FERC-approved transmission costs, underground distribution lines, environmental compliance, conservation and energy efficiency programs and renewable energy programs, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.

In March 2018, the GTSA reinstated base rate reviews on a triennial basis other than the first review, which will be a quadrennial review, occurring for Virginia Power in 2021 for the four successive 12-month test periods beginning January 1, 2017 and ending December 31, 2020. This review for Virginia Power will occur one year earlier than under the Regulation Act legislation enacted in February 2015.

In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized return on equity that might have been refunded to customers and served as the basis for a reduction in future rates, may be reduced by approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include in a customer credit reinvestment offset. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a customer credit reinvestment offset. Any costs that are the subject of a customer credit reinvestment offset may not be recovered in base

rates for the service life of the projects and may not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized return on equity, base rates are subject to reduction prospectively and customer refunds would be due unless the total customer credit reinvestment offset elected by the utility equals or exceeds the amount of earnings in excess of the 70 basis points. In the 2021 review, any such rate reduction is limited to $50 million.

The legislation also included provisions requiring Virginia Power to provide current customers one-time rate credits totaling $200 million and to reduce base rates to reflect reductions in income tax expense resulting from the 2017 Tax Reform Act. In addition, Virginia Power reduced base rates on an annual basis by $125 million effective July 2018, to reflect the estimated effect of the 2017 Tax Reform Act, which is subject to adjustment effective April 2019. In May and June 2018, Virginia Power submitted filings detailing the implementation plan for interim reductions in rates for generation and distribution services pursuant to the GTSA.

If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.

See Futures Issues and Other Matters in Item 7. MD&A and Note 13 to the Consolidated Financial Statements for additional information, which is incorporated herein by reference.

Electric Regulation in North Carolina

Virginia Power’s retail electric base rates in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes and the rules and procedures of the North Carolina Commission. North Carolina base rates are set by a process that allows Virginia Power to recover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the North Carolina Commission, retail electric rates may be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, Virginia Power’s future earnings could be negatively impacted. Fuel rates are subject to revision under annual fuel cost adjustment proceedings.

Virginia Power’s transmission service rates in North Carolina are regulated by the North Carolina Commission as part of Virginia Power’s bundled retail service to North Carolina customers. See Note 13 to the Consolidated Financial Statements for additional information, which is incorporated herein by reference.

Electric Regulation in South Carolina

SCE&G’s retail electric base rates in South Carolina are regulated on a cost-of-service/rate-of-return basis subject to South Carolina statutes and the rules and procedures of the South Carolina Commission. South Carolina base rates are set by a process that allows SCE&G to recover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the South Carolina Commission, retail electric rates may by sub-

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ject to review and possible reduction, which may decrease SCE&G’s future earnings. Additionally, if the South Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, SCE&G’s future earnings could be negatively impacted. Fuel costs are reviewed annually by the South Carolina Commission, as required by statute, and fuel rates are subject to revision in these annual fuel proceedings.

SCE&G offers to its retail electric customers several DSM programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the South Carolina Commission related to these programs. As actual DSM program costs are incurred, they are deferred as regulatory assets and recovered through a rider approved by the South Carolina Commission. The rider also provides for recovery of any net lost revenues and for a shared savings incentive.

In connection with the SCANA Combination, SCE&G agreed not to file a general rate case with the South Carolina Commission with a requested rate effective date earlier than January 2021. Rate adjustments are permitted prior to 2021 for fuel and environmental costs, DSM costs and other rates routinely adjusted on an annual or biennial basis.

See Note 3 to the Consolidated Financial Statements for additional information, which is incorporated herein by reference.

GAS

Dominion Energy Questar’s natural gas development, production, transportation, and distribution services, including the rates it may charge its customers, are regulated by the state commissions of Utah, Wyoming and Idaho. East Ohio’s natural gas distribution services, including the rates it may charge its customers, are regulated by the Ohio Commission. Hope’s natural gas distribution services are regulated by the West Virginia Commission. SCE&G and PSNC’s natural gas distribution services are regulated by the South Carolina Commission and North Carolina Commission, respectively.

Gas Regulation in Utah, Wyoming and Idaho

Questar Gas is subject to regulation of rates and other aspects of its business by the Utah, Wyoming and Idaho Commissions. The Idaho Commission has contracted with the Utah Commission for rate oversight of Questar Gas’ operations in a small area of southeastern Idaho. When necessary, Questar Gas seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. Base rates for Questar Gas are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. The volumetric charges for the residential and small commercial customers in Utah and Wyoming are subject to revenue decoupling and adjusted for changes in usage per customer.

In addition to general rate increases, Questar Gas makes routine separate filings with the Utah and Wyoming Commissions to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery through the Wexpro Agreement and Wexpro II Agreement. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas recovery filings generally cover a prospective twelve-month period. Approved increases or decreases in

gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

In connection with the Dominion Energy Questar Combination, Questar Gas withdrew its general rate case filed in July 2016 with the Utah Commission and agreed not to file a general rate case with the Utah Commission to adjust its base distribution non-gas rates prior to July 2019, unless otherwise ordered by the Utah Commission. In addition Questar Gas agreed not to file a general rate case with the Wyoming Commission with a requested rate effective date earlier than January 2020. This does not impact Questar Gas’ ability to adjust rates through various riders. See Notes 3 and 13 to the Consolidated Financial Statements for additional information.

Gas Regulation in Ohio

East Ohio is subject to regulation of rates and other aspects of its business by the Ohio Commission. When necessary, East Ohio seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. A straight-fixed-variable rate design, in which the majority of operating costs are recovered through a monthly charge rather than a volumetric charge, is utilized to establish rates for a majority of East Ohio’s customers pursuant to a 2008 rate case settlement.

In addition to general base rate increases, East Ohio makes routine filings with the Ohio Commission to reflect changes in the costs of gas purchased for operational balancing on its system. These purchased gas costs are subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The rider filings cover unrecovered gas costs plus prospective annual demand costs. Increases or decreases in gas cost rider rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

The Ohio Commission has also approved several stand-alone cost recovery mechanisms to recover specified costs and a return for infrastructure projects and certain other costs that vary widely over time; such costs are excluded from general base rates. See Note 13 to the Consolidated Financial Statements for additional information.

Gas Regulation in West Virginia

Hope is subject to regulation of rates and other aspects of its business by the West Virginia Commission. When necessary, Hope seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. Base rates for Hope are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges.

In addition to general rate increases, Hope makes routine separate filings with the West Virginia Commission to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings gen-

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erally cover a prospective twelve-month period. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

Legislation was passed in West Virginia authorizing a stand-alone cost recovery mechanism to recover specified costs and a return for infrastructure upgrades, replacements and expansions between general base rate cases. See Note 13 to the Consolidated Financial Statements for additional information.

Gas Regulation in North Carolina

PSNC is subject to regulation of rates and other aspects of its business by the North Carolina Commission. PSNC’s base rates are set in a general rate case based on the cost-of-service by rate class. Such rates are designed primarily based on a rate design methodology in which the majority of operating costs are recovered through volumetric charges.

PSNC has certain riders to its tariff that allow it to make periodic rate adjustment filings with the North Carolina Commission outside of a general rate case. PSNC’s purchased gas adjustment allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses. The purchased gas adjustment provides for a benchmark cost of gas rate component and a fixed gas cost component, both of which may be periodically adjusted to reflect changes in the costs of purchased gas, including transportation costs. In addition, PSNC utilizes a customer usage tracker, a decoupling mechanism, which allows it to adjust rates semi-annually for residential and commercial customers based on average customer consumption. PSNC also utilizes an integrity management tracker, which provides for semi-annual rate adjustments to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. All of these riders utilize deferral accounting to track over- and under-collected costs for subsequent rate consideration.

In connection with the SCANA Combination, PSNC agreed not to file a general rate case with the North Carolina Commission with a requested rate effective date earlier than November 2021 other than for rate adjustments pursuant to the customer usage tracker, the integrity management tracker and the purchased gas adjustment.

See Note 3 to the Consolidated Financial Statements for additional information, which is incorporated herein by reference.

Gas Regulation in South Carolina

SCE&G is subject to regulation of rates and other aspects of its natural gas distribution service by the South Carolina Commission. SCE&G provides retail natural gas service to customers in areas in which it has received authorization from the South Carolina Commission and in municipalities in which it holds a franchise. SCE&G’s base rates can be adjusted annually, pursuant to the Natural Gas Rate Stabilization Act, for recovery of costs related to natural gas infrastructure. Base rates are set based on the cost-of-service by rate class approved by the South Carolina Commission in the latest general rate case. Base rates for SCE&G are designed primarily based on a rate design methodology in which the majority of operating costs are recovered through volumetric charges. SCE&G also utilizes a weather normalization adjustment to adjust its base rates during the winter billing

months for residential and commercial customers to mitigate the effects of unusually cold or warm weather.

In addition, SCE&G’s natural gas tariffs include a purchased gas adjustment that provides for the recovery of prudently incurred gas costs, including transportation costs. SCE&G is authorized to adjust its purchased gas rates monthly and makes routine filings with the South Carolina Commission to provide notification of changes in these rates. Costs that are under or over recovered are deferred as regulatory assets or liabilities, respectively, and considered in subsequent purchased gas adjustments. The purchased gas adjustment filings generally cover a prospective twelve-month period. Increases or decreases in purchased gas costs can result in corresponding changes in purchased gas adjustment rates and the revenue generated by those rates. The South Carolina Commission reviews SCE&G’s gas purchasing policies and practices, including its administration of the purchased gas adjustment, annually.

See Note 3 to the Consolidated Financial Statements for additional information, which is incorporated herein by reference.

Status of Competitive Retail Gas Services

The states of Ohio and West Virginia, in which Dominion Energy and Dominion Energy Gas have gas distribution operations, have considered legislation regarding a competitive deregulation of natural gas sales at the retail level.

Ohio—Since October 2000, East Ohio has offered the Energy Choice program, under which residential and commercial customers are encouraged to purchase gas directly from retail suppliers or through a community aggregation program. In October 2006, East Ohio restructured its commodity service by entering into gas purchase contracts with selected suppliers at a fixed price above the New York Mercantile Exchange month-end settlement and passing that gas cost to customers under the Standard Service Offer program. Starting in April 2009, East Ohio buys natural gas under the Standard Service Offer program only for customers not eligible to participate in the Energy Choice program and places Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which is designated on the customers’ bills.

In January 2013, the Ohio Commission granted East Ohio’s motion to fully exit the merchant function for its nonresidential customers, beginning in April 2013, which requires those customers to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2018, approximately 1.1 million of Dominion Energy Gas’ 1.2 million Ohio customers were participating in the Energy Choice program. Subject to the Ohio Commission’s approval, East Ohio may eventually exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. East Ohio continues to be the provider of last resort in the event of default by a supplier. Large industrial customers in Ohio also source their own natural gas supplies.

West Virginia—At this time, West Virginia has not enacted legislation allowing customers to choose providers in the retail natural gas markets served by Hope. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customers a choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia.

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Federal Regulations

FEDERAL ENERGY REGULATORY COMMISSION

Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and sells electricity to wholesale purchasers in Virginia and North Carolina. Dominion Energy’s merchant generators sell electricity in the PJM, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California, South Carolina and Utah, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. In addition, Virginia Power and SCE&G have FERC approval of a tariff to sell wholesale power at capped rates based on their respective embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power and SCE&G’s service territories. Any such sales would be voluntary.

Dominion Energy and Virginia Power are subject to FERC’s Standards of Conduct that govern conduct between transmission function employees of interstate gas and electricity transmission providers and the marketing function employees of their affiliates. The rule defines the scope of transmission and marketing-related functions that are covered by the standards and is designed to prevent transmission providers from giving their affiliates undue preferences.

Dominion Energy and Virginia Power are also subject to FERC’s affiliate restrictions that (1) prohibit power sales between merchant plants and utility plants without first receiving FERC authorization, (2) require the merchant and utility plants to conduct their wholesale power sales operations separately, and (3) prohibit utilities from sharing market information with merchant plant operating personnel. The rules are designed to prohibit utilities from giving the merchant plants a competitive advantage.

EPACT included provisions to create an ERO. The ERO is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC has certified NERC as the ERO and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines of up to $1.2 million per day, per violation and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.

Dominion Energy and Virginia Power plan and operate their facilities in compliance with approved NERC reliability requirements. Dominion Energy and Virginia Power employees participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. Dominion Energy and Virginia Power anticipate incurring additional compliance expenditures over the next several years as a result of the implementation of new cybersecurity programs. In addition, NERC has redefined critical assets which expanded the number of assets subject to NERC reliability standards, including cybersecurity assets. NERC continues to develop additional requirements specifically regarding supply chain standards and control centers

that impact the bulk electric system. While Dominion Energy and Virginia Power expect to incur additional compliance costs in connection with NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.

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 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.

Gas

FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion Energy Questar Pipeline, DETI, DECG, Iroquois and certain services performed by Cove Point. The design, construction and operation of Cove Point’s LNG facility, including associated natural gas pipelines, the Liquefaction Project and the import and export of LNG are also regulated by FERC.

Dominion Energy and Dominion Energy Gas’ interstate gas transmission and storage activities are conducted on an open access basis, in accordance with certificates, tariffs and service agreements on file with FERC and FERC regulations.

Dominion Energy and Dominion Energy Gas operate in compliance with FERC standards of conduct, which prohibit the sharing of certain non-public transmission information or customer specific data by its interstate gas transmission and storage companies with non-transmission function employees. Pursuant to these standards of conduct, Dominion Energy and Dominion Energy Gas also make certain informational postings available on Dominion Energy’s website.

See Note 13 to the Consolidated Financial Statements for additional information.

Safety Regulations

Dominion Energy and Dominion Energy Gas are also subject to the Pipeline Safety Improvement Act of 2002 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which mandate inspections of interstate and intrastate natural gas transmission and storage pipelines, particularly those located in areas of high-density population. Dominion Energy and Dominion Energy Gas have evaluated their natural gas transmission and storage properties, as required by the U.S. Department of Transportation regulations under these Acts, and have implemented a program of identification, testing and potential remediation activities. These activities are ongoing.

The Companies are subject to a number of federal and state laws and regulations, including Occupational Safety and Health Administration, and comparable state statutes, whose purpose is to protect the health and safety of workers. The Companies have an internal safety, health and security program designed to mon-

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itor and enforce compliance with worker safety requirements, which is routinely reviewed and considered for improvement. The Companies believe that they are in material compliance with all applicable laws and regulations related to worker health and safety. Notwithstanding these preventive measures, incidents may occur that are outside of the Companies’ control.

Environmental Regulations

Each of the Companies’ operating segments faces substantial laws, regulations and compliance costs with respect to environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Companies. If compliance expenditures and associated operating costs are not recoverable from customers through regulated rates (in regulated businesses) or market prices (in unregulated businesses), those costs could adversely affect future results of operations and cash flows. The Companies have applied for or obtained the necessary environmental permits for the construction and operation of their facilities. Many of these permits are subject to reissuance and continuing review. For a discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance required to be discussed in this Item, see Environmental Matters in Future Issues and Other Matters in Item 7. MD&A, which information is incorporated herein by reference. Additional information can also be found in Item 3. Legal Proceedings and Note 22 to the Consolidated Financial Statements, which information is incorporated herein by reference.

AIR

The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. Regulated emissions include, but are not limited to, carbon, methane, VOC, other GHGs, mercury, other toxic metals, hydrogen chloride, NO_X, SO₂ and particulate matter. At a minimum, delegated 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.

GLOBAL CLIMATE CHANGE

The Companies support national climate change legislation that would provide a consistent, economy-wide approach to addressing this issue and are currently taking action to protect the environment and reduce GHG emissions while meeting the growing needs of their customers. Dominion Energy’s CEO and operating segment CEOs are responsible for compliance with the laws and regulations governing environmental matters, including GHG emissions, and Dominion Energy’s Board of Directors receives periodic updates on these matters. See Environmental Strategy below, Environmental Matters in Future Issues and Other Matters in Item 7. MD&A and Note 22 to the Consolidated Financial Statements for information on climate change legislation and regulation, which information is incorporated herein by reference.

WATER

The CWA 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 CWA and analogous state laws impose restrictions and strict controls regarding discharges of effluent into surface waters and require permits to be obtained from the EPA or the analogous state agency for those discharges. Containment berms and similar structures may be required to help prevent accidental releases. Dominion Energy must comply with applicable CWA requirements at its current and former operating facilities. Stormwater related to construction activities is also regulated under the CWA and by state and local stormwater management and erosion and sediment control laws. From time to time, Dominion Energy’s projects and operations may impact tidal and non-tidal wetlands. In these instances, Dominion Energy must obtain authorization from the appropriate federal, state and local agencies prior to impacting wetlands. The authorizing agency may impose significant direct or indirect mitigation costs to compensate for such impacts to wetlands.

WASTE AND CHEMICAL MANAGEMENT

Dominion Energy is subject to various federal and state laws and implementing regulations governing the management, storage, treatment, reuse and disposal of waste materials and hazardous substances, including the Resources Conservation and Recovery Act of 1976, CERCLA, the Emergency Planning and Community Right-to-Know Act of 1986 and the Toxic Substance Control Act of 1976. Dominion Energy’s operations and construction activities, including activities associated with oil and gas production and gas storage wells, generate waste. Across Dominion Energy, completion water is disposed at commercial disposal facilities. Produced water is either hauled for disposal, evaporated or injected into company and third-party owned underground injection wells. Wells drilled in tight-gas-sand and shale reservoirs require hydraulic-fracture stimulation to achieve economic production rates and recoverable reserves. The majority of Wexpro’s current and future production and reserve potential is derived from reservoirs that require hydraulic-fracture stimulation to be commercially viable. Currently, all well construction activities, including hydraulic-fracture stimulation and management and disposal of hydraulic fracturing fluids, are regulated by federal and state agencies that review and approve all aspects of gas- and oil-well design and operation.

PROTECTED SPECIES

The ESA and analogous state laws prohibit activities that can result in harm to specific species of plants and animals, as well as impacts to the habitat on which those species depend. In addition to ESA programs, the MBTA and BGEPA establish broader prohibitions on harm to protected birds. Many of the Companies’ facilities are subject to requirements of the ESA, MBTA and BGEPA. The ESA and BGEPA require potentially lengthy coordination with the state and federal agencies to ensure potentially affected species are protected. Ultimately, the suite of species protections may restrict company activities to certain times of year, project modifications may be necessary to avoid harm, or a permit may be needed for unavoidable taking of the species. The authorizing agency may impose mitigation requirements and costs

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to compensate for harm of a protected species or habitat loss. These requirements and time of year restrictions can result in adverse impacts on project plans and schedules such that the Companies’ businesses may be materially affected.

OTHER REGULATIONS

Other significant environmental regulations to which the Companies are subject include federal and state laws protecting graves, sacred sites, historic sites and cultural resources, including those of American Indian tribal nations and tribal communities. These can result in compliance and mitigation costs as well as potential adverse effects on project plans and schedules such that the Companies’ businesses may be materially affected.

Nuclear Regulatory Commission

All aspects of the operation and maintenance of Dominion Energy and Virginia Power’s nuclear power stations are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.

From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining Dominion Energy and Virginia Power’s nuclear generating units. See Note 22 to the Consolidated Financial Statements for further information.

The NRC also requires Dominion Energy and Virginia Power to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and Dominion Energy and Virginia Power are required by the NRC to be financially prepared. For information on decommissioning trusts, see Power Generation-Nuclear Decommissioning and Southeast Energy-Nuclear Decommissioning above and Notes 3 and 9 to the Consolidated Financial Statements. See Notes 3 and 22 to the Consolidated Financial Statements for information on spent nuclear fuel.

ENVIRONMENTAL STRATEGY

The Companies’ environmental strategy is a component of the overall long-term strategic planning overseen by the CEO and Board of Directors, including oversight by the sustainability and corporate responsibility board committee which was formed in 2018. The Companies are committed to continuing to be an industry leader, delivering safe, reliable, clean and affordable energy while fully complying with all applicable environmental laws and regulations. Additionally, the Companies seek to build partnerships and engage with local communities, stakeholders and customers on environmental issues important to them, including environmental justice considerations such as fair treatment, inclusive involvement and effective communication. The Companies believe in being transparent about their environmental commitments, policies, including the Environmental Justice Policy adopted in 2018, and initiatives which have been

disclosed in reports included on Dominion Energy’s website. The Companies are dedicated to meeting their customers’ growing energy needs with innovative, sustainable solutions. It is the Companies’ belief that sustainable solutions should strive to balance the interdependent goals of environmental stewardship and economic effects. The integrated strategy to meet these objectives consists of three major elements:

• Reduction of GHG emissions;

• Energy infrastructure modernization, including natural gas and electric operations; and

• Conservation and energy efficiency.

Reduction of GHG Emissions

The Companies’ integrated strategy has resulted in a reduction in GHG emission intensity. Over the past two decades, the Companies have made changes to the generation mix and to natural gas operations which have significantly improved environmental performance. For example, Power Generation has reduced both its carbon emissions and its carbon intensity while generating electricity with an increasingly clean portfolio. From 2000 through 2017, Dominion Energy’s carbon intensity decreased by 50%. This strategy has also resulted in measurable reductions of other air pollutants such as NO_X, SO₂ and mercury and also reduced the amount of coal ash generated and the amount of water withdrawn. The principal components of the strategy include initiatives that address electric energy production and delivery, natural gas storage, transmission and delivery and energy management.

See Operating Segments for more information on certain of the projects described above.

CLEANER GENERATION

Renewable energy is an important component of a diverse and reliable energy mix that helps to mitigate the environmental aspects of energy production. Dominion Energy has nearly 2,600 MW of solar generating capacity in operation or under development in nine states, including offtake agreements for Virginia Power’s utility customers. Virginia, North Carolina and South Carolina have passed legislation setting targets for renewable power. Dominion Energy continues to add utility-scale solar capacity and is committed to meeting Virginia’s goals of 12% of base year electric energy sales from renewable power sources by 2022, and 15% by 2025, North Carolina’s Renewable Portfolio Standard of 12.5% by 2021 and South Carolina’s goal of 2% of aggregate generation capacity from renewable power sources by 2021. Backed by a $1 billion investment from 2018 through 2020, Dominion Energy has grown its solar fleet in Virginia and North Carolina to about 1,700 MW in service, in construction or under development.

See Operating Segments and Item 2. Properties for additional information, including Dominion Energy’s merchant solar properties.

GHG EMISSIONS

Since 2000, Dominion Energy and Virginia Power have tracked the emissions of their electric generation fleet, which employs a mix of fuel and renewable energy sources. Comparing annual year 2017 to annual year 2000, the entire electric generating fleet

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(based on ownership percentage) reduced its average CO₂ emissions per MWh of energy produced from electric generation by approximately 50%. Comparing annual year 2017 to annual year 2000, the regulated electric generating fleet (based on ownership percentage) reduced its average CO₂ emissions per MWh of energy produced from electric generation by approximately 35%. Dominion Energy and Virginia Power’s 2018 emissions data is not yet available.

Dominion Energy also develops a comprehensive GHG inventory annually. For Power Generation, Dominion Energy and Virginia Power’s direct CO₂ equivalent emissions (based on ownership percentage) were 30.1 million metric tons and 26.4 million metric tons, respectively, in 2017, compared to 37.2 million metric tons and 33.1 million metric tons, respectively, in 2016. The corresponding Power Generation carbon intensity rates for Dominion Energy were 0.295 metric tons CO₂ equivalent emissions per net MWh in 2017 and 0.339 metric tons CO₂ equivalent emissions per net MWh in 2016.

For Power Delivery’s regulated electric transmission and distribution operations, direct CO₂ equivalent emissions for 2017 were 37,841 metric tons, compared to 42,847 metric tons in 2016.

Dominion Energy’s natural gas companies have been reporting GHG emissions to the EPA since 2011 under the GHG Reporting Program. In January 2016, the GHG Reporting Program was expanded to also include GHG inputs and emissions associated with natural gas gathering and boosting sources and transmission pipeline blowdowns for facilities that exceed 25,000 metric tons per year of CO₂ equivalent emissions. The sources within these new facilities were not previously covered under the rule and the first reports for these new sources were submitted to the EPA on March 31, 2017.

Hope and East Ohio’s direct CO₂ equivalent emissions together increased to 0.88 million metric tons in 2017 from 0.86 in 2016. DETI and Cove Point’s direct CO₂ equivalent emissions together were 1.6 million metric tons in 2017, increasing from 1.3 million metric tons in 2016, attributable to increased operational activity related to new construction.

The Companies’ GHG inventory follows all methodologies specified in the EPA Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98 for calculating emissions. Total CO₂ equivalent emissions reported for our natural gas assets, as estimated in Dominion Energy’s corporate inventory, were 3.51 million metric tons in 2017. This estimate includes emissions reported under the GHG Reporting Program, as well as other emissions not required to be reported under the federal program. The 2017 corporate GHG inventory emission estimate includes Dominion Energy Questar Pipeline, Questar Gas and Wexpro for the entire calendar year. Dominion Energy’s 2017 methane emissions reported under Subpart W of the Greenhouse Gas Reporting Rule are as follows:

Subpart W Segment	Subpart W Total CH4 Emissions (mcf CH4)
Distribution		1,668,183
Production		762,788
Transmission pipelines		396,720
Transmission compressor stations		147,565
Gathering and boosting		144,188
Storage		53,748
LNG import/export		6,444
Processing		916

Energy Infrastructure Modernization

Dominion Energy’s investment plan from 2019 through 2023 includes a focus on upgrading the electric grid in Virginia through investments in additional renewable generation facilities, smart meters, customer information platform, intelligent grid devices and associated control systems, physical and cyber security investments, strategic undergrounding and energy conservation programs. Dominion Energy also plans to upgrade its gas and electric transmission and distribution networks and meet environmental requirements and standards set by various regulatory bodies. These enhancements are primarily aimed at meeting Dominion Energy’s continued goal of providing reliable service and to address increases in electricity consumption. An additional benefit will be added capacity to efficiently deliver electricity from the renewable projects now being developed, or to be developed in the future, to meet our customers’ preference for cleaner energy. See Operating Segments for additional information.

The Companies have also implemented infrastructure improvements and improved operational practices to reduce the GHG emissions from our natural gas facilities. Dominion Energy and Dominion Energy Gas, in connection with the investment plan, are also pursuing the construction or upgrade of regulated infrastructure in their natural gas businesses. The Companies have made voluntary commitments as part of the EPA Methane Challenge Program to continue to reduce methane emissions as part of these improvements. See Operating Segments for additional information, including natural gas infrastructure projects.

Conservation and Energy Efficiency

Conservation and load management play a significant role in meeting the growing demand for electricity and natural gas, while also helping to reduce the environmental footprint of our customers. The Companies offer various energy efficiency programs in Virginia,

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North Carolina, Ohio, South Carolina, Utah and Wyoming designed to reduce energy consumption including programs such as:

• Energy audits and assessments;

• Incentives for customers to upgrade or install certain energy efficient measures and/or systems;

• Weatherization assistance to help income-eligible customers reduce their energy usage;

• Home energy planning, which provides homeowners with a step-by-step roadmap to efficiency improvements to reduce gas usage; and

• Rebates for installing high-efficiency equipment.

CYBERSECURITY

In an effort to reduce the likelihood and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In November 2018, Dominion Energy appointed a Chief Security Officer who is responsible for the further development and implementation of corporate security policies and procedures that protect cyber assets. In addition, the Companies are subject to mandatory cybersecurity regulatory requirements, including those enacted in December 2018 by FERC with compliance requirements effective in 2020, interface regularly with a wide range of external organizations and participate in classified briefings to maintain an awareness of current cybersecurity threats and vulnerabilities. The Companies’ current security posture and regulatory compliance efforts are intended to address the evolving and changing cyber threats. See Item 1A. Risk Factors for additional information.

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 their control. A number of these factors have been identified below. 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 Item 7. MD&A.

The Companies’ results of operations can be affected by changes in the weather. Fluctuations in weather can affect demand for the Companies’ services. For example, milder than normal weather can reduce demand for electricity and gas transmission and distribution services. In addition, severe weather, including hurricanes, winter storms, earthquakes, floods and other natural disasters can stress systems, disrupt operation of the Companies’ facilities and cause service outages, production delays and property damage that require incurring additional expenses. Changes in weather conditions can result in reduced water levels or changes in water temperatures that could adversely affect operations at some of the Companies’ power stations. Furthermore, the Companies’ operations could be adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level or sea temperatures.

The rates of Dominion Energy and Dominion Energy Gas’ gas transmission and distribution operations and Dominion Energy and Virginia Power’s electric transmission, distribution and generation operations are subject to regulatory review. Revenue provided by Dominion Energy and Virginia Power’s electric transmission, distribution and generation operations and Dominion Energy and Dominion Energy Gas’ gas transmission and distribution operations is based primarily on rates approved by state and federal regulatory agencies. However, certain large scale customers are able to enter into negotiated-rate contracts rather than pay cost-of-service rates which are subject to regulatory review. The profitability of these businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.

Dominion Energy and Virginia Power’s wholesale rates for electric transmission service are updated on an annual basis through operation of a FERC-approved formula rate mechanism. Through this mechanism, Dominion Energy and Virginia Power’s wholesale rates for electric transmission reflect the estimated cost-of-service for each calendar year. The difference in the estimated cost-of-service and actual cost-of-service for each calendar year is included as an adjustment to the wholesale rates for electric transmission service in a subsequent calendar year. These wholesale rates are subject to FERC review and prospective adjustment in the event that customers and/or interested state commissions file a complaint with FERC and are able to demonstrate that Dominion Energy or Virginia Power’s wholesale revenue requirement is no longer just and reasonable. They are also subject to retroactive corrections to the extent that the formula rate was not properly populated with the actual costs.

Similarly, various rates and charges assessed by Dominion Energy and Dominion Energy Gas’ gas transmission businesses are subject to review by FERC. In addition, the rates of Dominion Energy and Dominion Energy Gas’ gas distribution businesses are subject to state regulatory review in the jurisdictions in which they operate. A failure by Dominion Energy or Dominion Energy Gas to support these rates could result in rate decreases from current rate levels, which could adversely affect Dominion Energy and Dominion Energy Gas’ results of operations, cash flows and financial condition.

Virginia Power’s base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia Commission in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a historic test period, and the determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances described in the Regulation Act, Virginia Power may be required to share a portion of its earnings with customers through a refund process.

Dominion Energy and Virginia Power’s retail electric base rates for bundled generation, transmission, and distribution services to customers in South Carolina and North Carolina, respectively, are regulated on a cost-of-service/rate-of-return basis subject to South Carolina and North Carolina statutes, and the rules and procedures of the South Carolina and North Carolina Commissions. If retail electric earnings exceed the returns established by the South Carolina Commission and the North Carolina Commission, retail electric rates may be subject to review and

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possible reduction by the South Carolina Commission and the North Carolina Commission, which may decrease Dominion Energy and Virginia Power’s future earnings, respectively. Additionally, if the South Carolina and the North Carolina Commission do not allow recovery through base rates, on a timely basis, of costs incurred in providing service, Dominion Energy and Virginia Power’s future earnings could be negatively impacted.

Governmental officials, stakeholders and advocacy groups may challenge these regulatory reviews. Such challenges may lengthen the time, complexity and costs associated with such regulatory reviews.

The Companies are subject to complex governmental regulation, including tax regulation, that could adversely affect their results of operations and subject the Companies to monetary penalties. The Companies’ operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates from various governmental agencies. Such laws and regulations govern the terms and conditions of the services we offer, our relationships with affiliates, protection of our critical electric infrastructure assets and pipeline safety, among other matters. These operations are also subject to legislation governing taxation at the federal, state and local level. They must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that the business is conducted in accordance with applicable laws. The Companies’ businesses are subject to regulatory regimes which could result in substantial monetary penalties if any of the Companies is found not to be in compliance, including mandatory reliability standards and interaction in the wholesale markets. New laws or regulations, the revision or reinterpretation of existing laws or regulations, changes in enforcement practices of regulators, or penalties imposed for non-compliance with existing laws or regulations may result in substantial additional expense. Recent legislative and regulatory changes that are impacting the Companies include the 2017 Tax Reform Act and tariffs imposed on imported solar panels by the U.S. government in 2018.

The 2017 Tax Reform Act could have a material impact on our operations, cash flows, and financial results. Reductions in the estimated annual cost-of-service effect (commonly referred to as the gross-up factor) due to the reduction in the corporate income tax rates to 21% under the provisions of the 2017 Tax Reform Act have been recognized as a regulatory liability and are expected to be refunded to customers, generally through reductions in future rates or in the form of credits to customer bills. In addition, the Companies’ regulators may require the reduction in accumulated deferred income tax balances under the provisions of the 2017 Tax Reform Act to be shared with customers, generally through reductions in future rates or in the form of credits to customer bills. The 2017 Tax Reform Act includes provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential reductions in future rates attributable to other, non-plant related excess deferred taxes may be determined by our regulators.

The 2017 Tax Reform Act could have a material impact on Dominion Energy and Dominion Energy Gas’ FERC-regulated gas operations including rates charged to customers. In light of the reduction in the income tax rate in the 2017 Tax Reform Act, our FERC-regulated gas subsidiaries were required to file

informational reports to substantiate the rates charged for transportation and storage of natural gas in interstate commerce, when viewed holistically, are “just and reasonable” taking into account the effects of the 2017 Tax Reform Act and all other drivers. It is unclear if FERC will mandate a one-time rate reset or Section 5 rate case for Dominion Energy and Dominion Energy Gas’ FERC-regulated gas subsidiaries; however, any such action could have a material impact on our operations, cash flows and financial results.

The interpretation of provisions of the 2017 Tax Reform Act that take effect in 2019 may significantly impact our operations. The 2017 Tax Reform Act contains provisions that limit the deductibility of interest expense. The provisions generally limit the interest deduction on business interest to (1) business interest income, plus (2) 30 percent of the taxpayer’s adjusted taxable income. Business interest and business interest income is defined as that allocable to a trade or business and not investment interest and income. Dominion Energy is a consolidated group with both regulated and nonregulated lines of businesses. In November 2018, the U.S. Department of Treasury issued proposed regulations defining interest as any amounts associated with the time value of money or use of funds. These proposed regulations provide guidance for purposes of the exception to the interest limitation for regulated public utilities, the application of the interest limitation to consolidated groups, such as Dominion Energy, and the interest limitation with respect to partnerships and partners in those partnerships. It is unclear when that guidance may be finalized, or whether that guidance could result in a disallowance of a portion of our interest deductions in the future.

Dominion Energy and Virginia Power’s generation business may be negatively affected by possible FERC actions that could change market design in the wholesale markets or affect pricing rules or revenue calculations in the RTO markets. Dominion Energy and Virginia Power’s generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize RTOs to make changes in market design. FERC also periodically reviews Dominion Energy’s authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets or its interpretation of market rules, Dominion Energy or Virginia Power’s authority to sell power at market-based rates, or changes to pricing rules or rules involving revenue calculations, could adversely impact the future results of Dominion Energy or Virginia Power’s generation business. For example, in June 2018, FERC issued an order on PJM’s Minimum Offer Price Rule proposals finding the PJM tariff unjust and unreasonable because state out-of-market support for resources is suppressing PJM capacity prices and the current tariff provisions do not adequately address the price suppression. FERC is evaluating an alternative that would pull any state supported resource out of the capacity market along with an equivalent amount of load. In addition, there have been changes to the interpretation and application of FERC’s market manipulation rules. A failure to comply with these rules could lead to civil and criminal penalties.

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The Companies’ infrastructure build and expansion plans often require regulatory approval, including environmental permits, before commencing construction and completing projects. The Companies may not complete facility construction, pipeline, conversion or other infrastructure projects that they commence, or they may complete projects on materially different terms or timing than initially anticipated, and they may not be able to achieve the intended benefits of any such project, if completed. Several facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects have been announced and additional projects may be considered in the future. The Companies compete for projects with companies of varying size and financial capabilities, including some that may have competitive advantages. Commencing construction on announced and future projects may require approvals from applicable state and federal agencies, and such approvals could include mitigation costs which may be material to the Companies. Projects may not be able to be completed on time as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a decline in the credit strength of counterparties or vendors, or other factors beyond the Companies’ control. For example, Atlantic Coast Pipeline has experienced certain delays in obtaining permits necessary for construction along with construction delays due to judicial actions which has impacted the cost and schedule for the Atlantic Coast Pipeline Project. Even if facility construction, pipeline, expansion, electric transmission line, conversion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of the Companies following completion of the projects may not meet expectations. Start-up and operational issues can arise in connection with the commencement of commercial operations at our facilities. Such issues may include failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, the Companies may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies’ ability to realize the anticipated benefits from the facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects.

The development, construction and commissioning of several large-scale infrastructure projects simultaneously involves significant execution risk. The Companies are currently simultaneously developing, constructing or commissioning several major projects, including the Atlantic Coast Pipeline Project, the Supply Header project and the Coastal Virginia Offshore Wind project. Several of the Companies’ key projects are increasingly large-scale, complex and being constructed in constrained geographic areas or in difficult terrain, for example, the Atlantic Coast Pipeline Project. The advancement of the Companies’ ventures is also affected by the interventions, litigation or other activities of stakeholder and advocacy groups, some of which oppose natural gas-related and energy infrastructure projects. For example, certain landowners and stakeholder groups oppose the Atlantic Coast Pipeline

Project, which could impede construction activities or the acquisition of rights-of-way and other land rights on a timely basis or on acceptable terms. Given that these projects provide the foundation for the Companies’ strategic growth plan, if the Companies are unable to obtain or maintain the required approvals, develop the necessary technical expertise, allocate and coordinate sufficient resources, adhere to budgets and timelines, effectively handle public outreach efforts, or otherwise fail to successfully execute the projects, there could be an adverse impact to the Companies’ financial position, results of operations and cash flows. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect the Companies’ ability to execute their business plan.

The Companies are dependent on their contractors for the successful and timely completion of large-scale infrastructure projects. The construction of such projects is expected to take several years, is typically confined within a limited geographic area or difficult terrain and could be subject to delays, cost overruns, labor disputes and other factors that could cause the total cost of the project to exceed the anticipated amount and adversely affect the Companies’ financial performance and/or impair the Companies’ ability to execute the business plan for the project as scheduled.

Further, an inability to obtain financing or otherwise provide liquidity for the projects on acceptable terms could negatively affect the Companies’ financial condition, cash flows, the projects’ anticipated financial results and/or impair the Companies’ ability to execute the business plan for the projects as scheduled.

The Companies’ operations and construction activities are subject to a number of environmental laws and regulations which impose significant compliance costs to the Companies. The Companies’ operations and construction activities are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources, and health and safety. Compliance with these legal requirements requires the Companies to commit significant capital toward permitting, emission fees, environmental monitoring, installation and operation of environmental control equipment and purchase of allowances and/or offsets. Additionally, the Companies could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and the Companies expect that they will remain significant in the future. Certain facilities have become uneconomical to operate and have been shut down, converted to new fuel types or sold. These types of events could occur again in the future.

We expect that existing environmental laws and regulations may be revised and/or new laws may be adopted including regulation of GHG emissions which could have an impact on the Companies’ business. Risks relating to expected regulation of GHG emissions from existing fossil fuel-fired electric generating units are discussed below. In addition, further regulation of air quality and GHG emissions under the CAA have been imposed on the natural gas sector, including rules to limit methane leakage. The Companies are also subject to federal water and waste regulations, including regulations concerning cooling water intake structures, coal combustion by-product handling and disposal

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practices, wastewater discharges from steam electric generating stations, management and disposal of hydraulic fracturing fluids and the potential further regulation of polychlorinated biphenyls.

Compliance costs cannot be estimated with certainty due to the inability to predict the requirements and timing of implementation of any new environmental rules or regulations. Other factors which affect the ability to predict future environmental expenditures with certainty include the difficulty in estimating clean-up costs and quantifying liabilities under environmental laws that impose joint and several liabilities on all responsible parties. However, such expenditures, if material, could make the Companies’ facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect the Companies’ results of operations, financial performance or liquidity.

Any additional federal and/or state requirements imposed on energy companies mandating limitations on GHG emissions or requiring efficiency improvements may result in compliance costs that alone or in combination could make some of the Companies’ electric generation units or natural gas facilities uneconomical to maintain or operate. The EPA has proposed the Affordable Clean Energy rule targeted at reducing CO₂ emissions from existing fossil fuel-fired power generation facilities as a replacement for the Clean Power Plan which has been stayed. The Affordable Clean Energy rule would require states to develop plans within three years of the final rule to implement these performance standards. States are also contemplating regulations regarding GHG emissions. For example, the Virginia General Assembly recently considered legislation which would authorize the state to directly join the RGGI program as a full participant. Compliance with the proposed Affordable Clean Energy rule or other federal or state carbon regulations is expected to require increasing the energy efficiency of equipment at facilities, committing significant capital toward carbon reduction programs, purchase of allowances and/or emission rate credits, fuel switching, and/or retirement of high-emitting generation facilities and potential replacement with lower-emitting generation facilities. Given these developments and uncertainties, Dominion Energy and Virginia Power cannot estimate the aggregate effect of such requirements on their results of operations, financial condition or their customers. However, such expenditures, if material, could make Dominion Energy and Virginia Power’s generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion Energy or Virginia Power’s results of operations, financial performance or liquidity.

There are also potential impacts on Dominion Energy and Dominion Energy Gas’ natural gas businesses as federal or state GHG regulations may require GHG emission reductions from the natural gas sector which, in addition to resulting in increased costs, could affect demand for natural gas. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products, which could impact the natural gas businesses.

Dominion Energy and Virginia Power are subject to risks associated with the disposal and storage of coal ash. Dominion Energy and Virginia Power historically produced and continue to produce coal ash, or CCRs, as a by-product of their coal-fired generation operations. The ash is stored and managed in

impoundments (ash ponds) and landfills located at 11 different facilities, eight of which are at Virginia Power.

The EPA has issued regulations concerning the management and storage of CCRs, which Virginia has adopted. These CCR regulations require Dominion Energy and Virginia Power to make additional capital expenditures and increase operating and maintenance expenses. In addition, Dominion Energy and Virginia Power will incur expenses and other costs associated with closing, corrective action and ongoing monitoring of certain ash ponds. Dominion Energy and Virginia Power also may face litigation concerning their coal ash facilities.

Further, while Dominion Energy and Virginia Power operate their ash ponds and landfills in compliance with applicable state safety regulations, a release of coal ash with a significant environmental impact, such as the Dan River ash basin release by a neighboring utility, could result in remediation costs, civil and/or criminal penalties, claims, litigation, increased regulation and compliance costs, and reputational damage, and could impact the financial condition of Dominion Energy and/or Virginia Power.

The Companies’ operations are subject to operational hazards, equipment failures, supply chain disruptions and personnel issues which could negatively affect the Companies. Operation of the Companies’ facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply, pipeline integrity or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, changes to the environment and performance below expected levels. The Companies’ businesses are dependent upon sophisticated information technology systems and network infrastructure, the failure of which could prevent them from accomplishing critical business functions. Because the Companies’ transmission facilities, pipelines and other facilities are interconnected with those of third parties, the operation of their facilities and pipelines could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.

Operation of the Companies’ facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of the Companies’ facilities and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Companies’ business. Unplanned outages typically increase the Companies’ operation and maintenance expenses and may reduce their revenues as a result of selling less output or may require the Companies to incur significant costs as a result of operating higher cost units or obtaining replacement output from third parties in the open market to satisfy forward energy and capacity or other contractual obligations. Moreover, if the Companies are unable to perform their contractual obligations, penalties or liability for damages could result.

In addition, there are many risks associated with the Companies’ operations and the transportation, storage and processing of natural gas and NGLs, including nuclear accidents, fires, explosions, uncontrolled release of natural gas and other environ-

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mental hazards, pole strikes, electric contact cases, the collision of third party equipment with pipelines and avian and other wildlife impacts. Such incidents could result in loss of human life or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or business interruptions and associated public or employee safety impacts, loss of revenues, increased liabilities, heightened regulatory scrutiny and reputational risk. Further, the location of pipelines and storage facilities, or generation, transmission, substations and distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.

Dominion Energy and Virginia Power have substantial ownership interests in and operate nuclear generating units; as a result, each may incur substantial costs and liabilities. Dominion Energy and Virginia Power’s nuclear facilities are subject to operational, environmental, health and financial risks such as the on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, limitations on the amounts and types of insurance available, potential operational liabilities and extended outages, the costs of replacement power, the costs of maintenance and the costs of securing the facilities against possible terrorist attacks. Dominion Energy and Virginia Power maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that future decommissioning costs could exceed amounts in the decommissioning trusts and/or damages could exceed the amount of insurance coverage. If Dominion Energy and Virginia Power’s decommissioning trust funds are insufficient, and they are not allowed to recover the additional costs incurred through insurance or regulatory mechanisms, their results of operations could be negatively impacted.

Dominion Energy and Virginia Power’s nuclear facilities are also subject to complex government regulation which could negatively impact their results of operations. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending on its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require Dominion Energy and Virginia Power to make substantial expenditures at their nuclear plants. In addition, although the Companies have no reason to anticipate a serious nuclear incident at their plants, if an incident did occur, it could materially and adversely affect their results of operations and/or financial condition. A major incident at a nuclear facility anywhere in the world, such as the nuclear events in Japan in 2011, could cause the NRC to adopt increased safety regulations or otherwise limit or restrict the operation or licensing of domestic nuclear units.

Sustained declines in natural gas and NGL prices have resulted in, and could result in further, curtailments of third-party producers’ drilling programs, delaying the production of volumes of natural gas and NGLs that Dominion Energy and Dominion Energy Gas gather, process, and transport and reducing the value of NGLs retained by Dominion Energy Gas, which may adversely affect Dominion Energy and Dominion

Energy Gas’ revenues and earnings. Dominion Energy and Dominion Energy Gas obtain their supply of natural gas and NGLs from numerous third-party producers. Most producers are under no obligation to deliver a specific quantity of natural gas or NGLs to Dominion Energy and Dominion Energy Gas’ facilities. A number of other factors could reduce the volumes of natural gas and NGLs available to Dominion Energy and Dominion Energy Gas’ pipelines and other assets. Increased regulation of energy extraction activities could result in reductions in drilling for new natural gas wells, which could decrease the volumes of natural gas supplied to Dominion Energy and Dominion Energy Gas. Producers with direct commodity price exposure face liquidity constraints, which could present a credit risk to Dominion Energy and Dominion Energy Gas. Producers could shift their production activities to regions outside Dominion Energy and Dominion Energy Gas’ footprint. In addition, the extent of natural gas reserves and the rate of production from such reserves may be less than anticipated. If producers were to decrease the supply of natural gas or NGLs to Dominion Energy and Dominion Energy Gas’ systems and facilities for any reason, Dominion Energy and Dominion Energy Gas could experience lower revenues to the extent they are unable to replace the lost volumes on similar terms. In addition, Dominion Energy Gas’ revenue from processing and fractionation operations largely results from the sale of commodities at market prices. Dominion Energy Gas receives the wet gas product from producers and may retain the extracted NGLs as compensation for its services. This exposes Dominion Energy Gas to commodity price risk for the value of the spread between the NGL products and natural gas, and relative changes in these prices could adversely impact Dominion Energy Gas’ results.

Dominion Energy’s merchant power business operates in a challenging market, which could adversely affect its results of operations and future growth. The success of Dominion Energy’s merchant power business depends upon favorable market conditions including the ability to sell power at prices sufficient to cover its operating costs. Dominion Energy operates in active wholesale markets that expose it to price volatility for electricity and nuclear fuel as well as the credit risk of counterparties. Dominion Energy attempts to manage its price risk by entering into hedging transactions, including short-term and long-term fixed price sales and purchase contracts.

In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently, the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore, changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion Energy does not enter into long-term power purchase agreements or otherwise effectively hedge its output, these changes in market prices could adversely affect its financial results.

Dominion Energy purchases nuclear fuel primarily under long-term contracts. Dominion Energy is exposed to nuclear fuel cost volatility for the portion of its nuclear fuel obtained through short-term contracts or on the spot market, including as a result

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of market supply shortages. Nuclear fuel prices can be volatile and the price that can be obtained for power produced may not change at the same rate as nuclear fuel costs, thus adversely impacting Dominion Energy’s financial results. In addition, in the event that any of the merchant generation facilities experience a forced outage, Dominion Energy may not receive the level of revenue it anticipated.

The Companies’ financial results can be adversely affected by various factors driving supply and demand for electricity and gas and related services. Technological advances required by federal laws mandate new levels of energy efficiency in end-use devices, including lighting, furnaces and electric heat pumps and could lead to declines in per capita energy consumption. Additionally, certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Further, Virginia Power’s business model is premised upon the cost efficiency of the production, transmission and distribution of large-scale centralized utility generation. However, advances in distributed generation technologies, such as solar cells, gas microturbines and fuel cells, may make these alternative generation methods competitive with large-scale utility generation, and change how customers acquire or use our services. Virginia Power has an exclusive franchise to serve retail electric customers in Virginia. However, Virginia’s Retail Access Statutes allow certain Power Generation customers exceptions to this franchise. As market conditions change, Virginia Power’s customers may further pursue exceptions and Virginia Power’s exclusive franchise may erode.

Reduced energy demand or significantly slowed growth in demand due to customer adoption of energy efficient technology, conservation, distributed generation, regional economic conditions, or the impact of additional compliance obligations, unless substantially offset through regulatory cost allocations, could adversely impact the value of the Companies’ business activities.

Dominion Energy Gas has experienced a decline in demand for certain of its processing services due to competing facilities operating in nearby areas.

Dominion Energy and Dominion Energy Gas may not be able to maintain, renew or replace their existing portfolio of customer contracts successfully, or on favorable terms. Upon contract expiration, customers may not elect to re-contract with Dominion Energy and Dominion Energy Gas as a result of a variety of factors, including the amount of competition in the industry, changes in the price of natural gas, their level of satisfaction with Dominion Energy and Dominion Energy Gas’ services, the extent to which Dominion Energy and Dominion Energy Gas are able to successfully execute their business plans and the effect of the regulatory framework on customer demand. The failure to replace any such customer contracts on similar terms or with counterparties with similar credit profiles could result in a loss of revenue for Dominion Energy and Dominion Energy Gas and related decreases in their earnings and cash flows.

Certain of Dominion Energy and Dominion Energy Gas’ gas pipeline services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if the cost to perform such services exceeds the revenues received from such contracts. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or

below the FERC regulated, cost-based recourse rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue as a result of these “negotiated rate” contracts could decrease Dominion Energy and Dominion Energy Gas’ earnings and cash flows.

Dominion Energy and Dominion Energy Gas conduct certain operations through joint ventures that may limit our operational flexibility. Certain operations are conducted through joint venture arrangements, such as Atlantic Coast Pipeline and Iroquois, to which Dominion Energy and Dominion Energy Gas have significant influence but do not control the operations of such entities. The joint ventures operate in accordance with the applicable governing provisions of each entity. Accordingly, Dominion Energy and Dominion Energy Gas may have limited ability to influence or control certain day to day activities affecting the operations and do have not unilateral control over decisions that may have a material financial impact on the joint venture participants. Dominion Energy and Dominion Energy Gas are dependent upon third parties satisfying their respective obligations, including, as applicable, funding of their required share of capital expenditures. In addition, Dominion Energy and Dominion Energy Gas may be subject to restrictions or limitations on their ability to sell or transfer their interests in the joint venture arrangements. The third-party participants in the joint ventures have their own interests and objectives which may differ from those of Dominion Energy and Dominion Energy Gas. Accordingly, any disputes amongst the joint venture partners may result in delays, litigation or operational impasses.

Exposure to counterparty performance may adversely affect the Companies’ financial results of operations. The Companies are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Some of Dominion Energy’s operations are conducted through less than wholly-owned subsidiaries, as noted above. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. Defaults or failure to perform by customers, suppliers, contractors, joint venture partners, financial institutions or other third parties may adversely affect the Companies’ financial results.

Dominion Energy is exposed to counterparty credit risk relating to the terminal services agreements for the Liquefaction Project. While the counterparties’ obligations are supported by parental guarantees and letters of credit, there is no assurance that such credit support would be sufficient to satisfy the obligations in the event of a counterparty default. In addition, if a controversy arises under either agreement resulting in a judgment in Dominion Energy’s favor, Dominion Energy may need to seek to enforce a final U.S. court judgment in a foreign tribunal, which could involve a lengthy process.

Market performance and other changes may decrease the value of Dominion Energy and Virginia Power’s decommissioning trust funds and Dominion Energy and Dominion Energy Gas’ benefit plan assets or increase Dominion Energy and Dominion Energy Gas’ liabilities, which could then require significant additional funding. The performance of the capital markets affects the value of the assets that are held in trusts to

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satisfy future obligations to decommission Dominion Energy and Virginia Power’s nuclear plants and under Dominion Energy and Dominion Energy Gas’ pension and other postretirement benefit plans. The Companies have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates.

With respect to decommissioning trust funds, a decline in the market value of these assets may increase the funding requirements of the obligations to decommission Dominion Energy and Virginia Power’s nuclear plants or require additional NRC-approved funding assurance.

A decline in the market value of the assets held in trusts to satisfy future obligations under Dominion Energy and Dominion Energy Gas’ pension and other postretirement benefit plans may increase the funding requirements under such plans. Additionally, changes in interest rates will affect the liabilities under Dominion Energy and Dominion Energy Gas’ pension and other postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in mortality assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans.

If the decommissioning trust funds and benefit plan assets are negatively impacted by market fluctuations or other factors, the Companies’ results of operations, financial condition and/or cash flows could be negatively affected.

The use of derivative instruments could result in financial losses and liquidity constraints. The Companies use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity, currency and financial market risks. In addition, Dominion Energy and Dominion Energy Gas purchase and sell commodity-based contracts for hedging purposes.

The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The CEA, as amended by Title VII of the Dodd-Frank Act, requires certain over-the-counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, may elect the end-user exception to the CEA’s clearing requirements. The Companies have elected to exempt their swaps from the CEA’s clearing requirements. If, as a result of changes to the rulemaking process, the Companies’ derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs due to decreased market liquidity or increased margin payments. In addition, the Companies’ swap dealer counterparties may attempt to pass-through additional trading costs in connection with changes to or the elimination of rulemaking that implements Title VII of the Dodd-Frank Act.

Changing rating agency requirements could negatively affect the Companies’ growth and business strategy. In order to maintain appropriate credit ratings to obtain needed credit at a reasonable cost in light of existing or future rating agency requirements, the Companies may find it necessary to take steps or change their

business plans in ways that may adversely affect their growth and earnings. A reduction in the Companies’ credit ratings could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require the Companies to post additional collateral in connection with some of its price risk management activities.

An inability to access financial markets could adversely affect the execution of the Companies’ business plans. The Companies rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for business plans with increasing capital expenditure needs, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or declines in market reputation either for the Companies or their industry in general, or general financial market disruptions outside of the Companies’ control could increase their cost of borrowing or restrict their ability to access one or more financial markets. Further market disruptions could stem from delays in the current economic recovery, the bankruptcy of an unrelated company, general market disruption due to general credit market or political events, or the failure of financial institutions on which the Companies rely. Increased costs and restrictions on the Companies’ ability to access financial markets may be severe enough to affect their ability to execute their business plans as scheduled.

Potential changes in accounting practices may adversely affect the Companies’ financial results. The Companies cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or their operations specifically. New accounting standards could be issued that could change the way they record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect earnings or could increase liabilities.

War, acts and threats of terrorism, intentional acts and other significant events could adversely affect the Companies’ operations. The Companies cannot predict the impact that any future terrorist attacks may have on the energy industry in general, or on the Companies’ business in particular. Any retaliatory military strikes or sustained military campaign may affect the Companies’ operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets. In addition, the Companies’ infrastructure facilities, including projects under construction, could be direct targets of, or indirect casualties of, an act of terror. For example, there have been multiple instances of vandalism or attempted sabotage on third-party oil and gas pipelines either under construction or in operation. Furthermore, the physical compromise of the Companies’ facilities could adversely affect the Companies’ ability to manage these facilities effectively. Instability in financial markets as a result of terrorism, war, intentional acts, pandemic, credit crises, recession or other factors could result in a significant decline in the U.S. economy and increase the cost of insurance coverage. This could negatively impact the Companies’ results of operations and financial condition.

Hostile cyber intrusions could severely impair the Companies’ operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on the Companies’ business.

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The Companies own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run the Companies’ facilities are not completely isolated from external networks. There appears to be an increasing level of activity, sophistication and maturity of threat actors, in particular nation state actors, that wish to disrupt the U.S. bulk power system and the U.S. gas transmission or distribution system. Such parties could view the Companies’ computer systems, software or networks as attractive targets for cyber attack. For example, malware has been designed to target software that runs the nation’s critical infrastructure such as power transmission grids and gas pipelines. In addition, the Companies’ businesses require that they and their vendors collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

A successful cyber attack on the systems that control the Companies’ electric generation, electric or gas transmission or distribution assets could severely disrupt business operations, preventing the Companies from serving customers or collecting revenues. The breach of certain business systems could affect the Companies’ ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to the Companies’ reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data at the Companies or one of their vendors could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. While the Companies maintain property and casualty insurance, along with other contractual provisions, that may cover certain damage caused by potential cyber incidents, all damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could materially and adversely affect the Companies’ business, financial condition and results of operations.

Failure to attract and retain key executive officers and an appropriately qualified workforce could have an adverse effect on the Companies’ operations. The Companies’ business strategy is dependent on their ability to recruit, retain and motivate employees. The Companies’ key executive officers are the CEO, CFO and presidents and those responsible for financial, operational, legal, regulatory and accounting functions. Competition for skilled management employees in these areas of the Companies’ business operations is high. Certain events, such as an aging workforce, mismatch of skill set, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base and the length of time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees, or future availability and cost of contract labor may adversely affect the ability to manage and operate the Companies’ business. In addition, certain specialized knowledge is required of the Companies’ technical employees for construction and oper-

ation of transmission, generation and distribution assets. The Companies’ inability to attract and retain these employees could adversely affect their business and future operating results.

Following the SCANA Combination, Dominion Energy may be unable to successfully integrate SCANA’s businesses. Dominion Energy is devoting significant management attention and resources to integrating SCANA’s businesses. While Dominion Energy has assumed that a certain level of transaction and integration expenses will be incurred, there are a number of factors beyond its control that could affect the total amount or the timing of its integration expenses. Potential difficulties Dominion Energy may encounter in the integration process include the following:

• The complexities associated with integrating SCANA, including its utility businesses, while at the same time continuing to provide consistent, high quality services;

• The complexities of integrating a company with different markets and customers;

• The inability to attract and retain key employees;

• Potential unknown liabilities and unforeseen increased expenses associated with the SCANA Combination;

• Difficulties in managing political and regulatory conditions related to SCANA’s utility businesses;

• The moratorium on filing requests for adjustments in SCE&G’s base electric rates until May 2020 with no changes in rates until January 1, 2021, which limits Dominion Energy’s ability to recover increases in non-fuel related costs of electric operations for SCE&G’s customers;

• The stipulation agreement approved by the North Carolina Commission, which provides for a rate moratorium at PSNC until November 1, 2021, with certain exceptions; and

• Performance shortfalls as a result of the diversion of Dominion Energy management’s attention caused by integrating SCANA’s businesses.

For these reasons, it is possible that the integration process could result in the distraction of Dominion Energy’s management, the disruption of Dominion Energy’s ongoing business or inconsistencies in its services, standards, controls, procedures and policies, any of which could adversely affect the ability of Dominion Energy to maintain or establish relationships with current and prospective customers, vendors and employees or could otherwise adversely affect the business and financial results of Dominion Energy.

Dominion Energy may be materially adversely affected by negative publicity related to the SCANA Combination and in connection with other related matters, including the abandonment of the NND Project. From time to time, political and public sentiment in connection with the merger and in connection with other matters, including the abandonment of the NND Project, may result in a significant amount of adverse press coverage and other adverse public statements affecting Dominion Energy. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims. Responding to these investigations and lawsuits, regardless of the ultimate outcome of the proceedings, as well as responding to and addressing adverse press coverage and other adverse public statements, can divert the time and effort of senior management from the management of Dominion Energy’s business.

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Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on the reputation of Dominion Energy, on the morale and performance of their employees and on their relationships with their respective regulators, customers and commercial counterparties. It may also have a negative impact on their ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on Dominion Energy’s business, financial condition and results of operations.

The SCANA Combination may not be accretive to operating earnings and may cause dilution to Dominion Energy’s earnings per share, which may negatively affect the market price of Dominion Energy common stock. Dominion Energy currently anticipates that the SCANA Combination will be immediately accretive to Dominion Energy’s forecasted operating earnings per share on a standalone basis. This expectation is based on preliminary estimates, which may materially change. Dominion Energy may encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates or its ability to realize operational efficiencies. Any of these factors could cause a decrease in Dominion Energy’s operating earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of Dominion Energy’s common stock. Dominion Energy expects the initial effect of the SCANA Combination on its GAAP earnings will be a decrease in such earnings due to the anticipated charges for refunds to SCE&G customers and transaction and transition costs.

Through the SCANA Combination, Dominion Energy acquired SCANA and SCE&G which are subject to numerous legal proceedings and ongoing governmental investigations and examinations. SCANA and SCE&G are defendants in numerous federal and state legal proceedings and governmental investigations relating to the decision to abandon construction at the

NND Project. Among other things, the lawsuits and investigations allege misrepresentation, failure to properly manage the NND Project, unfair trade practices and violation of anti-trust laws. The plaintiffs seek a judgment that SCE&G may not charge its customers for any past or continuing costs of the NND Project, among other remedies.

Additionally, SCANA and SCE&G are defendants in federal and state legal proceedings relating to the SCANA Combination. Among other things, the lawsuits allege breaches of various fiduciary duties. Remedies sought include rescinding the SCANA Combination.

The outcome of these legal proceedings, investigations and examinations is uncertain and may adversely affect Dominion Energy’s financial condition or results of operation.

Dominion Energy has goodwill and other intangible assets on its balance sheet, and these amounts will increase as a result of the SCANA Combination. If its goodwill or other intangible assets become impaired in the future, Dominion Energy may be required to record a significant, non-cash charge to earnings and reduce its shareholders’ equity. Dominion Energy will record as goodwill the excess of the purchase price paid by Dominion Energy over the fair value of SCANA’s assets and liabilities as determined for financial accounting purposes in its Consolidated Balance Sheet beginning in the first quarter of 2019. Under GAAP, intangible assets are reviewed for impairment on an annual basis or more frequently whenever events or circumstances indicate that its carrying value may not be recoverable. If Dominion Energy’s intangible assets, including goodwill as a result of the SCANA Combination, are determined to be impaired in the future, Dominion Energy may be required to record a significant, non-cash charge to earnings during the period in which the impairment is determined.

Item 1B. Unresolved Staff Comments

None.

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Item 2. Properties

As of December 31, 2018, Dominion Energy owned its principal executive office in Richmond, Virginia and five other corporate offices. Dominion Energy also leases corporate offices in other cities in which its subsidiaries operate. Virginia Power and Dominion Energy Gas share Dominion Energy’s principal office in Richmond, Virginia, which is owned by Dominion Energy. In addition, Virginia Power’s Power Delivery and Power Generation segments share certain leased buildings and equipment.

Dominion Energy’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described below.

Certain of Virginia Power’s properties are subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding as of December 31, 2018; however, by leaving the indenture open, Virginia Power expects to retain the flexibility to issue mortgage bonds in the future. Certain of Dominion Energy’s merchant generation facilities are also subject to liens. Additionally, SCE&G’s bond indenture, which secures its First Mortgage Bonds, constitutes a direct mortgage lien on substantially all of its electric utility property. GENCO’s Williams Station is also subject to a first mortgage lien which secures certain outstanding debt of GENCO.

POWER DELIVERY

Virginia Power has approximately 6,700 miles of electric transmission lines of 69 kV or more located in North Carolina, Virginia and West Virginia. Portions of Virginia Power’s electric transmission lines cross national parks and forests under permits

entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.

In addition, Virginia Power’s electric distribution network includes approximately 58,300 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, Virginia Power owns 475 substations.

POWER GENERATION

Dominion Energy and Virginia Power generate electricity for sale on a wholesale and a retail level. Dominion Energy and Virginia Power supply electricity demand either from their generation facilities or through purchased power contracts. As of December 31, 2018, Power Generation’s total utility, non-jurisdictional and merchant generating capacity was approximately 26,000 MW. The following tables list Power Generation’s utility, non-jurisdictional and merchant generating units and capability, as of December 31, 2018.

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VIRGINIA POWER UTILITY GENERATION

Plant	Location		Net Summer Capability (MW)			Percentage Net Summer Capability
Gas
Greensville County (CC)		Greensville County, VA		1,588
Brunswick County (CC)		Brunswick County, VA		1,376
Warren County (CC)		Warren County, VA		1,370
Ladysmith (CT)		Ladysmith, VA		783
Bear Garden (CC)		Buckingham County, VA		622
Remington (CT)		Remington, VA		622
Possum Point (CC)		Dumfries, VA		573
Chesterfield (CC)		Chester, VA		397
Elizabeth River (CT)		Chesapeake, VA		330
Possum Point(1)		Dumfries, VA		316
Bellemeade (CC)(1)		Richmond, VA		267
Bremo(1)		Bremo Bluff, VA		227
Gordonsville Energy (CC)		Gordonsville, VA		218
Gravel Neck (CT)		Surry, VA		170
Darbytown (CT)		Richmond, VA		168
Rosemary (CC)		Roanoke Rapids, NC		160
Total Gas				9,187			41	%
Coal
Mt. Storm		Mt. Storm, WV		1,621
Chesterfield(1)		Chester, VA		1,275
Virginia City Hybrid Energy Center		Wise County, VA		610
Clover		Clover, VA		439	(3)
Yorktown(2)		Yorktown, VA		323
Mecklenburg(1)		Clarksville, VA		138
Total Coal				4,406			20
Nuclear
Surry		Surry, VA		1,676
North Anna		Mineral, VA		1,672	(4)
Total Nuclear				3,348			15
Oil
Yorktown		Yorktown, VA		790
Possum Point		Dumfries, VA		770
Gravel Neck (CT)		Surry, VA		198
Darbytown (CT)		Richmond, VA		168
Possum Point (CT)		Dumfries, VA		72
Chesapeake (CT)		Chesapeake, VA		51
Low Moor (CT)		Covington, VA		48
Northern Neck (CT)		Lively, VA		47
Total Oil				2,144			10
Hydro
Bath County		Warm Springs, VA		1,808	(5)
Gaston		Roanoke Rapids, NC		220
Roanoke Rapids		Roanoke Rapids, NC		95
Other				1
Total Hydro				2,124			9
Biomass
Pittsylvania(1)		Hurt, VA		83
Altavista		Altavista, VA		51
Polyester		Hopewell, VA		51
Southampton		Southampton, VA		51
Total Biomass				236			1
Solar
Whitehouse Solar		Louisa County, VA		20
Woodland Solar		Isle of Wight County, VA		19
Scott Solar		Powhatan County, VA		17
Total Solar				56			—
Various
Mt. Storm (CT)		Mt. Storm, WV		11			—
				21,512
Power Purchase Agreements				930			4
Total Utility Generation				22,442			100	%

Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.

(1) Virginia Power has placed certain units at this facility in cold storage.

(2) Coal-fired units are expected to be retired at Yorktown power station as early as 2019 as a result of the issuance of MATS.

(3) Excludes 50% undivided interest owned by ODEC.

(4) Excludes 11.6% undivided interest owned by ODEC.

(5) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of FirstEnergy Corp.

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VIRGINIA POWER NON-JURISDICTIONAL GENERATION

Plant	Location	Net Summer Capability (MW)
Solar(1)
Pecan	Pleasant Hill, NC		75
Montross	Montross, VA		20
Morgans Corner	Pasquotank County, NC		20
Remington	Remington, VA		20
Oceana	Virginia Beach, VA		18
Hollyfield	Manquin, VA		17
Puller	Topping, VA		15
Total Solar			185

(1) All solar facilities are alternating current.

DOMINION ENERGY MERCHANT GENERATION

Plant	Location		Net Summer Capability (MW)			Percentage Net Summer Capability
Nuclear
Millstone		Waterford, CT		2,001	(1)
Total Nuclear				2,001			59	%
Solar(2)
Escalante I, II and III		Beaver County, UT		120	(3)
Amazon Solar Farm Virginia—Southampton		Newsoms, VA		100	(5)
Amazon Solar Farm Virginia—Accomack		Oak Hall, VA		80	(5)
Innovative Solar 37		Morven, NC		79	(5)
Moffett Solar 1		Ridgeland, SC		71	(5)
Granite Mountain East and West		Iron County, UT		65	(3)
Summit Farms Solar		Moyock, NC		60	(5)
Enterprise		Iron County, UT		40	(3)
Iron Springs		Iron County, UT		40	(3)
Pavant Solar		Holden, UT		34	(4)
Camelot Solar		Mojave, CA		30	(4)
Midway II		Calipatria, CA		30	(5)
Indy I, II and III		Indianapolis, IN		20	(4)
Amazon Solar Farm Virginia—Buckingham		Cumberland, VA		20	(5)
Amazon Solar Farm Virginia—Correctional		Barhamsville, VA		20	(5)
Hecate Cherrydale		Cape Charles, VA		20	(5)
Amazon Solar Farm Virginia—Sappony		Stoney Creek, VA		20	(5)
Amazon Solar Farm Virginia—Scott II		Powhatan, VA		20	(5)
Cottonwood Solar		Kings and Kern counties, CA		16	(4)
Alamo Solar		San Bernardino, CA		13	(4)
Maricopa West Solar		Kern County, CA		13	(4)
Imperial Valley Solar		Imperial, CA		13	(4)
Richland Solar		Jeffersonville, GA		13	(4)
CID Solar		Corcoran, CA		13	(4)
Kansas Solar		Lenmore, CA		13	(4)
Kent South Solar		Lenmore, CA		13	(4)
Old River One Solar		Bakersfield, CA		13	(4)
West Antelope Solar		Lancaster, CA		13	(4)
Adams East Solar		Tranquility, CA		13	(4)
Catalina 2 Solar		Kern County, CA		12	(4)
Mulberry Solar		Selmer, TN		11	(4)
Selmer Solar		Selmer, TN		11	(4)
Columbia 2 Solar		Mojave, CA		10	(4)
Hecate Energy Clarke County		White Post, VA		10	(5)
Ridgeland Solar Farm I		Ridgeland, SC		10	(5)
Other		Various		43	(4)(5)
Total Solar				1,122			33
Wind
Fowler Ridge(6)		Benton County, IN		150	(7)
NedPower(6)		Grant County, WV		132	(8)
Total Wind				282			8
Fuel Cell
Bridgeport Fuel Cell		Bridgeport, CT		15
Total Fuel Cell				15			—
Total Merchant Generation				3,420			100	%

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(1) Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain.

(2) All solar facilities are alternating current.

(3) Excludes 50% noncontrolling interest owned by GIP. Dominion Energy’s interest is subject to a lien securing Dominion Solar Projects III, Inc.’s debt.

(4) Excludes 33% noncontrolling interest owned by Terra Nova Renewable Partners. Dominion Energy’s interest is subject to a lien securing SBL Holdco’s debt.

(5) Dominion Energy’s interest is subject to a lien securing Eagle Solar’s debt.

(6) Subject to a lien securing the facility’s debt.

(7) Excludes 50% membership interest owned by BP.

(8) Excludes 50% membership interest owned by Shell.

GAS INFRASTRUCTURE

Dominion Energy and Dominion Energy Gas

East Ohio’s gas distribution network is located in Ohio. This network involves approximately 18,900 miles of pipe, exclusive of service lines. The right-of-way grants for many natural gas pipelines have been obtained from the actual owners of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.

Dominion Energy Gas has approximately 10,800 miles, excluding interests held by others, of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy Gas also owns NGL processing plants capable of processing over 270,000 mcf per day of natural gas. Hastings is the largest plant and is capable of processing over 180,000 mcf per day of natural gas. Hastings can also fractionate over 580,000 Gals per day of NGLs into marketable products, including propane, isobutane, butane and natural gasoline. NGL operations have storage capacity of 1,340,000 Gals of propane, 118,000 Gals of isobutane, 242,000 Gals of butane, 2,000,000 Gals of natural gasoline and 1,012,500 Gals of mixed NGLs. Dominion Energy Gas also operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with approximately 2,000 storage wells and approximately 399,000 acres of operated leaseholds.

The total designed capacity of the underground storage fields operated by Dominion Energy Gas is approximately 926 bcf. Certain storage fields are jointly-owned and operated by Dominion Energy Gas. The capacity of those fields owned by Dominion Energy Gas’ partners totals approximately 223 bcf.

Dominion Energy

Cove Point’s LNG Facility has an operational peak regasification daily send-out capacity of approximately 1.8 million Dths and an aggregate LNG storage capacity of approximately 14.6 bcfe. In addition, Cove Point has a liquefier that has the potential to create approximately 15,000 Dths/day. The Liquefaction Project consists of one LNG train with a nameplate outlet capacity of 5.25 Mtpa. Cove Point has authorization from the DOE to export up to 0.77 Bcfe/day (approximately 5.75 Mtpa) should the liquefaction facilities perform better than expected.

The Cove Point Pipeline is a 36-inch diameter underground, interstate natural gas pipeline that extends approximately 88 miles

from Cove Point to interconnections with Transco in Fairfax County, Virginia, and with Columbia Gas Transmission, LLC and DETI in Loudoun County, Virginia. In 2009, the original pipeline was expanded to include a 36-inch diameter expansion that extends approximately 48 miles, roughly 75% of which is parallel to the original pipeline.

Dominion Energy Questar Pipeline operates 2,200 miles of natural gas transportation pipelines that interconnect with other pipelines in Utah, Wyoming and western Colorado. Dominion Energy Questar Pipeline’s system ranges in diameter from lines that are less than four inches to 36-inches. Dominion Energy Questar Pipeline owns the Clay Basin storage facility in northeastern Utah, which has a certificated capacity of 120 bcf, including 54 bcf of working gas.

DECG’s interstate natural gas pipeline system in South Carolina and southeastern Georgia is comprised of nearly 1,500 miles of transmission pipeline.

Questar Gas owns and operates distribution systems in Utah, Wyoming and Idaho with a total of 30,100 miles of street mains, service lines and interconnecting pipelines.

Hope’s gas distribution network located in West Virginia is comprised of 3,200 miles of pipe, exclusive of service lines.

In total, Dominion Energy has 172 compressor stations with approximately 1,340,000 installed compressor horsepower.

SOUTHEAST ENERGY

SCE&G has approximately 3,500 miles and 26,500 miles of electric transmission and distribution lines, respectively, exclusive of service level lines, in South Carolina. The grants for most of SCE&G’s electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying property titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, SCE&G owns 440 substations.

SCE&G and PSNC’s natural gas system includes approximately 1,100 miles of transmission pipeline of up to 24 inches in diameter that connect their distribution systems with Southern Natural Gas Company, Transco and DECG. SCE&G and PSNC’s natural gas distribution system consists of approximately 40,600 miles of distribution mains and related service facilities.

SCE&G owns two LNG facilities, one located near Charleston, South Carolina, and the other in Salley, South Carolina. The Charleston facility can store the liquefied equivalent of 1.0 bcf of natural gas, can regasify approximately 6% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day. The Salley facility can store the liquefied equivalent of 0.9 bcf of natural gas and can regasify approximately 10% of its storage capacity per day. The Salley facility has no liquefying capabilities.

PSNC owns one LNG facility that stores the liquefied equivalent of 1.0 bcf of natural gas, can regasify approximately 10% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day.

To meet the requirements of their high priority natural gas customers during periods of maximum demand, SCE&G and

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PSNC have contracted for approximately 6 bcf of natural gas storage capacity on the systems of Southern Natural Gas Company and Transco.

Dominion Energy acquired through the SCANA Combination total utility generating capacity of approximately 6,000 MW, as detailed in the following table:

Plant	Location	Net Summer Capability (MW)			Percentage Net Summer Capability
Gas
Jasper (CC)	Hardeeville, SC		852	(1)
Columbia Energy Center (CC)	Gaston, SC		504	(1)
Urquhart (CC)	Beech Island, SC		458	(1)
McMeekin	Irmo, SC		250
Hagood (CT)	Charleston, SC		126	(1)
Urquhart Unit 3	Beech Island, SC		95
Urquhart (CT)	Beech Island, SC		87
Parr (CT)	Jenkinsville, SC		60	(1)
Williams (CT)	Goose Creek, SC		40	(1)
Coit (CT)	Columbia, SC		26	(1)
Hardeeville (CT)	Hardeeville, SC		9
Total Gas			2,507			42	%
Coal
Wateree	Eastover, SC		684
Williams	Goose Creek, SC		605
Cope	Cope, SC		415	(2)
Total Coal			1,704			28
Hydro
Fairfield	Jenkinsville, SC		576
Saluda	Irmo, SC		198
Other	Various		18
Total Hydro			792			13
Nuclear
Summer(1)	Jenkinsville, SC		647	(3)
Total Nuclear			647			11
Power Purchase Agreements			335			6
Total Utility Generation			5,985			100	%

Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.

(1) Capable of burning fuel oil as a secondary source.

(2) Capable of burning natural gas as a secondary source.

(3) Excludes 33.3% undivided interest owned by Santee Cooper.

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Item 3. 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 Notes 13 and 22 to the Consolidated Financial Statements and Future Issues and Other Matters in Item 7. MD&A, which information is incorporated herein by reference, for discussion of various legal, environmental and other regulatory proceedings to which the Companies are a party. See also Note 3 to the Consolidated Financial Statements, which information is incorporated herein by reference, for a discussion of various legal proceedings to which SCANA and SCE&G were a party to at the closing of the SCANA Combination.

Item 4. Mine Safety Disclosures

Not applicable.

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Executive Officers of Dominion Energy

Information concerning the executive officers of Dominion Energy, each of whom is elected annually, is as follows:

Name and Age	Business Experience Past Five Years(1)
Thomas F. Farrell, II (64)	Chairman of the Board of Directors, President and CEO of Dominion Energy from April 2007 to date.
Robert M. Blue (51)	Executive Vice President and President & CEO—Power Delivery from May 2017 to date; Senior Vice President and President & CEO—Power Delivery from January 2017 to May 2017; Senior Vice President—Law, Regulation & Policy from February 2016 to December 2016; Senior Vice President—Regulation, Law, Energy Solutions and Policy from May 2015 to January 2016; President of Virginia Power from January 2014 to May 2015.
James R. Chapman (49)	Executive Vice President, Chief Financial Officer and Treasurer from January 2019 to date; Senior Vice President, Chief Financial Officer and Treasurer from November 2018 to December 2018; Senior Vice President—Mergers & Acquisitions and Treasurer from February 2016 to October 2018; Vice President—Corporate Finance and Mergers & Acquisitions and Assistant Treasurer from May 2015 to January 2016; Vice President—Corporate Finance and Mergers & Acquisitions from January 2015 to May 2015; Assistant Treasurer from October 2013 to December 2014.
Paul D. Koonce (59)	Executive Vice President and President & CEO—Power Generation from January 2017 to date; Executive Vice President and CEO—Power Generation from January 2016 to December 2016; Executive Vice President and CEO—Gas Infrastructure from February 2013 to December 2015.
Diane Leopold (52)	Executive Vice President and President & CEO—Gas Infrastructure from May 2017 to date; Senior Vice President and President & CEO—Gas Infrastructure from January 2017 to May 2017; President of DETI, East Ohio and Dominion Cove Point, Inc. from January 2014 to date.
P. Rodney Blevins (54)	President & Chief Executive Officer—Southeast Energy from January 2019 to date; Senior Vice President and Chief Information Officer from January 2014 to December 2018.
Carlos M. Brown (44)	Senior Vice President and General Counsel from January 2019 to date; Vice President and General Counsel from January 2017 to December 2018; Deputy General Counsel—Litigation, Labor, and Employment of DES from July 2016 to December 2016; Director—Power Generation Station II of DES from July 2015 to June 2016; Director—Alternative Energy Solutions Business Development & Commercialization of DES from January 2013 to June 2015.
William L. Murray (51)	Senior Vice President—Corporate Affairs & Communications from February 2019 to date; Vice President—State & Electric Public Policy of DES from May 2017 to January 2019; Senior Policy Director—Public Policy of DES from April 2016 to May 2017; Managing Director—Corporate Public Policy of DES from June 2007 to March 2016.
Michele L. Cardiff (51)	Vice President, Controller and CAO from April 2014 to date; Vice President—Accounting of DES from January 2014 to March 2014.

(1) All positions held at Dominion Energy, unless otherwise noted. Any service listed for Virginia Power, DETI, East Ohio, Dominion Cove Point, Inc., and DES reflects service at a subsidiary of Dominion Energy.

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Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Dominion Energy

Dominion Energy’s common stock is listed on the NYSE under the ticker symbol D. At February 15, 2019, there were approximately 137,000 record holders of Dominion Energy’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion Energy’s transfer agent records and includes accounts with shares held in (1) certificate form, (2) book-entry in the Direct Registration System and (3) book-entry under Dominion Energy Direct^®. Discussions of expected dividend payments required by this Item are contained in Liquidity and Capital Resources in Item 7. MD&A.

The following table presents certain information with respect to Dominion Energy’s common stock repurchases during the fourth quarter of 2018:

DOMINION ENERGY 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)
10/1/18-10/31/18		27,800	$	70.10		—	19,629,059 shares/$1.18 billion
11/1/18-11/30/18		3,630		70.33		—	19,629,059 shares/$1.18 billion
12/1/18-12/31/18		1,494		74.58		—	19,629,059 shares/$1.18 billion
Total		32,924	$	70.33		—	19,629,059 shares/$1.18 billion

(1) 27,800, 3,630 and 1,494 shares were tendered by employees to satisfy tax withholding obligations on vested restricted stock in October, November and December 2018, respectively.

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

(3) The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Energy Board of Directors in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion Energy 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.

Virginia Power

There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion Energy. Virginia Power intends to pay quarterly cash dividends in 2019 but is neither required to nor restricted, except as described in Note 20 to the Consolidated Financial Statements, from making such payments.

Dominion Energy Gas

All of Dominion Energy Gas’ membership interests are owned by Dominion Energy. Dominion Energy Gas intends to pay quarterly cash dividends in 2019 but is neither required to nor restricted, except as described in Note 20 to the Consolidated Financial Statements, from making such payments.

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Item 6. Selected Financial Data

The following table should be read in conjunction with the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.

Beginning in 2019, Dominion Energy’s result of operations will include the results of operations of SCANA. Additionally, in connection with the SCANA Combination, SCE&G will provide refunds and restitution of $2.0 billion over 20 years with capital support from Dominion Energy as well as exclude from rate recovery $2.4 billion of costs related to the NND Project and $180 million of costs associated with the purchase of the Columbia Energy Center power station. See Note 3 to the Consolidated Financial Statements for further information including charges expected to be recognized in the first quarter of 2019.

DOMINION ENERGY

Year Ended December 31,	2018(1)		2017(2)		2016(3)		2015		2014(4)
(millions, except per share amounts)
Operating revenue	$	13,366	$	12,586	$	11,737	$	11,683	$	12,436
Net income attributable to Dominion Energy		2,447		2,999		2,123		1,899		1,310
Net income attributable to Dominion Energy per common share-basic		3.74		4.72		3.44		3.21		2.25
Net income attributable to Dominion Energy per common share-diluted		3.74		4.72		3.44		3.20		2.24
Dividends declared per common share		3.340		3.035		2.80		2.59		2.40
Total assets		77,914		76,585		71,610		58,648		54,186
Long-term debt(5)		31,144		30,948		30,231		23,468		21,665

(1) Includes $568 million after-tax gains on sales of certain merchant generation facilities and equity method investments partially offset by $164 million after-tax charge related to the impairment of certain gathering and processing assets and a $160 million after-tax charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers.

(2) Includes $851 million of tax benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate, partially offset by $96 million of after-tax charges associated with equity method investments in wind-powered generation facilities.

(3) Includes a $122 million after-tax charge related to future ash pond and landfill closure costs at certain utility generation facilities.

(4) Includes $248 million of after-tax charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, a $193 million after-tax charge related to Dominion Energy’s restructuring of its producer services business and a $174 million after-tax charge associated with the Liability Management Exercise.

(5) Includes capital leases.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

MD&A discusses Dominion Energy’s results of operations and general financial condition and Virginia Power and Dominion Energy Gas’ results of operations. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. Virginia Power and Dominion Energy 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 Energy

• Dominion Energy

• Results of Operations

• Segment Results of Operations

• Virginia Power

• Results of Operations

• Dominion Energy Gas

• Results of Operations

• Liquidity and Capital Resources—Dominion Energy

• Future Issues and Other Matters—Dominion Energy

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, but not limited to, 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 substances, 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 or related appeals;

• 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 Energy and Dominion Energy 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 Energy and Virginia Power and in benefit plan trusts by Dominion Energy and Dominion Energy Gas;

• Fluctuations in interest rates or foreign currency exchange rates;

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

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

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

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

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

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

• Changes in rules for RTOs and ISOs in which Dominion Energy 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 Energy and Dominion Energy 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

47

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

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 Energy’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers;

• Competition in the development, construction and ownership of certain electric transmission facilities in Dominion Energy and Virginia Power’s service territories in connection with 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 Dominion Energy and Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion Energy and Dominion Energy Gas;

• Changes in operating, maintenance and construction costs;

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

• The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement or intervention in such projects;

• Adverse outcomes in litigation matters or regulatory proceedings, including matters acquired in the SCANA Combination; 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.

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

Dominion Energy has identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or using different assumptions. Dominion Energy has discussed the development, selection

and disclosure of each of these policies with the Audit Committee of its Board of Directors.

ACCOUNTING FOR REGULATED OPERATIONS

The accounting for Dominion Energy’s regulated electric and gas operations differs from the accounting for nonregulated operations in that Dominion Energy is required to reflect the effect of rate regulation in its Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.

Dominion Energy evaluates whether or not recovery of its regulatory assets through future rates is probable and makes various assumptions in its analysis. The expectations of future recovery are generally based on orders issued by regulatory commissions, legislation or historical experience, as well as discussions with applicable regulatory authorities and legal counsel. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. See Notes 12 and 13 to the Consolidated Financial Statements for additional information.

ASSET RETIREMENT OBLIGATIONS

Dominion Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists and the ARO can be reasonably estimated. These AROs are recognized at fair value as incurred or when sufficient information becomes available to determine fair value and are generally capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Dominion Energy estimates the fair value of its AROs using present value techniques, in which it makes various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. The impact on measurements of new AROs or remeasurements of existing AROs, using different cost escalation or credit-adjusted risk free rates in the future, may be significant. When Dominion Energy revises any assumptions used to calculate the fair value of existing AROs, it adjusts the carrying amount of both the ARO liability and the related long-lived asset for assets that are in service; for assets that have ceased operations, Dominion Energy adjusts the carrying amount of the ARO liability with such changes recognized in income. Dominion Energy accretes the ARO liability to reflect the passage of time. In 2018, Dominion Energy recorded an increase in AROs of $140 million primarily related to future ash pond and landfill closure costs at certain generation facilities. See Note 22 to the Consolidated Financial Statements for additional information.

48

In 2018, 2017 and 2016, Dominion Energy recognized $119 million, $117 million and $104 million, respectively, of accretion, and expects to recognize approximately $145 million in 2019. Dominion Energy records accretion and depreciation associated with utility nuclear decommissioning AROs and regulated pipeline replacement AROs as an adjustment to the regulatory liabilities related to these items.

A significant portion of Dominion Energy’s AROs relates to the future decommissioning of its merchant and utility nuclear facilities. These nuclear decommissioning AROs are reported in the Power Generation segment. Subsequent to the SCANA Combination, SCANA’s nuclear decommissioning AROs will be reported in the Southeast Energy segment. At December 31, 2018, Dominion Energy’s nuclear decommissioning AROs totaled $1.6 billion, representing approximately 62% of its total AROs. Subsequent to the SCANA Combination, Dominion Energy’s nuclear decommissioning AROs will total approximately $1.8 billion, representing approximately 55% of its total AROs. Based on their significance, the following discussion of critical assumptions inherent in determining the fair value of AROs relates to those associated with Dominion Energy’s nuclear decommissioning obligations.

Dominion Energy obtains from third-party specialists periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for its nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. In addition, Dominion Energy’s cost estimates include cost escalation rates that are applied to the base year costs. Dominion Energy determines cost escalation rates, which represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities, for each nuclear facility. The selection of these cost escalation rates is dependent on subjective factors which are considered to be critical assumptions.

INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws, including the provisions of the 2017 Tax Reform Act, involves uncertainty, since tax authorities may interpret the laws differently. In addition, the states in which the Companies operate may or may not conform to some or all the provisions in the 2017 Tax Reform Act. Ultimate resolution or clarification of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2018, Dominion Energy had

$44 million of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.

Deferred income tax assets and liabilities are recorded representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion Energy evaluates quarterly the probability of realizing deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. Dominion Energy establishes a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2018, Dominion Energy had established $158 million of valuation allowances.

The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies, including changes in corporate tax rates and business deductions. Many of these provisions differ significantly from prior U.S. tax law, resulting in pervasive financial reporting implications for the Companies. The 2017 Tax Reform Act included significant changes to the Internal Revenue Code of 1986, including amendments which significantly change the taxation of individuals and business entities and included specific provisions related to regulated public utilities including Dominion Energy subsidiaries Questar Gas, Hope, and SCE&G and PSNC, following the SCANA Combination, Virginia Power and Dominion Energy Gas’ subsidiaries DETI and East Ohio. The more significant changes that impact the Companies included in the 2017 Tax Reform Act are (i) reducing the corporate federal income tax rate from 35% to 21%; (ii) effective in 2018, limiting the deductibility of interest expense to 30% of adjusted taxable income for certain businesses with any disallowed interest allowed to be carried forward indefinitely; (iii) permitting 100% expensing (100% bonus depreciation) for certain qualified property; (iv) eliminating the deduction for qualified domestic production activities; and (v) limiting the utilization of net operating losses arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward. The specific provisions related to regulated public utilities in the 2017 Tax Reform Act generally allow for the continued deductibility of interest expense, the exclusion from full expensing for tax purposes of certain property acquired and placed in service after September 27, 2017 and continued certain rate normalization requirements for accelerated depreciation benefits.

At the date of enactment, the Companies’ deferred taxes were remeasured based upon the new tax rate expected to apply when temporary differences are realized or settled. For regulated operations, many of the changes in deferred taxes represented amounts probable of collection from or refund to customers, and were recorded as either an increase to a regulatory asset or liability. The 2017 Tax Reform Act included provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred taxes will be determined by the Companies’ regulators. For nonregulated operations, the changes in deferred taxes were recorded as an adjustment to deferred tax expense.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

ACCOUNTING FOR DERIVATIVE CONTRACTS AND FINANCIAL INSTRUMENTS AT FAIR VALUE

Dominion Energy uses derivative contracts such as physical and financial forwards, futures, swaps, options and FTRs to manage commodity, interest rate and foreign currency exchange rate risks of its business operations. Derivative contracts, with certain exceptions, are reported in the Consolidated Balance Sheets at fair value. The majority of investments held in Dominion Energy’s nuclear decommissioning and rabbi trusts and pension and other postretirement funds are also subject to fair value accounting. See Notes 6 and 21 to the Consolidated Financial Statements for further information on these fair value measurements.

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, management seeks indicative price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, Dominion Energy considers whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if Dominion Energy believes that observable pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases, Dominion Energy must estimate prices based on available historical and near-term future price information and use of statistical methods, including regression analysis, that reflect its market assumptions.

Dominion Energy maximizes the use of observable inputs and minimizes the use of unobservable inputs when measuring fair value.

USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING

As of December 31, 2018, Dominion Energy reported $6.4 billion of goodwill in its Consolidated Balance Sheet. A significant portion resulted from the acquisition of the former CNG in 2000 and the Dominion Energy Questar Combination in 2016. As discussed in Note 3 to the Consolidated Financial Statements, Dominion Energy expects to reflect a significant amount of goodwill in connection with the SCANA Combination in its Consolidated Balance Sheet in the first quarter of 2019.

In April of each year, Dominion Energy tests its goodwill for potential impairment, and performs additional tests more frequently if an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 2018, 2017 and 2016 annual tests and any interim tests did not result in the recognition of any goodwill impairment.

In general, Dominion Energy estimates the fair value of its reporting units by using a combination of discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. Fair value estimates are dependent on subjective factors such as Dominion Energy’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, partic-

ularly changes in discount rates or growth rates inherent in Dominion Energy’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion Energy has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent tests had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present.

See Note 11 to the Consolidated Financial Statements for additional information.

USE OF ESTIMATES IN LONG-LIVED ASSET AND EQUITY METHOD INVESTMENT IMPAIRMENT TESTING

Impairment testing for an individual or group of long-lived assets, including intangible assets with definite lives, and equity method investments is required when circumstances indicate those assets may be impaired. When a long-lived asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. When an equity method investment’s carrying amount exceeds its fair value, and the decline in value is deemed to be other-than-temporary, an impairment is recognized to the extent that the fair value is less than its carrying amount. Performing an impairment test on long-lived assets and equity method investments involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets in the case of long-lived assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of a market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about the operations of the long-lived assets and equity method investments and the selection of an appropriate discount rate. When determining whether a long-lived asset or asset group has been impaired, management groups assets at the lowest level that has identifiable cash flows. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset or underlying assets of equity method investees, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. See Notes 6 and 9 to the Consolidated Financial Statements for a discussion of impairments related to certain long-lived assets and equity method investments.

As discussed in Future Issues and Other Matters, delays in obtaining permits necessary for construction and construction delays due to judicial actions have impacted the estimated cost and schedule for the Atlantic Coast Pipeline Project. As a result, Dominion Energy evaluated the carrying amount of its equity

50

method investment in Atlantic Coast Pipeline for an other-than-temporary impairment and determined that it was not impaired. Any significant changes affecting the discounted cash flow estimates associated with the Atlantic Coast Pipeline Project, such as future unfavorable judicial actions resulting in further construction and in-service delays along with an increase in construction costs, could result in an impairment charge.

EMPLOYEE BENEFIT PLANS

Dominion Energy sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate of return on plan assets, discount rates applied to benefit obligations, mortality rates and the anticipated rate of increase in healthcare costs and participant compensation, also have a significant impact on employee benefit costs. The impact of changes in these factors, as well as differences between Dominion Energy’s assumptions and actual experience, is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants, rather than immediately.

The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality rates are critical assumptions. Dominion Energy determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:

• Expected inflation and risk-free interest rate assumptions;

• Historical return analysis to determine long-term historic returns as well as historic risk premiums for various asset classes;

• Expected future risk premiums, asset classes’ volatilities and correlations;

• Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and

• Investment allocation of plan assets. The strategic target asset allocation for Dominion Energy’s pension funds is 28% U.S. equity, 18% non-U.S. equity, 35% fixed income, 3% real estate and 16% other alternative investments, such as private equity investments.

Strategic investment policies are established for Dominion Energy’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include those mentioned above such as employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion Energy’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the targets. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns.

Dominion Energy develops non-investment related assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions. Dominion Energy calculated its pension cost using an expected long-term rate of return on plan assets assumption of 8.75% for 2018, 2017 and 2016. For 2019, the expected long-term rate of return for pension cost assumption is 8.65% for Dominion Energy’s plans held as of December 31, 2018. Dominion Energy calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.50% for 2018, 2017 and 2016. For 2019, the expected long-term rate of return for other postretirement benefit cost assumption is 8.50%. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets.

Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost ranged from 3.80% to 3.81% for pension plans and 3.76% for other postretirement benefit plans in 2018, ranged from 3.31% to 4.50% for pension plans and 3.92% to 4.47% for other postretirement benefit plans in 2017 and ranged from 2.87% to 4.99% for pension plans and 3.56% to 4.94% for other postretirement benefit plans in 2016. Dominion Energy selected a discount rate ranging from 4.42% to 4.43% for pension plans and 4.37% to 4.38% for other postretirement benefit plans for determining its December 31, 2018 projected benefit obligations.

Dominion Energy establishes the healthcare cost trend rate assumption based on analyses of various factors including the specific provisions of its medical plans, actual cost trends experienced and projected, and demographics of plan participants. Dominion Energy’s healthcare cost trend rate assumption as of December 31, 2018 was 6.50% and is expected to gradually decrease to 5.00% by 2025 and continue at that rate for years thereafter.

Mortality rates are developed from actual and projected plan experience for postretirement benefit plans. Dominion Energy’s actuary conducts an experience study periodically as part of the process to select its best estimate of mortality. Dominion Energy considers both standard mortality tables and improvement factors as well as the plans’ actual experience when selecting a best estimate. During 2016, Dominion Energy conducted a new experience study as scheduled and, as a result, updated its mortality assumptions.

The following table illustrates the effect on cost of changing the critical actuarial assumptions previously discussed for Dominion Energy’s plans held as of December 31, 2018, while holding all other assumptions constant:

				Increase in Net Periodic Cost
	Change in Actuarial Assumption			Pension Benefits		Other Postretirement Benefits
(millions, except percentages)
Discount rate		(0.25	)%		$20		$  2
Long-term rate of return on plan assets		(0.25	)%		19		4
Healthcare cost trend rate		1	%		N/A		20

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

In addition to the effects on cost, at December 31, 2018, a 0.25% decrease in the discount rate would increase Dominion Energy’s projected pension benefit obligation by $294 million and its accumulated postretirement benefit obligation by $37 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $130 million.

See Note 21 to the Consolidated Financial Statements for additional information on Dominion Energy’s employee benefit plans.

New Accounting Standards

See Note 2 to the Consolidated Financial Statements for a discussion of new accounting standards.

Dominion Energy

RESULTS OF OPERATIONS

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

Year Ended December 31,	2018		$ Change			2017		$ Change		2016
(millions, except EPS)
Net Income attributable to Dominion Energy	$	2,447		$ (552)		$	2,999		$ 876	$	2,123
Diluted EPS		3.74		(0.98	)		4.72		1.28		3.44

Overview

2018 VS. 2017

Net income attributable to Dominion Energy decreased 18%, primarily due to the absence of benefits in 2017 resulting from the remeasurement of deferred income taxes to the new corporate income tax rate, an impairment charge on certain gathering and processing assets, a charge associated with Virginia legislation enacted in March 2018, decreased net investment earnings on nuclear decommissioning trust funds, lower renewable energy investment tax credits and a charge for disallowance of FERC-regulated plant. These decreases were partially offset by gains on the sales of certain merchant generation facilities and equity method investments, the commencement of commercial operations of the Liquefaction Project and the absence of charges associated with equity method investments in wind-powered generation facilities.

2017 VS. 2016

Net income attributable to Dominion Energy increased 41%, primarily due to benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate, the Dominion Energy Questar Combination and an absence of charges related to future ash pond and landfill closures. These increases were partially offset by lower renewable energy investment tax credits and charges associated with equity method investments in wind-powered generation facilities.

Analysis of Consolidated Operations

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

Year Ended December 31,	2018			$ Change			2017			$ Change			2016
(millions)
Operating revenue	$	13,366			$780		$	12,586			$849		$	11,737
Electric fuel and other energy-related purchases		2,814			513			2,301			(32	)		2,333
Purchased electric capacity		122			116			6			(93	)		99
Purchased gas		645			(56	)		701			242			459
Net revenue		9,785			207			9,578			732			8,846
Other operations and maintenance		3,458			258			3,200			(79	)		3,279
Depreciation, depletion and amortization		2,000			95			1,905			346			1,559
Other taxes		703			35			668			72			596
Impairment of assets and related charges		403			388			15			11			4
Gains on sales of assets		(380	)		(233	)		(147	)		(107	)		(40	)
Other income		1,021			663			358			(71	)		429
Interest and related charges		1,493			288			1,205			195			1,010
Income tax expense		580			610			(30	)		(685	)		655
Noncontrolling interests		102			(19	)		121			32			89

An analysis of Dominion Energy’s results of operations follows:

2018 VS. 2017

Net revenue increased 2%, primarily reflecting:

• A $500 million increase due to commencement of commercial operations of the Liquefaction Project, including terminalling services provided to the export customers ($508 million) and regulated gas transportation contracts to serve the export customers ($58 million), partially offset by credits associated with the start-up phase of the Liquefaction Project ($66 million);

• An increase in sales to electric utility retail customers from an increase in heating degree days during the heating season of 2018 ($71 million) and an increase in cooling degree days during the cooling season of 2018 ($69 million);

• A $130 million increase due to favorable pricing at merchant generation facilities;

• A $92 million increase due to growth projects placed in service, other than the Liquefaction Project;

• A $74 million increase in services performed for Atlantic Coast Pipeline; and

• A $46 million increase in sales to electric utility retail customers due to customer growth.

These increases were partially offset by:

• A $325 million decrease for regulated electric generation and electric and gas distribution operations as a result of the 2017 Tax Reform Act;

• A $215 million charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers;

• A $94 million increase in net electric capacity expense related to the annual PJM capacity performance market effective June 2017 ($112 million) and the annual PJM capacity perform-

52

ance market effective June 2018 ($39 million), partially offset by a benefit related to non-utility generators ($57 million);

• An $89 million decrease in rate adjustment clauses associated with electric utility operations, which includes the impacts of the 2017 Tax Reform Act; and

• A $38 million decrease from scheduled declines in or expiration of certain DETI and Cove Point contracts.

Net revenue does not reflect an impact from a reduction in planned outage days at Millstone as there was an offsetting increase in unplanned outage days.

Other operations and maintenance increased 8%, primarily reflecting:

• A $102 million increase in storm damage and service restoration costs in the regulated electric service territory;

• An $81 million increase due to a charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018;

• A $73 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income;

• A $47 million increase in operating expenses from the commercial operations of the Liquefaction Project and costs associated with regulated gas transportation contracts to serve the export customers; and

• A $38 million increase in salaries, wages and benefits, partially offset by

• A $74 million decrease from a reduction in planned outage days at certain merchant and utility generation facilities.

Depreciation, depletion and amortization increased 5%, primarily due to an increase from various growth projects being placed into service ($187 million), including the Liquefaction Project ($81 million), partially offset by revised depreciation rates for regulated nuclear plants to comply with the Virginia Commission requirements ($61 million).

Impairment of assets and related charges increased $388 million, primarily due to a $219 million impairment charge on certain gathering and processing assets, a $135 million charge for disallowance of FERC-regulated plant and a $37 million write-off associated with the Eastern Market Access Project.

Gains on sales of assets increased $233 million, primarily due to the sale of Fairless and Manchester ($210 million) and an increase in gains related to agreements to convey shale development rights under natural gas storage fields ($46 million).

Other income increased $663 million, primarily reflecting a gain on the sale of Dominion Energy’s 50% limited partnership interest in Blue Racer ($546 million), the absence of charges associated with equity method investments in wind-powered generation facilities ($158 million), a gain on the sale of Dominion Energy’s 25% limited partnership interest in Catalyst Old River Hydroelectric Limited Partnership ($87 million) and a decrease in the non-service components of pension and other postretirement employee benefit credits capitalized to property, plant and equipment in 2018 ($45 million), partially offset by a decrease in net investment earnings on nuclear decommissioning trust funds ($209 million).

Interest and related charges increased 24%, primarily due to the absence of capitalization of interest expense associated with the Liquefaction Project upon completion of construction ($111

million), higher long-term debt interest expense resulting from net debt issuances in 2018 and 2017 ($92 million) and charges associated with the early redemption of certain debt securities ($69 million).

Income tax expense increased $610 million, primarily due to the absence of benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($851 million) and lower renewable energy investment tax credits ($138 million), partially offset by the reduced corporate income tax rate ($414 million).

2017 VS. 2016

Net revenue increased 8%, primarily reflecting:

• A $663 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017;

• A $97 million electric capacity benefit related to non-utility generators ($133 million) and a benefit due to the annual PJM capacity performance market effective June 2016 ($123 million), partially offset by the annual PJM capacity performance market effective June 2017 ($159 million);

• An $86 million increase due to additional generation output from merchant solar generating projects;

• A $71 million increase in sales to electric utility retail customers due to the effect of changes in customer usage and other factors, including $25 million related to customer growth;

• A $63 million increase from regulated natural gas transmission growth projects placed in service;

• A $46 million increase from rate adjustment clauses associated with electric utility operations; and

• A $34 million increase in services performed for Atlantic Coast Pipeline.

These increases were partially offset by:

• A $144 million decrease from Cove Point import contracts;

• A $114 million decrease due to unfavorable pricing at merchant generation facilities; and

• A decrease in sales to electric utility retail customers from a decrease in cooling degree days during the cooling season of 2017 ($53 million) and a reduction in heating degree days during the heating season of 2017 ($28 million).

Other operations and maintenance decreased 2%, primarily reflecting:

• A $197 million absence of charges related to future ash pond and landfill closure costs at certain utility generation facilities;

• A $115 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;

• The absence of organizational design initiative costs ($64 million); and

• A $46 million decrease in storm damage and service restoration costs associated with electric utility operations, partially offset by

• A $162 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017;

• A $92 million increase in salaries, wages and benefits;

• A $36 million increase in outage costs; and

53

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

• A $33 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income.

Depreciation, depletion and amortization increased 22%, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017 ($162 million) and various growth projects being placed into service ($151 million).

Other taxes increased 12%, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017 ($35 million) and increased property taxes related to growth projects placed into service ($27 million).

Gains on sales of assets increased $107 million, primarily due to the sale of certain assets associated with nonregulated retail energy marketing operations.

Other income decreased 17%, primarily due to charges associated with equity method investments in wind-powered generation facilities ($158 million), partially offset by an increase in earnings, excluding charges, from equity method investments ($29 million) an increase in AFUDC associated with rate-regulated projects ($23 million) and an increase in the non-service cost components of pension and other postretirement employee benefit credits ($14 million).

Interest and related charges increased 19%, primarily due to higher long-term debt interest expense resulting from debt issuances in 2016 and 2017 ($171 million) and debt acquired in the Dominion Energy Questar Combination ($37 million).

Income tax expense decreased $685 million, primarily due to benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($851 million), partially offset by lower renewable energy investment tax credits ($133 million).

Outlook

Dominion Energy’s 2019 net income is expected to decrease on a per share basis as compared to 2018 primarily from the following:

• Charges incurred for refunds to SCE&G electric customers and transaction and transition costs related to the SCANA Combination;

• The absence of earnings from, and gains on, the sales of certain merchant generation facilities and equity method investments;

• A charge associated with the early retirement of the existing automated meter reading infrastructure;

• Return to normal weather;

• An increase in pension-related expenses; and

• Share dilution.

These decreases are expected to be partially offset by the following:

• Commercial operation of the Liquefaction Project for the entire year;

• The inclusion of operations acquired in the SCANA Combination;

• The absence of charges associated with the impairment of certain gathering and processing assets and disallowance of FERC-regulated plant;

• The absence of charges associated with Virginia legislation enacted in March 2018;

• Construction and operation of growth projects in gas transmission and distribution; and

• Construction and operation of growth projects in electric utility operations.

SEGMENT RESULTS OF OPERATIONS

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

Year Ended December 31,	2018						2017				2016
	Net income (loss) attributable to Dominion Energy			Diluted EPS			Net income attributable to Dominion Energy		Diluted EPS		Net income (loss) attributable to Dominion Energy			Diluted EPS
(millions, except EPS)
Power Delivery		$   587			$0.90			$   531		$ 0.83		$   484			$ 0.78
Power Generation		1,254			1.92			1,181		1.86		1,397			2.26
Gas Infrastructure		1,214			1.85			898		1.41		726			1.18
Primary operating segments		3,055			4.67			2,610		4.10		2,607			4.22
Corporate and Other		(608	)		(0.93	)		389		0.62		(484	)		(0.78	)
Consolidated		$2,447			$3.74			$2,999		$ 4.72		$2,123			$ 3.44

Power Delivery

Presented below are operating statistics related to Power Delivery’s operations:

Year Ended December 31,	2018		% Change			2017		% Change			2016
Electricity delivered (million MWh)		87.8		5	%		83.4		—	%		83.7
Degree days (electric distribution service area):
Cooling		2,019		12			1,801		(2	)		1,830
Heating		3,608		16			3,104		(10	)		3,446
Average electric distribution customer accounts (thousands)(1)		2,600		1			2,574		1			2,549

(1) Period average.

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

2018 VS. 2017

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	29		$	0.05
Other		48			0.08
Rate adjustment clause equity return		26			0.04
Depreciation and amortization		(8	)		(0.01	)
Storm damage and service restoration		(19	)		(0.03	)
Other		(20	)		(0.03	)
Share dilution		—			(0.03	)
Change in net income contribution	$	56		$	0.07

54

2017 VS. 2016

	Increase (Decrease)
	Amount		EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	(14)	$	(0.02)
Other		15		0.02
FERC transmission equity return		14		0.02
Storm damage and service restoration		14		0.02
Other		18		0.03
Share dilution		—		(0.02	)
Change in net income contribution	$	47	$	0.05

Power Generation

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

Year Ended December 31,	2018		% Change			2017		% Change			2016
Electricity supplied (million MWh):
Utility		88.0		4	%		85.0		(3	)%		87.9
Merchant		28.8		—			28.9		—			28.9
Degree days (electric utility service area):
Cooling		2,019		12			1,801		(2	)		1,830
Heating		3,608		16			3,104		(10	)		3,446

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

2018 VS. 2017

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather		$  57			$ 0.09
Other		(5	)		(0.01	)
Merchant generation margin		110			0.17
Planned outage costs		46			0.07
2017 Tax Reform Act impacts		45			0.07
Depreciation and amortization		30			0.05
Electric capacity		(66	)		(0.10	)
Renewable energy investment tax credit		(138	)		(0.21	)
Other		(6	)		(0.01	)
Share dilution		—			(0.06	)
Change in net income contribution		$  73			$ 0.06

2017 VS. 2016

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather		$  (36)			$(0.06)
Other		32			0.05
Electric capacity		58			0.09
Depreciation and amortization		(46	)		(0.07	)
Renewable energy investment tax credit		(133	)		(0.21	)
Merchant generation margin		(28	)		(0.04	)
Interest expense		(25	)		(0.04	)
Outage costs		(22	)		(0.03	)
Other		(16	)		(0.03	)
Share dilution		—			(0.06	)
Change in net income contribution		$(216)			$(0.40)

Gas Infrastructure

Presented below are selected operating statistics related to Gas Infrastructure’s operations.

Year Ended December 31,	2018		% Change			2017		% Change			2016
Gas distribution throughput (bcf)(1):
Sales		131		1	%		130		113	%		61
Transportation		725		11			654		22			537
Heating degree days (gas distribution service area):
Eastern region		5,693		15			4,930		(6	)		5,235
Western region(1)		4,672		(4	)		4,892		161			1,876
Average gas distribution customer accounts (thousands)(1)(2):
Sales		1,258		1			1,240		—			1,234	(3)
Transportation		1,096		1			1,086		1			1,071
Average retail energy marketing customer accounts (thousands)(2)		750		(47	)		1,405		2			1,376

(1) Includes Dominion Energy Questar effective September 2016.

(2) Period average.

(3) Includes Dominion Energy Questar customer accounts for the entire year.

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

2018 VS. 2017

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
2017 Tax Reform Act impacts		$141			$ 0.22
State legislative change		18			0.03
Assignment of shale development rights		27			0.04
Transportation and storage growth projects		30			0.05
Cove Point export contracts		259			0.41
Cove Point import contracts		(12	)		(0.02	)
DETI contract declines		(20	)		(0.03	)
Interest expense, net		(86	)		(0.14	)
Other		(41	)		(0.07	)
Share dilution		—			(0.05	)
Change in net income contribution		$316			$ 0.44

55

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

2017 VS. 2016

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Dominion Energy Questar Combination		$184			$0.30
Sale of certain energy marketing assets		48			0.08
Assignment of shale development rights		13			0.02
Noncontrolling interest(1)		(30	)		(0.05	)
Cove Point import contracts		(86	)		(0.14	)
Transportation and storage growth projects		29			0.04
Other		14			0.02
Share dilution		—			(0.04	)
Change in net income contribution		$172			$0.23

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

Corporate and Other

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

Year Ended December 31,	2018			2017			2016
(millions, except EPS)
Specific items attributable to operating segments		$   (88	)		$ 861		$	(180	)
Specific items attributable to Corporate and Other segment		(116	)		(151	)		(44	)
Total specific items		(204	)		710			(224	)
Other corporate operations:
2017 Tax Reform Act impacts		(80	)		—			—
Interest expense, net		(355	)		(330	)		(277	)
Other		31			9			17
Total other corporate operations		(404	)		(321	)		(260	)
Total net income (expense)		(608	)		389			(484	)
EPS impact		$(0.93	)		$0.62		$	(0.78	)

TOTAL SPECIFIC ITEMS

Corporate and Other includes specific items attributable to Dominion Energy’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. See Note 25 to the Consolidated Financial Statements for discussion of these items in more detail. Corporate and Other also includes specific items attributable to the Corporate and Other segment. In 2018, this primarily included $51 million of after-tax charges associated with the early redemption of certain debt securities and $31 million of after-tax transaction and transition costs associated with the Dominion Energy Questar Combination and SCANA Combination. In 2017, this primarily included $124 million of tax benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate. In 2016, this primarily included $53 million of after-tax transaction and transition costs associated with the Dominion Energy Questar Combination.

VIRGINIA POWER

RESULTS OF OPERATIONS

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

Year Ended December 31,	2018		$ Change		2017		$ Change		2016
(millions)
Net Income		$1,282		$(258)		$1,540		$322	$	1,218

Overview

2018 VS. 2017

Net income decreased 17%, primarily due to a charge associated with Virginia legislation enacted in March 2018, an increase in storm damage and service restoration costs, a charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018 and an increase in net electric capacity expense, partially offset by an increase in heating and cooling degree days in the service territory.

2017 VS. 2016

Net income increased 26%, primarily due to the absence of charges related to future ash pond and landfill closure costs, a benefit from the remeasurement of deferred income taxes to the new corporate income tax rate and an electric capacity benefit.

Analysis of Consolidated Operations

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

Year Ended December 31,	2018		$ Change			2017		$ Change			2016
(millions)
Operating revenue	$	7,619		$ 63		$	7,556		$ (32)		$	7,588
Electric fuel and other energy-related purchases		2,318		409			1,909		(64	)		1,973
Purchased electric capacity		122		116			6		(93	)		99
Net revenue		5,179		(462	)		5,641		125			5,516
Other operations and maintenance		1,676		198			1,478		(379	)		1,857
Depreciation and amortization		1,132		(9	)		1,141		116			1,025
Other taxes		300		10			290		6			284
Other income		22		(54	)		76		20			56
Interest and related charges		511		17			494		33			461
Income tax expense		300		(474	)		774		47			727

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

2018 VS. 2017

Net revenue decreased 8%, primarily reflecting:

• A $238 million decrease for regulated generation and distribution operations as a result of the 2017 Tax Reform Act;

• A $215 million charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers;

• A $94 million increase in net electric capacity expense related to the annual PJM capacity performance market effective June

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2017 ($112 million) and the annual PJM capacity performance market effective June 2018 ($39 million), partially offset by a benefit related to non-utility generators ($57 million); and

• An $89 million decrease from rate adjustment clauses, which includes the impacts of the 2017 Tax Reform Act; partially offset by

• An increase in sales to retail customers from an increase in heating degree days during the heating season of 2018 ($71 million) and an increase in cooling degree days during the cooling season of 2018 ($69 million); and

• A $46 million increase in sales to retail customers due to customer growth.

Other operations and maintenance increased 13%, primarily reflecting:

• A $102 million increase due to storm damage and service restoration costs; and

• An $81 million increase due to a charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018; partially offset by

• A $19 million decrease from a reduction in planned outage days at certain generation facilities.

Depreciation and amortization was substantially consistent as a decrease due to revised depreciation rates for regulated nuclear plants to comply with the Virginia Commission requirements ($61 million) was substantially offset by various growth projects being placed into service ($56 million).

Other income decreased 71%, primarily related to lower realized gains (including investment income) on nuclear decommissioning trust funds ($23 million), the electric transmission tower rental portfolio, including the absence of the assignment of such amounts to Vertical Bridge Towers II, LLC ($18 million) and the absence of interest income associated with the settlement of state income tax refund claims ($11 million), partially offset by the absence of a charge associated with a customer settlement ($16 million).

Income tax expense decreased 61%, primarily due to lower pre-tax income ($256 million), the reduced corporate income tax rate ($235 million) and higher renewable energy investment tax credits ($35 million), partially offset by the absence of benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($93 million).

2017 VS. 2016

Net revenue increased 2%, primarily reflecting:

• A $97 million electric capacity benefit related to non-utility generators ($133 million) and a benefit due to the annual PJM capacity performance market effective June 2016 ($123 million), partially offset by the annual PJM capacity performance market effective June 2017 ($159 million);

• A $71 million increase in sales to retail customers due to the effect of changes in customer usage and other factors, including $25 million related to customer growth; and

• A $46 million increase from rate adjustment clauses; partially offset by

• A decrease in sales to retail customers from a decrease in cooling degree days during the cooling season of 2017 ($53 million) and a reduction in heating degree days during the heating season of 2017 ($28 million).

Other operations and maintenance decreased 20%, primarily reflecting:

• A $197 million decrease due to the absence of charges related to future ash pond and landfill closure costs at certain utility generation facilities;

• A $115 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;

• A $46 million decrease in storm damage and service restoration costs; and

• The absence of organizational design initiative costs ($32 million); partially offset by

• A $37 million increase in salaries, wages and benefits and general administrative expenses.

Depreciation and amortization increased 11%, primarily due to various growth projects being placed into service ($58 million) and revised depreciation rates ($40 million).

Other income increased 36%, primarily reflecting:

• An $11 million increase in interest income associated with the settlement of state income tax refund claims;

• An $11 million increase from the assignment of Virginia Power’s electric transmission tower rental portfolio; and

• An $8 million increase in AFUDC associated with rate-regulated projects; partially offset by

• A $16 million charge associated with a customer settlement.

Income tax expense increased 6% primarily due to higher pretax income ($139 million), partially offset by benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($93 million).

DOMINION ENERGY GAS

RESULTS OF OPERATIONS

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

Year Ended December 31,	2018		$ Change		2017		$ Change		2016
(millions)
Net Income		$301		$(314)		$615		$223		$392

Overview

2018 VS. 2017

Net income decreased 51%, primarily due to an impairment charge on certain gathering and processing assets, a charge for disallowance of FERC-regulated plant and the absence of benefits from the 2017 Tax Reform Act partially offset by regulated natural gas transmission activities from growth projects placed into service and an increase in gains from agreements to convey shale development rights underneath several natural gas storage fields.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

2017 VS. 2016

Net income increased 57%, primarily due to a benefit from the remeasurement of deferred income taxes to the new corporate income tax rate and gas transportation and storage activities from growth projects placed into service.

Analysis of Consolidated Operations

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

Year Ended December 31,	2018			$ Change			2017			$ Change			2016
(millions)
Operating revenue	$	1,940			$126		$	1,814			$176		$	1,638
Purchased gas		40			(92	)		132			23			109
Other energy-related purchases		135			114			21			9			12
Net revenue		1,765			104			1,661			144			1,517
Other operations and maintenance		759			94			665			70			595
Depreciation and amortization		244			17			227			23			204
Other taxes		200			15			185			15			170
Impairment of assets and related charges		346			330			16			16			—
Gains on sales of assets		(119	)		(49	)		(70	)		(25	)		(45	)
Earnings from equity method investee		24			3			21			—			21
Other income		133			29			104			17			87
Interest and related charges		105			8			97			3			94
Income tax expense		86			35			51			(164	)		215

An analysis of Dominion Energy Gas’ results of operations follows:

2018 VS. 2017

Net revenue increased 6%, primarily reflecting:

• A $74 million increase in services performed for Atlantic Coast Pipeline;

• A $57 million increase due to regulated natural gas transmission growth projects placed in service; and

• A $20 million increase in PIR program revenues; partially offset by

• A $36 million decrease for regulated distribution operations as a result of the 2017 Tax Reform Act; and

• A $25 million decrease from scheduled declines in certain DETI contracts.

Other operations and maintenance increased 14%, primarily reflecting:

• A $73 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income; and

• A $7 million increase in salaries, wages and benefits.

Depreciation and amortization increased 7%, primarily due to an increase from various growth projects being placed into service.

Impairment of assets and related charges increased $330 million, primarily due to an impairment charge on certain gathering and processing assets ($219 million) and a charge for disallowance of FERC-regulated plant ($127 million) partially offset by the absence of a charge to write-off the balance of a regulatory asset no longer considered probable of recovery ($15 million).

Gains on sales of assets increased 70%, primarily due to increased gains related to agreements to convey shale development rights under natural gas storage fields.

Earnings from equity method investee increased 14%, primarily due to higher earnings from unsubscribed capacity as a result of an increase in heating degree days at Iroquois.

Other income increased 28%, primarily due to a decrease in the non-service components of pension and other postretirement employee benefit credits capitalized to property, plant and equipment in 2018 ($24 million) partially offset by AFUDC on rate-regulated projects ($5 million).

Interest and related charges increased 8%, primarily due to higher interest expense on long-term debt due to an issuance in the second quarter of 2018 and increased interest rates ($10 million), partially offset by an increase in deferred carrying costs ($6 million).

Income tax expense increased 69%, primarily due to the absence of benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($197 million) and the absence of a settlement with state tax authorities ($5 million), partially offset by the reduced corporate income tax rate ($67 million) and lower pre-tax income ($98 million).

2017 VS. 2016

Net revenue increased 9%, primarily reflecting:

• A $55 million increase due to regulated natural gas transmission growth projects placed in service;

• A $34 million increase in services performed for Atlantic Coast Pipeline;

• A $24 million increase in PIR program revenues; and

• A $16 million increase in rate recovery for low income assistance programs associated with regulated natural gas distribution operations.

Other operations and maintenance increased 12%, primarily reflecting:

• A $33 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income;

• A $16 million increase in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income; and

• A $13 million increase in salaries, wages and benefits and general administrative expenses.

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

Impairment of assets and related charges increased $16 million, primarily due to a charge to write-off the balance of a regulatory asset no longer considered probable of recovery.

Gains on sales of assets increased 56% primarily due to increased gains from agreements to convey shale development rights underneath several natural gas storage fields.

Other income increased 20%, primarily due to a $12 million increase in AFUDC associated with rate-regulated projects and an $8 million increase in the non-service cost components of pension and other postretirement employee benefit credits, partially offset by the absence of the 2016 sale of a portion of Dominion Energy Gas’ interest in Iroquois ($5 million).

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Income tax expense decreased 76%, primarily due to benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($197 million), partially offset by higher pre-tax income ($22 million).

LIQUIDITY AND CAPITAL RESOURCES

Dominion Energy 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.

At December 31, 2018, Dominion Energy had $5.6 billion of unused capacity under its credit facility. See additional discussion below under Credit Facilities and Short-Term Debt.

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

Year Ended December 31,	2018			2017			2016
(millions)
Cash, restricted cash and equivalents at beginning of year	$	185		$	322		$	632
Cash flows provided by (used in):
Operating activities		4,773			4,502			4,151
Investing activities		(2,358	)		(5,942	)		(10,691	)
Financing activities		(2,209	)		1,303			6,230
Net increase (decrease) in cash, restricted cash and equivalents		206			(137	)		(310	)
Cash, restricted cash and equivalents at end of year	$	391		$	185		$	322

Operating Cash Flows

Net cash provided by Dominion Energy’s operating activities increased $271 million, primarily due to the commencement of commercial operations of the Liquefaction Project, higher merchant generation margin, derivative activities and the favorable impact of weather, partially offset by lower deferred fuel cost recoveries in the Virginia jurisdiction, increased interest expense and one-time rate credits to electric utility customers.

Dominion Energy 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. In December 2018, Dominion Energy’s Board of Directors established an annual dividend rate for 2019 of $3.67 per share of common stock, a 10.0% increase over the 2018 rate. Dividends are subject to declaration by the Board of Directors. In January 2019, Dominion Energy’s Board of Directors declared dividends payable in March 2019 of 91.75 cents per share of common stock.

Dominion Energy’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, and which are discussed in Item 1A. Risk Factors.

CREDIT RISK

Dominion Energy’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 Energy’s credit exposure as of December 31, 2018 for these

activities. Gross credit exposure for each counterparty is calculated as 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)		$101		$4		$97
Non-investment grade(2)		1		—		1
No external ratings:
Internally rated—investment grade(3)		3		—		3
Internally rated—non-investment grade(4)		44		—		44
Total	$	149	$	4	$	145

(1) Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 60% of the total net credit exposure.

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

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

(4) The five largest counterparty exposures, combined, for this category represented approximately 26% of the total net credit exposure.

Investing Cash Flows

Net cash used in Dominion Energy’s investing activities decreased $3.6 billion, primarily due to proceeds from the sale of certain merchant generation facilities and equity method investments and decreases in plant construction due to the commencement of commercial operations of the Liquefaction Project and Greensville County.

Financing Cash Flows and Liquidity

Dominion Energy relies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by its operations. As discussed in Credit Ratings, Dominion Energy’s 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 Energy 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. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows Dominion Energy to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.

From time to time, Dominion Energy 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 tender offers or otherwise.

Net cash used by Dominion Energy’s financing activities in 2018 was $2.2 billion compared to net cash provided by financing activities in 2017 of $1.3 billion, primarily due to net debt repayments in 2018 compared to net debt issuances in 2017, partially offset by the issuance of common stock.

59

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

CREDIT FACILITIES AND SHORT-TERM DEBT

Dominion Energy uses 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 Energy utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties.

In connection with commodity hedging activities, Dominion Energy is required to provide collateral to counterparties under some circumstances. Under certain collateral arrangements, Dominion Energy may satisfy these requirements by electing to either deposit cash, post letters of credit or, in some cases, utilize other forms of security. From time to time, Dominion Energy may vary the form of collateral provided to counterparties after weighing the costs and benefits of various factors associated with the different forms of collateral. These factors include short-term borrowing and short-term investment rates, the spread over these short-term rates at which Dominion Energy can issue commercial paper, balance sheet impacts, the costs and fees of alternative collateral postings with these and other counterparties and overall liquidity management objectives.

Dominion Energy’s commercial paper and letters of credit outstanding, as well as capacity available under its credit facility, were as follows:

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit		Facility Capacity Available
(millions)
At December 31, 2018
Joint revolving credit facility(2)	$	6,000		$324		$88	$	5,588

(1) The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s credit facility was 2.93% at December 31, 2018.

(2) This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

In connection with the SCANA Combination, Dominion Energy intends to terminate SCANA, SCE&G and PSNC’s existing credit facilities, which have limits of $400 million, $700 million and $200 million, respectively, and add SCE&G as a co-borrower to its $6.0 billion joint revolving credit facility in the first quarter of 2019 once certain regulatory approvals are obtained. In January 2019, Virginia Power and SCE&G, as co-borrowers, filed with the Virginia Commission and the South Carolina Commission, respectively, for approval. In February 2019, the Virginia Commission approved the request. SCE&G is required to obtain FERC approval to issue short-term indebtedness, including commercial paper, and to assume liabilities as a guarantor. In February 2019, Dominion Energy terminated South Carolina Fuel Company, Inc.’s existing credit facility of $500 million.

In November 2017, Dominion Energy filed an SEC shelf registration statement for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability Investment^SM. The registration limits the

principal amount that may be outstanding at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. The balance as of December 31, 2018 was $10 million. The notes are short-term debt obligations on Dominion Energy’s Consolidated Balance Sheets. The proceeds will be used for general corporate purposes and to repay debt.

In March 2018, Dominion Energy Midstream entered into a $500 million revolving credit facility. The credit facility was scheduled to mature in March 2021, bore interest at a variable rate, and was used to support bank borrowings and the issuance of commercial paper, as well as to support up to $250 million of letters of credit. At December 31, 2018, Dominion Energy Midstream had $73 million outstanding under this credit facility. In February 2019, Dominion Energy Midstream terminated the facility subsequent to repaying the outstanding balance, plus accrued interest.

In October 2018, Dominion Energy entered into a credit agreement, which allows Dominion Energy to issue up to approximately $21 million in letters of credit. At December 31, 2018, approximately $21 million in letters of credit were outstanding under this agreement. The facility terminates in June 2020.

In February and June 2018, Dominion Energy borrowed $950 million and $500 million, respectively, under 364-Day Term Loan Agreements that bore interest at a variable rate. In September 2018, the principal outstanding plus accrued interest for both borrowings was repaid.

LONG-TERM DEBT

During 2018, Dominion Energy issued the following long-term public debt:

Type	Issuer		Principal		Rate			Maturity
			(millions)
Senior notes		Dominion Energy	$	300		4.250	%		2028
Senior notes		Virginia Power		700		3.800	%		2028
Senior notes		Virginia Power		600		4.600	%		2048
Senior notes		Dominion Energy Gas		500		variable			2021
Total notes issued			$	2,100

During 2018, Dominion Energy also issued the following long-term private debt:

• In January 2018, Dominion Energy Questar Pipeline issued, through private placement, $100 million of 3.53% senior notes and $150 million of 3.91% senior notes that mature in 2028 and 2038, respectively. The proceeds were used to repay maturing long-term debt.

• In April 2018, Questar Gas issued through private placement $50 million of 3.30% senior notes and $100 million of 3.97% senior notes that mature in 2030 and 2047, respectively. The proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper.

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• In May 2018, Dominion Energy issued through private placement $500 million of variable rate senior notes that mature in 2020. The proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper. In November 2018, the notes were redeemed at the principal outstanding plus accrued interest.

• In November 2018, Eagle Solar issued through private placement $362 million of 4.82% senior secured notes which mature in December 2042. The debt is nonrecourse to Dominion Energy and is secured by Eagle Solar’s interest in certain merchant solar facilities. The proceeds were used for the reimbursement of equity amounts previously invested by Dominion Energy in the acquisition, development or construction of the projects in Eagle Solar.

During 2018, Dominion Energy also borrowed the following under a term loan agreement:

• In September 2018, Cove Point closed on an up to $3.0 billion term loan that is secured by Dominion Energy’s common equity interest in Cove Point, bears interest at a variable rate and matures in 2021. In accordance with the terms of the term loan, Cove Point borrowed $2.0 billion and $1.0 billion in September 2018 and December 2018, respectively. Under the terms of the term loan, Cove Point faces certain restrictions on issuing additional debt, divesting the Cove Point LNG Facility, paying distributions to Dominion Energy or taking certain other actions without necessary approvals.

During 2018, in addition to the November 2018 redemption described above, Dominion Energy redeemed the following long-term debt:

• In March 2018, Virginia Power redeemed $100 million of its variable rate tax-exempt financings which would otherwise have matured in 2024, 2026 and 2027.

• In December 2018, Virginia Power redeemed its $14 million 5.60% Economic Development Authority of the County of Chesterfield Solid Waste and Sewage Disposal Revenue Bonds, Series 2007A, due in 2031 at the principal outstanding plus accrued interest.

• In December 2018, Dominion Energy redeemed the following outstanding series of senior notes: 2011 Series A 4.45% Senior Notes due 2021, 2014 Series B 2.50% Senior Notes due 2019 and 2014 Series C 3.625% Senior Notes due 2024 with an aggregate outstanding principal of $1.7 billion plus accrued interest and the applicable make-whole premium of $34 million. See Note 17 to the Consolidated Financial Statements for a description of senior note redemptions.

During 2018, Dominion Energy repaid and repurchased $5.7 billion of long-term debt, including redemption premiums.

In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan agreement due in December 2019 at the principal outstanding plus accrued interest.

In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any and all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of $1.0 billion.

SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer.

NONCONTROLLING INTEREST IN DOMINION ENERGY MIDSTREAM

In May 2018, all of the subordinated units of Dominion Energy Midstream held by Dominion Energy were converted into common units on a 1:1 ratio following the payment of Dominion Energy Midstream’s distribution for the first quarter of 2018. In June 2018, Dominion Energy, as general partner, exercised an incentive distribution right reset as defined in Dominion Energy Midstream’s partnership agreement and received 26.7 million common units representing limited partner interests in Dominion Energy Midstream. As a result of the increase in its ownership interest in Dominion Energy Midstream, Dominion Energy recorded a decrease in noncontrolling interest, and a corresponding increase in shareholders’ equity, of $375 million reflecting the change in the carrying value of the interest in the net assets of Dominion Energy Midstream held by others.

In January 2019, Dominion Energy and Dominion Energy Midstream closed on an agreement and plan of merger pursuant to which Dominion Energy acquired each outstanding common unit representing limited partner interests in Dominion Energy Midstream not already owned by Dominion Energy through the issuance of 22.5 million shares of common stock valued at $1.6 billion. Under the terms of the agreement and plan of merger, each publicly held outstanding common unit representing limited partner interests in Dominion Energy Midstream was converted into the right to receive 0.2492 shares of Dominion Energy common stock. Immediately prior to the closing, each Series A Preferred Unit representing limited partner interests in Dominion Energy Midstream was converted into common units representing limited partner interests in Dominion Energy Midstream in accordance with the terms of Dominion Energy Midstream’s partnership agreement.

ISSUANCE OF COMMON STOCK AND OTHER EQUITY SECURITIES

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

During 2018, Dominion Energy received cash proceeds of $2.5 billion, net of fees and commissions from the issuance of approximately 36 million shares of common stock through various programs including the forward sale agreements described in Note 19 resulting in approximately 681 million shares of common stock outstanding at December 31, 2018. These proceeds include cash of $315 million from the issuance of 4.5 million of shares through Dominion Energy Direct^® and employee savings plans.

In 2018, Dominion Energy issued 9.3 million shares and received cash proceeds of $692 million, net of fees and commissions paid of $7 million through its at-the-market programs. See Note 19 for a description of the at-the-market programs.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Dominion Energy entered in March 2018, and closed in April 2018, separate forward sale agreements with Goldman Sachs & Co. LLC and Credit Suisse Capital LLC, as forward purchasers, and an underwriting agreement with Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, as representatives of the several underwriters named therein, relating to an aggregate of 20.0 million shares of Dominion Energy common stock. The underwriting agreement granted the underwriters a 30-day option to purchase up to an additional three million shares of Dominion Energy common stock, which the underwriters exercised with respect to approximately 2.1 million shares in April 2018. Dominion Energy entered into separate forward sale agreements with the forward purchasers with respect to the additional shares. In December 2018, Dominion Energy received proceeds of $1.4 billion upon the physical settlement of 22.1 million shares. See Note 19 to the Consolidated Financial Statements for a description of the forward sale agreements.

In January 2019, in connection with the SCANA Combination, Dominion Energy issued 95.6 million shares of Dominion Energy common stock, valued at $6.8 billion, representing 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock outstanding at closing. SCANA’s outstanding debt totaled $6.9 billion at closing. Also in January 2019, Dominion Energy issued 22.5 million shares of common stock to acquire interests in Dominion Energy Midstream as noted above. In addition, during 2019, Dominion Energy plans to issue shares for employee savings plans and direct stock purchase and dividend reinvestment plans.

REPURCHASE OF COMMON STOCK

Dominion Energy did not repurchase any shares in 2018 and does not plan to repurchase shares during 2019, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which does not count against its stock repurchase authorization.

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. Dominion Energy believes that its current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to Dominion Energy may affect its ability to access these funding sources or cause an increase in the return required by investors. Dominion Energy’s credit ratings affect its liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which it is able to offer its debt securities.

Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. Credit ratings should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for Dominion Energy are affected by its financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and event risk, if applicable, such as major acquisitions or dispositions.

In December 2018, Moody’s and Standard & Poor’s affirmed Dominion Energy’s ratings and changed Dominion Energy’s rating outlook to stable from negative.

Credit ratings and outlooks as of February 25, 2019 follow:

	Fitch		Moody’s		Standard & Poor’s
Dominion Energy
Issuer		BBB+		Baa2		BBB+
Senior unsecured debt securities		BBB+		Baa2		BBB
Junior subordinated notes(1)		BBB		Baa3		BBB
Enhanced junior subordinated notes(2)		BBB-		Baa3		BBB-
Junior/remarketable subordinated notes(2)		BBB-		Baa3		BBB-
Commercial paper		F2		P-2		A-2
Outlook		Stable		Stable		Stable

(1) Securities do not have an interest deferral feature.

(2) Securities have an interest deferral feature.

A downgrade in an individual company’s credit rating does not necessarily restrict its ability to raise short-term and long-term financing as long as its credit rating remains investment grade, but it could result in an increase in the cost of borrowing. Dominion Energy works closely with Fitch, Moody’s and Standard & Poor’s with the objective of achieving its targeted credit ratings. Dominion Energy may find it necessary to modify its business plan to maintain or achieve appropriate credit ratings and such changes may adversely affect growth and EPS.

Debt Covenants

As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, Dominion Energy must enter into enabling agreements. These agreements contain covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion Energy.

Some of the typical covenants include:

• The timely payment of principal and interest;

• Information requirements, including submitting financial reports and information about changes in Dominion Energy’s credit ratings to lenders;

• Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation and restrictions on disposition of all or substantially all assets;

• Compliance with collateral minimums or requirements related to mortgage bonds; and

• Limitations on liens.

Dominion Energy is required to pay annual commitment fees to maintain its credit facility. In addition, Dominion Energy’s credit agreement contains various terms and conditions that could affect its ability to borrow under the facility. They include a maximum debt to total capital ratio and cross-default provisions.

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As of December 31, 2018, the calculated total debt to total capital ratio, pursuant to the terms of the agreement, was as follows:

Company	Maximum Allowed Ratio			Actual Ratio(1)(2)
Dominion Energy		67.5	%		53.4%

(1) Indebtedness as defined by the bank agreements excludes certain junior subordinated and remarketable subordinated notes reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets.

(2) At January 1, 2019, the calculated total debt to total capital ratio, as adjusted for the SCANA Combination was 52.8%.

If Dominion Energy or any of its material subsidiaries fails to make payment on various debt obligations in excess of $100 million, the lenders could require the defaulting company, if it is a borrower under Dominion Energy’s credit facility, to accelerate its repayment of any outstanding borrowings and the lenders could terminate their commitments, if any, to lend funds to that company under the credit facility. In addition, if the defaulting company is Virginia Power, Dominion Energy’s obligations to repay any outstanding borrowing under the credit facility could also be accelerated and the lenders’ commitments to Dominion Energy could terminate.

Dominion Energy executed RCCs in connection with its issuance of the June 2006 hybrids and September 2006 hybrids. See Note 17 to the Consolidated Financial Statements for additional information, including terms of the RCCs.

At December 31, 2018, the termination dates and covered debt under the RCCs associated with Dominion Energy’s hybrids were as follows:

Hybrid	RCC Termination Date		Designated Covered Debt Under RCC
June 2006 hybrids		6/30/2036		September 2006 hybrids
September 2006 hybrids		9/30/2036		June 2006 hybrids

Dominion Energy monitors these debt covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2018, there have been no events of default under Dominion Energy’s debt covenants.

Dividend Restrictions

Certain agreements associated with Dominion Energy’s credit facility contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion Energy’s ability to pay dividends or receive dividends from its subsidiaries at December 31, 2018.

See Note 17 to the Consolidated Financial Statements for a description of potential restrictions on dividend payments by Dominion Energy, including in connection with the deferral of interest payments and contract adjustment payments on certain junior subordinated notes and equity units, initially in the form of corporate units, which information is incorporated herein by reference.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

CONTRACTUAL OBLIGATIONS

Dominion Energy is party to numerous contracts and arrangements obligating it to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion Energy is a party as of December 31, 2018. In addition, see Note 3 to the Consolidated Financial Statements for a description of significant contractual obligations acquired in the SCANA Combination. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities in the Consolidated Balance Sheets, other than current maturities of long-term debt, interest payable and certain derivative instruments. The majority of Dominion Energy’s current liabilities will be paid in cash in 2019.

	2019		2020- 2021		2022- 2023		2024 and thereafter		Total
(millions)
Long-term debt(1)(2)	$	3,607	$	7,333	$	3,238	$	20,931	$	35,109
Interest payments(3)		1,419		2,456		2,037		15,629		21,541
Operating leases		64		116		85		384		649
Purchase obligations(4):
Purchased electric capacity for utility operations		60		98		—		—		158
Fuel commitments for utility operations		1,060		644		363		1,057		3,124
Fuel commitments for nonregulated operations		35		169		84		113		401
Pipeline transportation and storage		329		537		403		1,723		2,992
Other(5)		206		122		48		13		389
Other long-term liabilities(6):
Other contractual obligations(7)		88		53		19		42		202
Total cash payments	$	6,868	$	11,528	$	6,277	$	39,892	$	64,565

(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.

(2) Includes capital leases. See Note 17 to the Consolidated Financial Statements for more information.

(3) Includes interest payments over the terms of the debt and payments on related stock purchase contracts. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2018 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 17 to the Consolidated Financial Statements. Does not reflect Dominion Energy’s ability to defer interest and stock purchase contract payments on certain junior subordinated notes or RSNs and equity units, initially in the form of Corporate Units.

(4) Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.

(5) Includes capital, operations, and maintenance commitments.

(6) Excludes regulatory liabilities, AROs and employee benefit plan obligations, which are not contractually fixed as to timing and amount. See Notes 12, 14 and 21 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $29 million of income taxes payable associated with unrecognized tax

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

benefits are excluded. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 5 to the Consolidated Financial Statements.

(7) Includes interest rate and foreign currency swap agreements.

PLANNED CAPITAL EXPENDITURES

Dominion Energy’s planned capital expenditures are expected to total approximately $6.3 billion, $7.3 billion and $6.9 billion in 2019, 2020 and 2021, respectively. Dominion Energy’s planned expenditures are expected to include construction and expansion of electric generation and natural gas transmission and storage facilities, construction improvements and expansion of electric transmission and distribution assets, purchases of nuclear fuel, maintenance and expected contributions to Atlantic Coast Pipeline.

Dominion Energy expects to fund its capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Planned capital expenditures include capital projects that are subject to approval by regulators and the Board of Directors.

See Power Delivery, Power Generation, Gas Infrastructure and Southeast Energy-Properties in Item 1. Business for a discussion of Dominion Energy’s expansion plans.

These estimates are based on a capital expenditures plan reviewed and endorsed by Dominion Energy’s Board of Directors in late 2018 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion Energy may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.

Use of Off-Balance Sheet Arrangements

LEASING ARRANGEMENT

In July 2016, Dominion Energy 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, totaling $365 million, to fund the estimated project costs. The project is expected to be completed by mid-2019. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $281 million as of December 31, 2018. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 89.9% of the then funded amount. For specific full recourse events, Dominion Energy 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 Energy 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 on behalf of the lessor 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

Energy 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 Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. In accordance with revised accounting guidance pertaining to the recognition, measurement, presentation and disclosure of leasing arrangements, which is effective in January 2019, Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy 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.

GUARANTEES

Dominion Energy primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the provisions of FASB guidance that dictate a guarantor’s accounting and disclosure requirements for guarantees, including indirect guarantees of indebtedness of others. In addition, Dominion Energy has provided a guarantee to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility. See Note 22 to the Consolidated Financial Statements for additional information, which information is incorporated herein by reference.

FUTURE ISSUES AND OTHER MATTERS

See Item 1. Business and Notes 13 and 22 to the Consolidated Financial Statements for additional information on various environmental, regulatory, legal and other matters that may impact future results of operations, financial condition and/or cash flows.

Environmental Matters

Dominion Energy 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.

ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES

Dominion Energy incurred $198 million, $200 million and $394 million of expenses (including accretion and depreciation) during, 2018, 2017 and 2016 respectively, in connection with environmental protection and monitoring activities. Dominion Energy expects these expenses to be approximately $191 million and $183 million in 2019 and 2020, respectively. In addition, capital expenditures related to environmental controls were $104 million, $201 million, and $191 million for 2018, 2017 and 2016, respectively. Dominion Energy expects these expenditures to be approximately $192 million and $203 million for 2019 and 2020, respectively.

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FUTURE ENVIRONMENTAL REGULATIONS

Air

In August 2018, the EPA proposed the Affordable Clean Energy rule as a replacement for the Clean Power Plan. The Affordable Clean Energy rule applies to fossil fuel-fired steam electric generating units greater than or equal to 25 MW, however, it does not apply to combustion turbines or units that burn biomass. The proposed rule includes unit-specific performance standards based on the degree of emission reduction levels achievable from unit efficiency improvements to be determined by the permitting agency. The Affordable Clean Energy rule would require states to develop plans within three years of the final rule to implement these performance standards. These state plans must be approved by the EPA. Given these developments and the associated federal and state regulatory and legal uncertainties, Dominion Energy cannot predict the potential financial statement impacts but believes the potential expenditures to comply could be material.

Climate Change

In December 2015, the Paris Agreement was formally adopted under the United Nations Framework Convention on Climate Change. A key element of the initial U.S. commitment to the agreement was the implementation of the Clean Power Plan, which the EPA has proposed to repeal. In June 2017, the Administration announced that the U.S. intends to file to withdraw from the Paris Agreement in 2019. Several states, including Virginia, subsequently announced a commitment to achieving the carbon reduction goals of the Paris Agreement. It is not possible at this time to predict the timing and impact of this withdrawal, or how any legal requirements in the U.S. at the federal, state or local levels pursuant to the Paris Agreement could impact the Companies’ customers or the business.

State Actions Related to Air and GHG Emissions

In August 2017, the Ozone Transport Commission released a draft model rule for control of NO_X emissions from natural gas pipeline compressor fuel-fire prime movers. States within the ozone transport region, including states in which Dominion Energy has natural gas operations, are expected to develop reasonably achievable control technology rules for existing sources based on the Ozone Transport Commission model rule. States outside of the Ozone Transport Commission may also consider the model rules in setting new reasonably achievable control technology standards.

In January 2018, the VDEQ published for comment a proposed state carbon regulation program linked to RGGI. In February 2019, the VDEQ proposed a revised rule with a 28 million ton initial carbon cap, which is 15% lower than the original proposal, based on revised modeling that uses projections of lower natural gas prices and additional solar capacity. A final rule is expected in mid-2019. Several other states in which Dominion Energy operates, including Pennsylvania, New York, Maryland and Ohio are developing or have announced plans to develop state-specific regulations to control GHG emissions, including methane. Dominion Energy cannot currently estimate the potential financial statement impacts related to these matters, but there could be a material impact to its financial condition and/or cash flows.

PHMSA Regulation

The most recent reauthorization of PHMSA included new provisions on historical records research, maximum-allowed operating pressure validation, use of automated or remote-controlled valves on new or replaced lines, increased civil penalties and evaluation of expanding integrity management beyond high-consequence areas. PHMSA has not yet issued new rulemaking on most of these items.

Dodd-Frank Act

The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The CEA, as amended by Title VII of the Dodd-Frank Act, requires certain over-the counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, may elect the end-user exception to the CEA’s clearing requirements. Dominion Energy has elected to exempt its swaps from the CEA’s clearing requirements. If, as a result of changes to the rulemaking process, Dominion Energy’s derivative activities are not exempted from clearing, exchange trading or margin requirements, it could be subject to higher costs due to decreased market liquidity or increased margin payments. In addition, Dominion Energy’s swap dealer counterparties may attempt to pass-through additional trading costs in connection with changes to or the elimination of rulemaking that implements Title VII of the Dodd-Frank Act. Due to the evolving rulemaking process, Dominion Energy is currently unable to assess the potential impact of the Dodd-Frank Act’s derivative-related provisions on its financial condition, results of operations or cash flows.

Virginia Legislation

In February 2019, legislation was passed by the Virginia General Assembly, and is awaiting signature by the Governor of Virginia, which would require any CCR unit located at Virginia Power’s Bremo, Chesapeake, Chesterfield or Possum Point power stations that stop accepting CCR prior to July 2019 be closed by removing the CCR to an approved landfill or through recycling for beneficial reuse. The legislation further would require that at least 6.8 million cubic yards of CCR be beneficially reused and that costs associated with the closure of these CCR units be recoverable through a rate adjustment clause approved by the Virginia Commission with a revenue requirement that cannot exceed $225 million in any 12-month period. While the impacts of this rule could be material to Dominion Energy and Virginia Power’s financial condition and/or cash flows, such rate adjustment clause would substantially mitigate any impact to Dominion Energy and Virginia Power’s results of operations.

Atlantic Coast Pipeline

In September 2014, Dominion Energy, along with Duke and Southern Company Gas, announced the formation of Atlantic Coast Pipeline. Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. During the third and fourth quarters of 2018, a FERC stop work order together with delays in obtaining permits necessary for construction and delays in construction due to judicial actions impacted the cost and schedule for the project. As a result project

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

cost estimates have increased from between $6.0 billion to $6.5 billion to between $7.0 billion to $7.5 billion, excluding financing costs. Atlantic Coast Pipeline expects to achieve a late 2020 in-service date for at least key segments of the project, while the remainder may extend into early 2021. Alternatively, if it takes longer to resolve the judicial issues, such as through appeal to the Supreme Court of the U.S., full in-service could extend to the end of 2021 with total project cost estimated to increase an additional $250 million, resulting in total project cost estimates of $7.25 billion to $7.75 billion excluding financing costs. Abnormal weather, work delays (including due to judicial or regulatory action) and other conditions may result in further cost or schedule modifications in the future, which could result in a material impact to Dominion Energy’s cash flows, financial position and/or results of operations.

North Anna

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it would require a Combined Construction Permit and Operating License from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In June 2017, the NRC issued the Combined Construction Permit and Operating License. Virginia Power has not yet committed to building a new nuclear unit at North Anna.

Other Matters

While management currently has no plans which may affect the carrying value of Millstone, based on potential future economic and other factors, including, but not limited to, market power prices, results of capacity auctions, legislative and regulatory solutions to ensure nuclear plants are fairly compensated for their carbon-free generation, and the impact of potential EPA carbon rules; there is risk that Millstone may be evaluated for an early retirement date. Should management make any decision on a potential early retirement date, the precise date and the resulting financial statement impacts, which could be material to Dominion Energy, may be affected by a number of factors, including any potential regulatory or legislative solutions, results of any transmission system reliability study assessments and decommissioning requirements, among other factors.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs of Item 7. MD&A. The reader’s attention is directed to those paragraphs and Item 1A. Risk Factors 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 Energy and Virginia Power’s electric operations and Dominion Energy and Dominion Energy 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 Energy 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 Energy Gas primarily holds commodity-based financial derivative instruments held for non-trading purposes associated with sales of NGLs.

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

A hypothetical 10% decrease in commodity prices would have resulted in a decrease in fair value of $6 million and $5 million of Dominion Energy’s commodity-based derivative instruments as of December 31, 2018 and December 31, 2017, respectively.

A hypothetical 10% decrease in commodity prices of Virginia Power’s commodity-based derivative instruments would have resulted in a decrease in fair value of $51 million as of both December 31, 2018 and December 31, 2017, respectively.

A hypothetical 10% increase in commodity prices of Dominion Energy Gas’ commodity-based financial derivative instruments would have resulted in a decrease in fair value of $1 million and $4 million as of December 31, 2018 and December 31, 2017, 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.

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 Dominion Energy, a hypothetical 10%

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increase in market interest rates would result in a $24 million and $12 million decrease in earnings at December 31, 2018 and December 31, 2017, respectively. For variable rate debt outstanding for Virginia Power and Dominion Energy Gas, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at December 31, 2018 or December 31, 2017.

The Companies also use interest rate derivatives, including forward-starting swaps, as cash flow hedges of forecasted interest payments. As of December 31, 2018, Dominion Energy, Virginia Power and Dominion Energy Gas had $5.9 billion, $1.9 billion and $1.1 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $147 million, $94 million and $17 million, respectively, in the fair value of Dominion Energy, Virginia Power and Dominion Energy Gas’ interest rate derivatives at December 31, 2018. As of December 31, 2017, Dominion Energy and Virginia Power had $3.5 billion and $1.5 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $86 million and $67 million, respectively, in the fair value of Dominion Energy and Virginia Power’s interest rate derivatives at December 31, 2017. Dominion Energy Gas had no interest rate derivatives outstanding at December 31, 2017.

During 2016, Dominion Energy Gas entered into foreign currency swaps with the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. As of December 31, 2018 and December 31, 2017, Dominion Energy and Dominion Energy Gas had $280 million (€ 250 million) in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $8 million and $6 million, in the fair value of Dominion Energy Gas’ foreign currency swaps at December 31, 2018 and December 31, 2017, respectively.

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 Energy 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 the Consolidated Balance Sheets at fair value.

Dominion Energy recognized net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $135 million for the year ended December 31, 2018. Dominion Energy recognized net realized gains (including

investment income) on nuclear decommissioning trust investments of $167 million for the year ended December 31, 2017. 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 Energy recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on debt investments of $36 million for the year ended December 31, 2018 and recorded a net increase in unrealized gains on debt and equity investments of $462 million for the year ended December 31, 2017.

Virginia Power recognized net investment losses (including investment income) on nuclear decommissioning trust investments of $44 million for the year ended December 31, 2018. Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $76 million for the year ended December 31, 2017. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on debt investments of $21 million for the year ended December 31, 2018 and recorded a net increase in unrealized gains on debt and equity investments of $216 million for the year ended December 31, 2017.

Dominion Energy sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power and Dominion Energy Gas employees participate in these plans. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $(605) million and $1.6 billion in 2018 and 2017, respectively, versus expected returns of $806 million and $767 million, respectively. Dominion Energy Gas’ pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual returns (losses) of $(129) million and $335 million in 2018 and 2017, respectively, versus expected returns of $178 million and $165 million, respectively. 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 such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion Energy’s plan assets would result in an increase in net periodic cost of $19 million as of both December 31, 2018 and 2017, for pension benefits and $4 million as of both December 31, 2018 and 2017, for other postretirement benefits. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion Energy Gas’ plan assets, for employees represented by collective bargaining units, would result in an increase in net periodic cost of $4 million as of both December 31, 2018 and 2017, for pension benefits and $1 million as of both December 31, 2018 and 2017, for other postretirement benefits.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Risk Management Policies

The Companies have established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion Energy has established an independent function at the corporate level to monitor compliance with the credit and commodity risk management policies of all subsidiaries, including Virginia Power and Dominion Energy Gas. Dominion Energy maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and

the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion Energy also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and the Companies’ December 31, 2018 provision for credit losses, management believes that it is unlikely that a material adverse effect on the Companies’ financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

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Item 8. Financial Statements and Supplementary Data

	Page Number
Dominion Energy, Inc.
Report of Independent Registered Public Accounting Firm		71
Consolidated Statements of Income for the years ended December  31, 2018, 2017 and 2016		72
Consolidated Statements of Comprehensive Income for the years ended December  31, 2018, 2017 and 2016		73
Consolidated Balance Sheets at December 31, 2018 and 2017		74
Consolidated Statements of Equity at December  31, 2018, 2017 and 2016 and for the years then ended		76
Consolidated Statements of Cash Flows for the years ended December  31, 2018, 2017 and 2016		77
Virginia Electric and Power Company
Report of Independent Registered Public Accounting Firm		79
Consolidated Statements of Income for the years ended December  31, 2018, 2017 and 2016		80
Consolidated Statements of Comprehensive Income for the years ended December  31, 2018, 2017 and 2016		81
Consolidated Balance Sheets at December 31, 2018 and 2017		82
Consolidated Statements of Common Shareholder’s Equity at December  31, 2018, 2017 and 2016 and for the years then ended		84
Consolidated Statements of Cash Flows for the years ended December  31, 2018, 2017 and 2016		85
Dominion Energy Gas Holdings, LLC
Report of Independent Registered Public Accounting Firm		87
Consolidated Statements of Income for the years ended December  31, 2018, 2017 and 2016		88
Consolidated Statements of Comprehensive Income for the years ended December  31, 2018, 2017 and 2016		89
Consolidated Balance Sheets at December 31, 2018 and 2017		90
Consolidated Statements of Equity at December  31, 2018, 2017 and 2016 and for the years then ended		92
Consolidated Statements of Cash Flows for the years ended December  31, 2018, 2017 and 2016		93
Combined Notes to Consolidated Financial Statements		95

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Dominion Energy, Inc.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Dominion Energy, Inc. and subsidiaries (“Dominion Energy”) at December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Dominion Energy at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), Dominion Energy’s internal control over financial reporting at December 31, 2018, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2019, expressed an unqualified opinion on Dominion Energy’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of Dominion Energy’s management. Our responsibility is to express an opinion on Dominion Energy’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Dominion Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2019

We have served as Dominion Energy’s auditor since 1988.

71

Dominion Energy, Inc.

Consolidated Statements of Income

Year Ended December 31,	2018			2017			2016
(millions, except per share amounts)
Operating Revenue(1)	$	13,366		$	12,586		$	11,737
Operating Expenses
Electric fuel and other energy-related purchases		2,814			2,301			2,333
Purchased electric capacity		122			6			99
Purchased gas		645			701			459
Other operations and maintenance		3,458			3,200			3,279
Depreciation, depletion and amortization		2,000			1,905			1,559
Other taxes		703			668			596
Impairment of assets and related charges		403			15			4
Gains on sales of assets		(380	)		(147	)		(40	)
Total operating expenses		9,765			8,649			8,289
Income from operations		3,601			3,937			3,448
Other income(1)		1,021			358			429
Interest and related charges		1,493			1,205			1,010
Income from operations including noncontrolling interests before income tax expense (benefit)		3,129			3,090			2,867
Income tax expense (benefit)		580			(30	)		655
Net Income Including Noncontrolling Interests		2,549			3,120			2,212
Noncontrolling Interests		102			121			89
Net Income Attributable to Dominion Energy	$	2,447		$	2,999		$	2,123
Earnings Per Common Share
Net income attributable to Dominion Energy—Basic	$	3.74		$	4.72		$	3.44
Net income attributable to Dominion Energy—Diluted	$	3.74		$	4.72		$	3.44

(1) See Note 9 for amounts attributable to related parties.

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

72

Dominion Energy, Inc.

Consolidated Statements of Comprehensive Income

Year Ended December 31,	2018			2017			2016
(millions)
Net Income Including Noncontrolling Interests	$	2,549		$	3,120		$	2,212
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $(10), $(3) and $(37) tax		30			8			55
Changes in unrealized net gains (losses) on investment securities, net of $5, $(121) and $(53) tax		(18	)		215			93
Changes in net unrecognized pension and other postretirement benefit costs, net of $75, $32 and $189 tax		(215	)		(69	)		(319	)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of $(35), $18 and $100 tax		102			(29	)		(159	)
Net realized (gains) losses on investment securities, net of $(2), $21 and $15 tax		5			(37	)		(28	)
Net pension and other postretirement benefit costs, net of $(21), $(32) and $(22) tax		78			50			34
Changes in other comprehensive gains (losses) from equity method investees, net of $(1), $(2) and $— tax		1			3			(1	)
Total other comprehensive income (loss)		(17	)		141			(325	)
Comprehensive income including noncontrolling interests		2,532			3,261			1,887
Comprehensive income attributable to noncontrolling interests		103			122			89
Comprehensive income attributable to Dominion Energy	$	2,429		$	3,139		$	1,798

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

73

Dominion Energy, Inc.

Consolidated Balance Sheets

At December 31,	2018			2017
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	268		$	120
Customer receivables (less allowance for doubtful accounts of $14 and $17)		1,749			1,660
Other receivables (less allowance for doubtful accounts of $4 and $2)(1)		331			126
Inventories:
Materials and supplies		1,039			1,049
Fossil fuel		287			328
Gas stored		92			100
Prepayments		265			260
Regulatory assets		496			294
Other		634			397
Total current assets		5,161			4,334
Investments
Nuclear decommissioning trust funds		4,938			5,093
Investment in equity method affiliates		1,278			1,544
Other		344			327
Total investments		6,560			6,964
Property, Plant and Equipment
Property, plant and equipment		76,578			74,823
Accumulated depreciation, depletion and amortization		(22,018	)		(21,065	)
Total property, plant and equipment, net		54,560			53,758
Deferred Charges and Other Assets
Goodwill		6,410			6,405
Pension and other postretirement benefit assets		1,279			1,378
Intangible assets, net		670			685
Regulatory assets		2,676			2,480
Other		598			581
Total deferred charges and other assets		11,633			11,529
Total assets	$	77,914		$	76,585

(1) See Note 9 for amounts attributable to related parties.

74

At December 31,	2018			2017
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	3,624		$	3,078
Credit facility borrowings		73			—
Short-term debt		334			3,298
Accounts payable		914			875
Accrued interest, payroll and taxes		836			848
Other		1,866			1,537
Total current liabilities		7,647			9,636
Long-Term Debt
Long-term debt		26,328			25,588
Junior subordinated notes		3,430			3,981
Remarketable subordinated notes		1,386			1,379
Total long-term debt		31,144			30,948
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		5,116			4,523
Regulatory liabilities		6,840			6,916
Asset retirement obligations		2,250			2,169
Pension and other postretirement benefit liability		2,328			2,160
Other(1)		541			863
Total deferred credits and other liabilities		17,075			16,631
Total liabilities		55,866			57,215
Commitments and Contingencies (see Note 22)
Equity
Common stock – no par(2)		12,588			9,865
Retained earnings		9,219			7,936
Accumulated other comprehensive loss		(1,700	)		(659	)
Total common shareholders’ equity		20,107			17,142
Noncontrolling interests		1,941			2,228
Total equity		22,048			19,370
Total liabilities and equity	$	77,914		$	76,585

(1) See Note 9 for amounts attributable to related parties.

(2) 1 billion shares authorized; 681 million shares and 645 million shares outstanding at December 31, 2018 and 2017, respectively.

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

75

Dominion Energy, Inc.

Consolidated Statements of Equity

	Common Stock					Dominion Energy Shareholders
	Shares		Amount			Retained Earnings			Accumulated Other Comprehensive Income (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							2,123						2,123			89			2,212
Contributions from SunEdison to Four Brothers and Three Cedars													—			189			189
Sale of interest in merchant solar projects				22									22			117			139
Sale of Dominion Energy Midstream common units—net of offering costs													—			482			482
Sale of Dominion Energy Midstream convertible preferred units—net of offering costs													—			490			490
Purchase of Dominion Energy Midstream common units				(3	)								(3	)		(14	)		(17	)
Issuance of common stock		32		2,152									2,152						2,152
Stock awards (net of change in unearned compensation)				14									14						14
Present value of stock purchase contract payments related to RSNs(1)				(191	)								(191	)					(191	)
Tax effect of Dominion Energy Questar Pipeline contribution to Dominion Energy Midstream				(116	)								(116	)					(116	)
Dividends ($2.80 per common share) and distributions							(1,727	)					(1,727	)		(62	)		(1,789	)
Other comprehensive loss, net of tax										(325	)		(325	)					(325	)
Other				(8	)								(8	)		6			(2	)
December 31, 2016		628	$	8,550		$	6,854		$	(799	)	$	14,605		$	2,235		$	16,840
Net income including noncontrolling interests							2,999						2,999			121			3,120
Contributions from NRG to Four Brothers and Three Cedars													—			9			9
Issuance of common stock		17		1,302									1,302						1,302
Sale of Dominion Energy Midstream common units—net of offering costs													—			18			18
Stock awards (net of change in unearned compensation)				22									22						22
Dividends ($3.035 per common share) and distributions							(1,931	)					(1,931	)		(156	)		(2,087	)
Other comprehensive income, net of tax										140			140			1			141
Other				(9	)		14						5						5
December 31, 2017		645	$	9,865		$	7,936		$	(659	)	$	17,142		$	2,228		$	19,370
Cumulative-effect of changes in accounting principles				(127	)		1,029			(1,023	)		(121	)		127			6
Net income including noncontrolling interests							2,447						2,447			102			2,549
Issuance of common stock		36		2,461									2,461						2,461
Sale of Dominion Energy Midstream common units—net of offering costs													—			4			4
Remeasurement of noncontrolling interest in Dominion Energy Midstream				375									375			(375	)		—
Stock awards (net of change in unearned compensation)				22									22						22
Dividends ($3.34 per common share) and distributions							(2,185	)					(2,185	)		(146	)		(2,331	)
Other comprehensive income (loss), net of tax										(18	)		(18	)		1			(17	)
Other				(8	)		(8	)					(16	)					(16	)
December 31, 2018		681	$	12,588		$	9,219		$	(1,700	)	$	20,107		$	1,941		$	22,048

(1) See Note 17 for further information.

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

76

Dominion Energy, Inc.

Consolidated Statements of Cash Flows

Year Ended December 31,	2018			2017			2016
(millions)
Operating Activities
Net income including noncontrolling interests	$	2,549		$	3,120		$	2,212
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation, depletion and amortization (including nuclear fuel)		2,280			2,202			1,849
Deferred income taxes and investment tax credits		517			(3	)		725
Current income tax for Dominion Energy Questar Pipeline contribution to Dominion Energy Midstream		—			—			(212	)
Proceeds from assignment of tower rental portfolio		—			91			—
Contribution to pension plan		—			(75	)		—
Gains on sales of assets and equity method investments		(1,006	)		(148	)		(50	)
Provision for rate credits to electric utility customers		77			—			—
Charges associated with equity method investments		—			158			—
Charges associated with future ash pond and landfill closure costs		81			—			197
Impairment of assets and related charges		395			15			4
Net (gains) losses on nuclear decommissioning trusts funds and other investments		102			(117	)		(96	)
Other adjustments		19			33			8
Changes in:
Accounts receivable		(110	)		(103	)		(286	)
Inventories		(29	)		15			1
Deferred fuel and purchased gas costs, net		(247	)		(71	)		54
Prepayments		(51	)		(62	)		21
Accounts payable		67			(89	)		97
Accrued interest, payroll and taxes		(12	)		64			203
Margin deposit assets and liabilities		—			(10	)		(66	)
Net realized and unrealized changes related to derivative activities		181			44			(335	)
Asset retirement obligations		(35	)		(94	)		(61	)
Pension and other postretirement benefits		(114	)		(177	)		(152	)
Other operating assets and liabilities		109			(291	)		38
Net cash provided by operating activities		4,773			4,502			4,151
Investing Activities
Plant construction and other property additions (including nuclear fuel)		(4,254	)		(5,504	)		(6,085	)
Acquisition of Dominion Energy Questar, net of cash acquired		—			—			(4,381	)
Acquisition of solar development projects		(151	)		(405	)		(40	)
Proceeds from sales of securities		1,804			1,831			1,422
Purchases of securities		(1,894	)		(1,940	)		(1,504	)
Proceeds from the sale of certain retail energy marketing assets		54			68			—
Proceeds from sales of assets and equity method investments		2,379			—			—
Proceeds from assignment of shale development rights		109			70			10
Contributions to equity method affiliates		(428	)		(370	)		(198	)
Distributions from equity method affiliates		36			275			2
Other		(13	)		33			83
Net cash used in investing activities		(2,358	)		(5,942	)		(10,691	)
Financing Activities
Issuance (repayment) of short-term debt, net		(2,964	)		143			(654	)
Issuance of short-term notes		1,450			—			1,200
Repayment and repurchase of short-term notes		(1,450	)		(250	)		(1,800	)
Issuance and remarketing of long-term debt		6,362			3,880			7,722
Repayment and repurchase of long-term debt (including redemption premiums)		(5,682	)		(1,572	)		(1,610	)
Credit facility borrowings		73			—			—
Net proceeds from issuance of Dominion Energy Midstream common units		4			18			482
Net proceeds from issuance of Dominion Energy Midstream preferred units		—			—			490
Proceeds from sale of interest in merchant solar projects		—			—			117
Contributions from NRG and SunEdison to Four Brothers and Three Cedars		—			9			189
Issuance of common stock		2,461			1,302			2,152
Common dividend payments		(2,185	)		(1,931	)		(1,727	)
Other		(278	)		(296	)		(331	)
Net cash provided by (used in) financing activities		(2,209	)		1,303			6,230
Increase (decrease) in cash, restricted cash and equivalents		206			(137	)		(310	)
Cash, restricted cash and equivalents at beginning of year		185			322			632
Cash, restricted cash and equivalents at end of year	$	391		$	185		$	322
Supplemental Cash Flow Information
Cash paid during the year for:
Interest and related charges, excluding capitalized amounts	$	1,362		$	1,083		$	905
Income taxes		89			9			145
Significant noncash investing and financing activities:(1)(2)
Accrued capital expenditures		307			343			427
Receivables from sales of assets and equity method investments		159			—			—
Guarantee provided by equity method affiliate		—			30			—

(1) See Note 9 for noncash activities related to equity method investments.

(2) See Note 19 for noncash activities related to the remeasurement of Dominion Energy’s noncontrolling interest in Dominion Energy Midstream.

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

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78

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Virginia Electric and Power Company

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Energy, Inc.) and subsidiaries (“Virginia Power”) at December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Virginia Power at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of Virginia Power’s management. Our responsibility is to express an opinion on Virginia Power’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Virginia Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Virginia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Virginia Power’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2019

We have served as Virginia Power’s auditor since 1988.

79

Virginia Electric and Power Company

Consolidated Statements of Income

Year Ended December 31,	2018		2017		2016
(millions)
Operating Revenue(1)	$	7,619	$	7,556	$	7,588
Operating Expenses
Electric fuel and other energy-related purchases(1)		2,318		1,909		1,973
Purchased electric capacity		122		6		99
Other operations and maintenance:
Affiliated suppliers		305		309		310
Other		1,371		1,169		1,547
Depreciation and amortization		1,132		1,141		1,025
Other taxes		300		290		284
Total operating expenses		5,548		4,824		5,238
Income from operations		2,071		2,732		2,350
Other income		22		76		56
Interest and related charges(1)		511		494		461
Income from operations before income tax expense		1,582		2,314		1,945
Income tax expense		300		774		727
Net Income	$	1,282	$	1,540	$	1,218

(1) See Note 24 for amounts attributable to affiliates.

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

80

Virginia Electric and Power Company

Consolidated Statements of Comprehensive Income

Year Ended December 31,	2018		2017			2016
(millions)
Net Income	$	1,282	$	1,540		$	1,218
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $(1), $3 and $1 tax		1		(5	)		(2	)
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds, net of $—, $(16) and $(7) tax		—		24			11
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of $—, $— and $— tax		1		1			1
Net realized (gains) losses on nuclear decommissioning trust funds, net of $—, $3 and $2 tax		—		(4	)		(4	)
Other comprehensive income		2		16			6
Comprehensive income	$	1,284	$	1,556		$	1,224

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

81

Virginia Electric and Power Company

Consolidated Balance Sheets

At December 31,	2018			2017
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	29		$	14
Customer receivables (less allowance for doubtful accounts of $9 and $10)		999			951
Other receivables (less allowance for doubtful accounts of $3 and $1)		76			64
Affiliated receivables		101			3
Inventories (average cost method):
Materials and supplies		550			531
Fossil fuel		287			319
Prepayments		28			27
Regulatory assets		424			205
Other(1)		77			110
Total current assets		2,571			2,224
Investments
Nuclear decommissioning trust funds		2,369			2,399
Other		3			3
Total investments		2,372			2,402
Property, Plant and Equipment
Property, plant and equipment		44,524			42,329
Accumulated depreciation and amortization		(14,003	)		(13,277	)
Total property, plant and equipment, net		30,521			29,052
Deferred Charges and Other Assets
Pension and other postretirement benefit assets(1)		254			199
Intangible assets		250			233
Regulatory assets		737			810
Other(1)		175			219
Total deferred charges and other assets		1,416			1,461
Total assets	$	36,880		$	35,139

(1) See Note 24 for amounts attributable to affiliates.

82

At December 31,	2018			2017
(millions)
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	350		$	850
Short-term debt		314			542
Accounts payable		339			361
Payables to affiliates		209			125
Affiliated current borrowings		224			33
Accrued interest, payroll and taxes		248			256
Asset retirement obligations		245			216
Regulatory liabilities		299			127
Other(1)		587			410
Total current liabilities		2,815			2,920
Long-Term Debt		11,321			10,496
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		3,017			2,728
Asset retirement obligations		1,200			1,149
Regulatory liabilities		4,647			4,760
Pension and other postretirement benefit liability(1)		632			505
Other		201			357
Total deferred credits and other liabilities		9,697			9,499
Total liabilities		23,833			22,915
Commitments and Contingencies (see Note 22)
Common Shareholder’s Equity
Common stock – no par(2)		5,738			5,738
Other paid-in capital		1,113			1,113
Retained earnings		6,208			5,311
Accumulated other comprehensive income (loss)		(12	)		62
Total common shareholder’s equity		13,047			12,224
Total liabilities and shareholder’s equity	$	36,880		$	35,139

(1) See Note 24 for amounts attributable to affiliates.

(2) 500,000 shares authorized; 274,723 shares outstanding at December 31, 2018 and 2017.

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

83

Virginia Electric and Power Company

Consolidated Statements of Common Shareholder’s Equity

	Common Stock				Other Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	Shares		Amount
(millions, except for shares)	(thousands)
December 31, 2015		275	$	5,738	$	1,113	$	3,750		$	40		$	10,641
Net income								1,218						1,218
Other comprehensive income, net of tax											6			6
December 31, 2016		275		5,738		1,113		4,968			46			11,865
Net income								1,540						1,540
Dividends								(1,199	)					(1,199	)
Other comprehensive income, net of tax											16			16
Other								2						2
December 31, 2017		275		5,738		1,113		5,311			62			12,224
Cumulative-effect of changes in accounting principles								79			(76	)		3
Net income								1,282						1,282
Dividends								(464	)					(464	)
Other comprehensive income, net of tax											2			2
December 31, 2018		275	$	5,738	$	1,113	$	6,208		$	(12	)	$	13,047

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

84

Virginia Electric and Power Company

Consolidated Statements of Cash Flows

Year Ended December 31,	2018			2017			2016
(millions)
Operating Activities
Net income	$	1,282		$	1,540		$	1,218
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		1,309			1,333			1,210
Deferred income taxes and investment tax credits		224			269			469
Proceeds from assignment of rental portfolio		—			91			—
Charges associated with future ash pond and landfill closure costs		81			—			197
Provision for rate credits to customers		77			—			—
Other adjustments		(21	)		(36	)		(16	)
Changes in:
Accounts receivable		(60	)		(27	)		(65	)
Affiliated receivables and payables		(14	)		125			220
Inventories		13			3			20
Prepayments		(1	)		3			8
Deferred fuel expenses, net		(269	)		(59	)		69
Accounts payable		(26	)		(42	)		25
Accrued interest, payroll and taxes		(8	)		17			49
Net realized and unrealized changes related to derivative activities		119			13			(153	)
Asset retirement obligations		(54	)		(88	)		(59	)
Other operating assets and liabilities		188			(181	)		77
Net cash provided by operating activities		2,840			2,961			3,269
Investing Activities
Plant construction and other property additions		(2,228	)		(2,496	)		(2,489	)
Purchases of nuclear fuel		(173	)		(192	)		(153	)
Acquisition of solar development projects		(141	)		(41	)		(7	)
Purchases of securities		(925	)		(884	)		(775	)
Proceeds from sales of securities		887			849			733
Other		(63	)		(41	)		(33	)
Net cash used in investing activities		(2,643	)		(2,805	)		(2,724	)
Financing Activities
Issuance (repayment) of short-term debt, net		(228	)		477			(1,591	)
Issuance (repayment) of affiliated current borrowings, net		191			(229	)		(114	)
Issuance and remarketing of long-term debt		1,300			1,500			1,688
Repayment and repurchase of long-term debt		(964	)		(681	)		(517	)
Common dividend payments to parent		(464	)		(1,199	)		—
Other		(18	)		(11	)		(18	)
Net cash used in financing activities		(183	)		(143	)		(552	)
Increase (decrease) in cash, restricted cash and equivalents		14			13			(7	)
Cash, restricted cash and equivalents at beginning of year		24			11			18
Cash, restricted cash and equivalents at end of year	$	38		$	24		$	11
Supplemental Cash Flow Information
Cash paid during the year for:
Interest and related charges, excluding capitalized amounts	$	498		$	458		$	435
Income taxes		128			362			79
Significant noncash investing activities:
Accrued capital expenditures		204			169			256

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Dominion Energy Gas Holdings, LLC

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Dominion Energy Gas Holdings, LLC (a wholly-owned subsidiary of Dominion Energy, Inc.) and subsidiaries (“Dominion Energy Gas”) at December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Dominion Energy Gas at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of Dominion Energy Gas’ management. Our responsibility is to express an opinion on Dominion Energy Gas’ consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Dominion Energy Gas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Dominion Energy Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Dominion Energy Gas’ internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2019

We have served as Dominion Energy Gas’ auditor since 2012.

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Dominion Energy Gas Holdings, LLC

Consolidated Statements of Income

Year Ended December 31,	2018			2017			2016
(millions)
Operating Revenue(1)	$	1,940		$	1,814		$	1,638
Operating Expenses
Purchased gas(1)		40			132			109
Other energy-related purchases		135			21			12
Other operations and maintenance:
Affiliated suppliers		94			87			81
Other(1)		665			578			514
Depreciation and amortization		244			227			204
Other taxes		200			185			170
Impairment of assets and related charges		346			16			—
Gains on sales of assets		(119	)		(70	)		(45	)
Total operating expenses		1,605			1,176			1,045
Income from operations		335			638			593
Earnings from equity method investee		24			21			21
Other income		133			104			87
Interest and related charges(1)		105			97			94
Income from operations before income tax expense		387			666			607
Income tax expense		86			51			215
Net Income	$	301		$	615		$	392

(1) See Note 24 for amounts attributable to related parties.

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

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Dominion Energy Gas Holdings, LLC

Consolidated Statements of Comprehensive Income

Year Ended December 31,	2018			2017			2016
(millions)
Net Income	$	301		$	615		$	392
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $6, $(3) and $10 tax		(17	)		5			(16	)
Changes in net unrecognized pension benefit (costs) , net of $20, $(8) and $14 tax		(52	)		20			(20	)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of $(7), $3 and $(6) tax		20			(4	)		9
Net pension and other postretirement benefit costs, net of $(2), $(2) and $(2) tax		4			4			3
Other comprehensive income (loss)		(45	)		25			(24	)
Comprehensive income	$	256		$	640		$	368

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

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Dominion Energy Gas Holdings, LLC

Consolidated Balance Sheets

At December 31,	2018			2017
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	10		$	4
Customer receivables (less allowance for doubtful accounts of less than $1 and $1)(1)		309			297
Other receivables (less allowance for doubtful accounts of $2 and $1)(1)		17			15
Affiliated receivables		10			10
Inventories:
Materials and supplies		53			55
Gas stored		12			9
Prepayments		116			112
Gas imbalances(1)		162			46
Other(1)		58			52
Total current assets		747			600
Investments		93			97
Property, Plant and Equipment
Property, plant and equipment		11,238			11,173
Accumulated depreciation and amortization		(2,971	)		(3,018	)
Total property, plant and equipment, net		8,267			8,155
Deferred Charges and Other Assets
Goodwill		547			542
Intangible assets, net		109			109
Pension and other postretirement benefit assets(1)		1,775			1,828
Regulatory assets		727			511
Other(1)		86			98
Total deferred charges and other assets		3,244			3,088
Total assets	$	12,351		$	11,940

(1) See Note 24 for amounts attributable to related parties.

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At December 31,	2018			2017
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	449		$	—
Short-term debt		10			629
Accounts payable		196			193
Payables to affiliates		65			62
Affiliated current borrowings		218			18
Accrued interest, payroll and taxes		265			250
Other(1)		198			189
Total current liabilities		1,401			1,341
Long-Term Debt		3,609			3,570
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		1,465			1,454
Regulatory liabilities		1,285			1,227
Other(1)		194			185
Total deferred credits and other liabilities		2,944			2,866
Total liabilities		7,954			7,777
Commitments and Contingencies (see Note 22)
Equity
Membership interests		4,566			4,261
Accumulated other comprehensive loss		(169	)		(98	)
Total equity		4,397			4,163
Total liabilities and equity	$	12,351		$	11,940

(1) See Note 24 for amounts attributable to related parties.

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

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Dominion Energy Gas Holdings, LLC

Consolidated Statements of Equity

	Membership Interests			Accumulated Other Comprehensive Income (Loss)			Total
(millions)
December 31, 2015	$	3,417		$	(99	)	$	3,318
Net income		392						392
Distributions		(150	)					(150	)
Other comprehensive loss, net of tax					(24	)		(24	)
December 31, 2016		3,659			(123	)		3,536
Net income		615						615
Distributions		(15	)					(15	)
Other comprehensive income, net of tax					25			25
Other		2						2
December 31, 2017		4,261			(98	)		4,163
Cumulative-effect of changes in accounting principles		29			(26	)		3
Net income		301						301
Distributions		(25	)					(25	)
Other comprehensive loss, net of tax					(45	)		(45	)
December 31, 2018	$	4,566		$	(169	)	$	4,397

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

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Dominion Energy Gas Holdings, LLC

Consolidated Statements of Cash Flows

Year Ended December 31,	2018			2017			2016
(millions)
Operating Activities
Net income	$	301		$	615		$	392
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		244			227			204
Deferred income taxes and investment tax credits		33			27			238
Gains on sales of assets		(109	)		(70	)		(50	)
Impairment of assets and related charges		348			15			—
Other adjustments		(7	)		(7	)		(6	)
Changes in:
Accounts receivable		(14	)		(17	)		(68	)
Affiliated receivables and payables		3			40			88
Inventories		(1	)		6			8
Prepayments		(4	)		(18	)		(6	)
Accounts payable		(5	)		(17	)		15
Accrued interest, payroll and taxes		15			24			42
Pension and other postretirement benefits		(155	)		(143	)		(141	)
Other operating assets and liabilities		(17	)		(16	)		(68	)
Net cash provided by operating activities		632			666			648
Investing Activities
Plant construction and other property additions		(772	)		(778	)		(854	)
Proceeds from sale of equity method investment in Iroquois		—			—			7
Proceeds from assignments of shale development rights		109			70			10
Other		(16	)		(19	)		(12	)
Net cash used in investing activities		(679	)		(727	)		(849	)
Financing Activities
Issuance (repayment) of short-term debt, net		(619	)		169			69
Issuance (repayment) of affiliated current borrowings, net		200			(100	)		23
Issuance of long-term debt		500			—			680
Repayment of long-term debt		—			—			(400	)
Distribution payments to parent		(25	)		(15	)		(150	)
Other		(5	)		(6	)		(5	)
Net cash provided by financing activities		51			48			217
Increase (decrease) in cash, restricted cash and equivalents		4			(13	)		16
Cash, restricted cash and equivalents at beginning of year		30			43			27
Cash, restricted cash and equivalents at end of year	$	34		$	30		$	43
Supplemental Cash Flow Information
Cash paid (received) during the year for:
Interest and related charges, excluding capitalized amounts	$	95		$	89		$	81
Income taxes		79			9			(92	)
Significant noncash investing activities:
Accrued capital expenditures		38			38			59

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

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Combined Notes to Consolidated Financial Statements

NOTE 1. NATURE OF OPERATIONS

Dominion Energy, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Energy Gas. Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s stock is owned by Dominion Energy. Dominion Energy 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. All of Dominion Energy Gas’ membership interests are held by Dominion Energy. The SCANA Combination was completed in January 2019. See Note 3 for a description of operations acquired in the SCANA Combination.

Dominion Energy’s operations also include the Cove Point LNG Facility, Cove Point Pipeline, Liquefaction Project, an equity investment in Atlantic Coast Pipeline and regulated gas transportation and distribution operations primarily in the eastern and Rocky Mountain regions of the U.S. Dominion Energy’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations.

At December 31, 2018, Dominion Energy owned the general partner, 60.9% of the common units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owned a preferred equity interest and the general partner interest in Cove Point, DECG, Dominion Energy Questar Pipeline and a 25.93% noncontrolling partnership interest in Iroquois. In January 2019, Dominion Energy acquired all outstanding partnership interests not owned by Dominion Energy and Dominion Energy Midstream became a wholly-owned subsidiary of Dominion Energy. At December 31, 2018, the public’s ownership interest in Dominion Energy Midstream is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements.

Through December 2018, Dominion Energy managed its daily operations through three primary operating segments: Power Delivery, Power Generation and Gas Infrastructure. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt). In addition, Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. Subsequent to the SCANA Combination, Dominion Energy manages the operations of SCANA through an additional operating segment, Southeast Energy.

Virginia Power manages its daily operations through two primary operating segments: Power Delivery and Power Generation. It also reports a Corporate and Other segment that 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.

Dominion Energy Gas manages its daily operations through one primary operating segment: Gas Infrastructure. It also reports a Corporate and Other segment that primarily includes specific items attributable to its 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 Energy Gas as a result of Dominion Energy’s basis in the net assets contributed.

See Note 25 for further discussion of the Companies’ operating segments.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES

General

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, expenses and cash flows for the periods presented. Actual results may differ from those estimates.

The Companies’ 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. At December 31, 2018, Dominion Energy 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. In August 2018, NRG’s ownership interest in Four Brothers and Three Cedars was transferred to GIP. GIP’s ownership interest in Four Brothers and Three Cedars, Terra Nova Renewable Partners’ 33% interest in certain of Dominion Energy’s merchant solar projects and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019), is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion Energy’s remaining 67% ownership in certain merchant projects upon the occurrence of certain events, none of which are expected to occur in 2019.

The Companies report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements.

The Companies consider acquisitions or dispositions in which substantially all of the fair value of the gross assets acquired or disposed of is concentrated into a single identifiable asset or group of similar identifiable assets to be an acquisition or a disposition of an asset, rather than a business. See Notes 3 and 10 for further information on such transactions.

Dominion Energy maintains pension and other postretirement benefit plans. Virginia Power and Dominion Energy Gas participate in certain of these plans. See Note 21 for further information on these plans.

Certain amounts in the Companies’ 2017 and 2016 Consolidated Financial Statements and Notes have been reclassified to

95

Combined Notes to Consolidated Financial Statements, Continued

conform to the 2018 presentation for comparative purposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.

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

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Dominion Energy and Virginia Power collect sales, consumption and consumer utility taxes and Dominion Energy Gas collects sales taxes; however, these amounts are excluded from revenue. Dominion Energy’s customer receivables at December 31, 2018 and 2017 included $626 million and $661 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 2018 and 2017 included $392 million and $400 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers. Dominion Energy Gas’ customer receivables at December 31, 2018 and 2017 included $131 million and $121 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas delivered but not yet billed to its customers. See Note 24 for amounts attributable to related parties.

The primary types of sales and service activities reported as operating revenue for Dominion Energy, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:

REVENUE FROM CONTRACTS WITH CUSTOMERS

• Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

• Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated hedging activity;

• Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;

• Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties and associated hedging activity;

• Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

• Nonregulated gas transportation and storage sales consist primarily of LNG terminalling services;

• Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities; and

• Other nonregulated revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity. Other nonregulated revenue also includes services performed for Atlantic Coast Pipeline, sales of energy-related products

and services from Dominion Energy’s retail energy marketing operations, service concession arrangements and gas processing and handling revenue.

OTHER REVENUE

• Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

The primary types of sales and service activities reported as operating revenue for Dominion Energy, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:

• Regulated electric sales consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

• Nonregulated electric sales consisted primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;

• Regulated gas sales consisted primarily of state- and FERC-regulated natural gas sales and related distribution services and associated derivative activity;

• Nonregulated gas sales consisted primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity;

• Gas transportation and storage sales consisted primarily of FERC-regulated sales of transmission and storage services. Also included were state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services; and

• Other revenue consisted primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also included miscellaneous service revenue from electric and gas distribution operations, sales of energy-related products and services from Dominion Energy’s retail energy marketing operations and gas processing and handling revenue.

The primary types of sales and service activities reported as operating revenue for Virginia Power, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:

REVENUE FROM CONTRACTS WITH CUSTOMERS

• Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services;

• Other regulated revenue consists primarily of sales of excess capacity and other commodities and miscellaneous service revenue from electric distribution operations; and

• Other nonregulated revenue consists primarily of sales to non-jurisdictional customers from certain solar facilities, revenue from renting space on certain electric transmission poles and distribution towers and service concession arrangements.

OTHER REVENUE

• Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

96

The primary types of sales and service activities reported as operating revenue for Virginia Power, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:

• Regulated electric sales consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; and

• Other revenue consisted primarily of miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities.

The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:

REVENUE FROM CONTRACTS WITH CUSTOMERS

• Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;

• Nonregulated gas sales consist primarily of sales of gas purchased from third parties and royalty revenues;

• Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

• NGL revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity;

• Management service revenue consists primarily of services performed for Atlantic Coast Pipeline;

• Other regulated revenue consists primarily of miscellaneous regulated revenues; and

• Other nonregulated revenue consists primarily of miscellaneous service revenue.

OTHER REVENUE

• Other revenue consists primarily of gains and losses from derivative instruments not subject to hedge accounting.

The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:

• Regulated gas sales consisted primarily of state- and FERC-regulated natural gas sales and related distribution services;

• Nonregulated gas sales consisted primarily of sales of natural gas production at market-based rates and contracted fixed prices and sales of gas purchased from third parties. Revenue from sales of gas production was recognized based on actual volumes of gas sold to purchasers and was reported net of royalties;

• Gas transportation and storage sales consisted primarily of FERC-regulated sales of transmission and storage services. Also included were state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

• NGL revenue consisted primarily of sales of NGL production and condensate, extracted products and associated derivative activity; and

• Other revenue consisted primarily of miscellaneous service revenue, gas processing and handling revenue.

Dominion Energy and Virginia Power record refunds to customers as required by state commissions as a reduction to regulated electric sales or regulated gas sales, as applicable. Dominion Energy and Virginia Power’s revenue accounted for under the alternative revenue program guidance primarily consists of the equity return for under-recovery of certain riders. Alternative revenue programs compensate Dominion Energy and Virginia Power for certain projects and initiatives. Revenues arising from these programs are presented separately from revenue arising from contracts with customers in the categories above.

Revenues from electric and gas sales are recognized over time, as the customers of the Companies consume gas and electricity as it is delivered. Transportation and storage contracts are primarily stand-ready service contracts that include fixed reservation and variable usage fees. LNG terminalling services are also stand-ready service contracts, primarily consisting of fixed fees, offset by service credits associated with the start-up phase of the Liquefaction Project. Fixed fees are recognized ratably over the life of the contract as the stand-ready performance obligation is satisfied, while variable usage fees are recognized when Dominion Energy and Dominion Energy Gas have a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the performance obligation completed to date. Sales of products and services, including NGLs, typically transfer control and are recognized as revenue upon delivery of the product or service. The customer is able to direct the use of, and obtain substantially all of the benefits from, the product at the time the product is delivered. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. Payment for most sales and services varies by contract type, but is typically due within a month of billing.

Dominion Energy and Dominion Energy Gas typically receive or retain NGLs and natural gas from customers when providing natural gas processing, transportation or storage services. The revised guidance for revenue from contracts with customers requires entities to include the fair value of the noncash consideration in the transaction price. Therefore, subsequent to the adoption of the revised guidance for revenue recognition from contracts with customers, Dominion Energy and Dominion Energy Gas record the fair value of NGLs received during natural gas processing as service revenue recognized over time, and continue to recognize revenue from the subsequent sale of the NGLs to customers upon delivery. Dominion Energy and Dominion Energy Gas typically retain natural gas under certain transportation service arrangements that are intended to facilitate performance of the service and allow for natural losses that occur. As the intent of the allowance is to enable fulfillment of the contract rather than to provide compensation for services, the fuel allowance is not included in revenue.

Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs

Where permitted by regulatory authorities, the differences between Dominion Energy and Virginia Power’s actual electric fuel and purchased energy expenses and Dominion Energy and Dominion Energy Gas’ purchased gas expenses and the related

97

Combined Notes to Consolidated Financial Statements, Continued

levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.

Of the cost of fuel used in electric generation and energy purchases to serve utility customers, at December 31, 2018, approximately 84% is subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.

Virtually all of Dominion Energy Gas, Cove Point, Questar Gas, Hope and SCE&G and PSNC’s, following the SCANA Combination, natural gas purchases are either subject to deferral accounting or are recovered from the customer in the same accounting period as the sale.

Income Taxes

A consolidated federal income tax return is filed for Dominion Energy and its subsidiaries, including Virginia Power and Dominion Energy Gas’ subsidiaries. In addition, where applicable, combined income tax returns for Dominion Energy and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed.

Although Dominion Energy Gas is disregarded for income tax purposes, a provision for income taxes is recognized to reflect the inclusion of its business activities in the tax returns of its parent, Dominion Energy. Virginia Power and Dominion Energy Gas participate in intercompany tax sharing agreements with Dominion Energy and its subsidiaries. Current income taxes are based on taxable income or loss and credits determined on a separate company basis.

Under the agreements, if a subsidiary incurs a tax loss or earns a credit, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or credit or to the extent the tax loss or credit is absorbed by the taxable income of other Dominion Energy consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax asset until realized.

The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies, including changes in corporate tax rates and business deductions. The 2017 Tax Reform Act reduces the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. Deferred tax assets and liabilities are classified as noncurrent in the Consolidated Balance Sheets and measured at the enacted tax rate expected to apply when temporary differences are realized or settled. Thus, at the date of enactment, federal deferred taxes were remeasured based upon the new 21% tax rate. The total effect of tax rate changes on deferred tax balances was recorded as a component of the income tax provision related to continuing operations for the period in which the law is enacted, even if the assets and liabilities relate to other components of the financial statements, such as items of accumulated other comprehensive income. For Dominion Energy subsidiaries that are not rate-regulated utilities, existing deferred income tax assets or liabilities were adjusted for the reduction in the corporate income tax rate and allocated to continuing operations. Dominion Energy’s rate-regulated utility subsidiaries likewise were required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, if it is probable that the effect of the change in

income tax rates will be recovered or refunded in future rates, the regulated utility recorded a regulatory asset or liability instead of an increase or decrease to deferred income tax expense.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. The Companies establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

The Companies recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the Consolidated Balance Sheets and current payables are included in accrued interest, payroll and taxes on the Consolidated Balance Sheets.

The Companies recognize interest on underpayments and overpayments of income taxes in interest expense and other income, respectively. Penalties are also recognized in other income.

Interest for the Companies was immaterial in 2018 and 2016. Dominion Energy and Virginia Power both recognized interest income of $11 million in 2017. Dominion Energy Gas’ interest was immaterial in 2017. Dominion Energy, Virginia Power and Dominion Energy Gas’ penalties were immaterial in 2018, 2017 and 2016.

At December 31, 2018, Virginia Power had an income tax-related affiliated receivable of $36 million, comprised of $34 million of federal income taxes and $2 million of state income taxes due from Dominion Energy. Dominion Energy Gas also had a net affiliated receivable of $2 million due from Dominion Energy, representing $8 million of federal income taxes receivable and $6 million of state income taxes payable to Dominion Energy. The net affiliated receivables are expected to be received from Dominion Energy.

In addition, Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2018 included $13 million of state income taxes receivable. State income taxes receivable at Virginia Power were immaterial at December 31, 2018.

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At December 31, 2017, Virginia Power had an income tax-related affiliated payable of $16 million, comprised of $16 million of federal income taxes due to Dominion Energy. Dominion Energy Gas also had an affiliated payable of $25 million due to Dominion Energy, representing $21 million of federal income taxes and $4 million of state income taxes. The net affiliated payables were paid to Dominion Energy.

In addition, Virginia Power’s Consolidated Balance Sheet at December 31, 2017 included $1 million of noncurrent federal income taxes receivable, less than $1 million of state income taxes receivable and $1 million of noncurrent state income taxes receivable. Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2017 included $14 million of state income taxes receivable.

Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.

Cash, Restricted Cash and Equivalents

Cash, restricted cash and equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Current banking arrangements generally do not require checks to be funded until they are presented for payment. The following table illustrates the checks outstanding but not yet presented for payment and recorded in accounts payable for the Companies:

At December 31,	2018		2017
(millions)
Dominion Energy	$	35	$	30
Virginia Power		16		17
Dominion Energy Gas		7		7

RESTRICTED CASH AND EQUIVALENTS

The Companies hold restricted cash and equivalent balances that primarily consist of amounts held for customer deposits, future debt payments on SBL Holdco and Dominion Solar Projects III, Inc.’s term loan agreements and on Eagle Solar’s senior note agreement.

The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within the Companies’ Consolidated Balance Sheets to the corresponding amounts reported within the Companies’ Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016:

	Cash, Restricted Cash and Equivalents at End/Beginning of Year
	December 31, 2018		December 31, 2017		December 31, 2016		December 31, 2015
(millions)
Dominion Energy
Cash and cash equivalents	$	268	$	120	$	261	$	607
Restricted cash and equivalents(1)		123		65		61		25
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	391	$	185	$	322	$	632
Virginia Power
Cash and cash equivalents	$	29	$	14	$	11	$	18
Restricted cash and equivalents(1)		9		10		—		—
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	38	$	24	$	11	$	18
Dominion Energy Gas
Cash and cash equivalents	$	10	$	4	$	23	$	13
Restricted cash and equivalents(1)		24		26		20		14
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	34	$	30	$	43	$	27

(1) Restricted cash and equivalent balances are presented within other current assets in the Companies’ Consolidated Balance Sheets.

DISTRIBUTIONS FROM EQUITY METHOD INVESTEES

Dominion Energy and Dominion Energy Gas each hold investments that are accounted for under the equity method of accounting. Dominion Energy and Dominion Energy Gas classify distributions from equity method investees as either cash flows from operating activities or cash flows from investing activities in the Consolidated Statements of Cash Flows according to the nature of the distribution. Distributions received are classified on the basis of the nature of the activity of the investee that generated the distribution as either a return on investment (classified as cash flows from operating activities) or a return of an investment (classified as cash flows from investing activities) when such information is available to Dominion Energy and Dominion Energy Gas.

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Combined Notes to Consolidated Financial Statements, Continued

Derivative Instruments

The Companies are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as interest rate and foreign currency exchange rate risks of their business operations. Dominion Energy uses derivative instruments such as physical and financial forwards, futures, swaps, options and FTRs to manage the commodity, interest rate and foreign currency exchange rate risks of its business operations. Virginia Power uses derivative instruments such as physical and financial forwards, futures, swaps, options and FTRs to manage commodity and interest rate risks. Dominion Energy Gas uses derivative instruments such as physical and financial forwards, futures and swaps to manage commodity, interest rate and foreign currency exchange rate risks.

All derivatives, except those for which an exception applies, are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.

The Companies do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion Energy had margin assets of $95 million and $92 million associated with cash collateral at December 31, 2018 and 2017, respectively. Dominion Energy’s margin liabilities associated with cash collateral were less than $1 million at December 31, 2018 and 2017. Virginia Power had margin assets of $23 million associated with cash collateral at December 31, 2017. Virginia Power had no margin assets associated with cash collateral at December 31, 2018 and no margin liabilities associated with cash collateral at December 31, 2018 and 2017. Dominion Energy Gas had no margin assets or liabilities associated with cash collateral at December 31, 2018 and 2017. See Note 7 for further information about derivatives.

To manage price risk, the Companies hold certain derivative instruments that are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices. All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses, interest and related charges or other income based on the nature of the underlying risk.

Changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.

DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS

In accordance with accounting guidance pertaining to derivatives and hedge accounting, the Companies designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For derivative instruments that are accounted for as fair value hedges or cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.

Cash Flow Hedges-A majority of the Companies’ hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas and NGLs. The Companies also use interest rate swaps to hedge their exposure to variable interest rates on long-term debt as well as foreign currency swaps to hedge their exposure to interest payments denominated in Euros. For transactions in which the Companies are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Dominion Energy entered into interest rate derivative instruments to hedge its forecasted interest payments related to planned debt issuances in 2014. These interest rate derivatives were designated by Dominion Energy as cash flow hedges prior to the formation of Dominion Energy Gas. For the purposes of the Dominion Energy Gas financial statements, the derivative balances, AOCI balance, and any income statement impact related to these interest rate derivative instruments entered into by Dominion Energy have been, and will continue to be, included in the Dominion Energy Gas’ Consolidated Financial Statements as the forecasted interest payments related to the debt issuances now occur at Dominion Energy Gas.

Fair Value Hedges-Dominion Energy has also designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. In addition, Dominion Energy has used fair value hedges to mitigate the fixed price exposure inherent in commodity inventory. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7 for further information on derivatives.

Property, Plant and Equipment

Property, plant and equipment is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is generally charged to expense as it is incurred.

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In 2018, 2017 and 2016, Dominion Energy capitalized interest costs and AFUDC to property, plant and equipment of $134 million, $236 million and $159 million, respectively. In 2018, 2017 and 2016, Virginia Power capitalized AFUDC to property, plant and equipment of $56 million, $37 million and $21 million, respectively. In 2018, 2017 and 2016, Dominion Energy Gas capitalized AFUDC to property, plant and equipment of $18 million, $25 million and $8 million, respectively.

Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2018, 2017 and 2016, Virginia Power recorded $4 million, $22 million and $31 million of AFUDC related to these projects, respectively.

For property subject to cost-of-service rate regulation, including Dominion Energy and Virginia Power electric distribution, electric transmission and generation property, Dominion Energy Gas natural gas distribution and transmission property, and for certain Dominion Energy natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be abandoned. In January 2019, Virginia Power committed to a plan to retire certain automated meter reading infrastructure associated with its electric operations before the end of its useful life and replace such equipment with more current AMI technology. As a result, Virginia Power expects to incur a charge of approximately $190 million ($141 million after-tax) in 2019.

For property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. The Companies’ average composite depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,	2018		2017		2016
(percent)
Dominion Energy
Generation		2.71		2.94		2.83
Transmission		2.54		2.55		2.47
Distribution		2.97		3.00		3.02
Storage		2.40		2.48		2.29
Gas gathering and processing		2.62		2.21		2.66
General and other		4.56		4.89		4.12
Virginia Power
Generation		2.71		2.94		2.83
Transmission		2.52		2.54		2.36
Distribution		3.31		3.32		3.32
General and other		4.52		4.68		3.49
Dominion Energy Gas
Transmission		2.45		2.40		2.43
Distribution		2.41		2.42		2.55
Storage		2.46		2.45		2.19
Gas gathering and processing		3.07		2.42		2.58
General and other		5.59		4.96		4.54

In the second quarter of 2018, Virginia Power recorded an adjustment for the retroactive application of depreciation rates for regulated nuclear plants to comply with Virginia Commission requirements. This adjustment resulted in a decrease of $60 million ($44 million after-tax) in depreciation expense in Virginia Power’s Consolidated Statements of Income for the year ended December 31, 2018. This resulted in an increase to Dominion Energy’s EPS of $0.07 per share for the year ended December 31, 2018. This revision is expected to decrease annual depreciation expense by approximately $30 million ($23 million after-tax).

In the first quarter of 2017, Virginia Power revised the depreciation rates for its assets to reflect the results of a new depreciation study. This change resulted in an increase in annual depreciation expense of $40 million ($25 million after-tax) for 2017. Additionally, Dominion Energy revised the depreciable lives for its merchant generation assets, excluding Millstone, which resulted in a decrease in annual depreciation expense of $26 million ($16 million after-tax) for 2017.

Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved gas and oil reserves, at a rate of $1.89 and $2.11 per mcfe in 2018 and 2017, respectively.

Dominion Energy’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:

Asset	Estimated Useful Lives
Merchant generation-nuclear		44 years
Merchant generation-other		15-30 years
Nonutility gas gathering and processing		3-50 years
LNG facility		40 years
General and other		5-59 years

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Combined Notes to Consolidated Financial Statements, Continued

Depreciation and amortization related to Virginia Power and Dominion Energy Gas’ nonutility property, plant and equipment and exploration and production properties was immaterial for the years ended December 31, 2018, 2017 and 2016, except for Dominion Energy Gas’ nonutility gas gathering and processing properties which are depreciated using the straight-line method over estimated useful lives between 10 and 50 years.

Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion Energy and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.

Long-Lived and Intangible Assets

The Companies perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for further discussion on the impairment of long-lived assets.

Regulatory Assets and Liabilities

The accounting for Dominion Energy and Dominion Energy Gas’ regulated gas and Dominion Energy and Virginia Power’s regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.

The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions, legislation or historical experience, as well as discussions with applicable regulatory authorities and legal counsel. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made.

Asset Retirement Obligations

The Companies recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair

value is estimated using discounted cash flow analyses. Quarterly, the Companies assess their AROs to determine if circumstances indicate that estimates of the amounts or timing of future cash flows associated with retirement activities have changed. AROs are adjusted when significant changes in the amounts or timing of future cash flows are identified. Dominion Energy and Dominion Energy Gas report accretion of AROs and depreciation on asset retirement costs associated with their natural gas pipeline and storage well assets as an adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Dominion Energy, following the SCANA Combination, and Virginia Power report accretion of AROs and depreciation on asset retirement costs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions. Additionally, Dominion Energy and Virginia Power report accretion of AROs and depreciation on asset retirement costs associated with certain rider and prospective rider projects as an adjustment to the regulatory asset for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs are reported in other operations and maintenance expense and depreciation expense, respectively, in the Consolidated Statements of Income.

Debt Issuance Costs

The Companies defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as a reduction in long-term debt in the Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest expense. Unamortized costs associated with redemptions of debt securities prior to stated maturity dates are generally recognized and recorded in interest expense immediately. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation are deferred and amortized.

Investments

DEBT AND EQUITY SECURITIES WITH READILY DETERMINABLE FAIR VALUES

Dominion Energy accounts for and classifies investments in debt securities as trading or available-for-sale securities. Virginia Power classifies investments in debt securities as available-for-sale securities.

• Debt securities classified as trading securities include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.

• Debt securities classified as available-for-sale securities include all other debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability

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for certain jurisdictions subject to cost-based regulation. For all other available-for-sale debt securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.

In determining realized gains and losses for debt securities, the cost basis of the security is based on the specific identification method.

Equity securities with readily determinable fair values include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans and securities held by Dominion Energy and Virginia Power in the nuclear decommissioning trusts. Dominion Energy and Virginia Power record all equity securities with a readily determinable fair value, or for which they are permitted to estimate fair value using NAV (or its equivalent), at fair value in nuclear decommissioning trust funds and other investments in the Consolidated Balance Sheets. However, Dominion Energy and Virginia Power may elect a measurement alternative for equity securities without a readily determinable fair value. Under the measurement alternative, equity securities are reported at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. Dominion Energy and Virginia Power qualitatively assess equity securities reported using the measurement alternative to determine whether an investment is impaired on an ongoing basis. Net realized and unrealized gains and losses on equity securities held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other equity securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts and rabbi trusts, net realized and unrealized gains and losses are included in other income in the Consolidated Statements of Income.

EQUITY SECURITIES WITHOUT READILY DETERMINABLE FAIR VALUES

The Companies account for illiquid and privately held securities without readily determinable fair values under either the equity method or cost method. Equity securities without readily determinable fair values include:

• Equity method investments when the Companies have the ability to exercise significant influence, but not control, over the investee. Dominion Energy’s investments are included in investments in equity method affiliates and Dominion Energy Gas’ investments are included in investments in their Consolidated Balance Sheets. Dominion Energy and Dominion Energy Gas record equity method adjustments in other income and earnings from equity method investee, respectively, in their Consolidated Statements of Income, including their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.

• Cost method investments when Dominion Energy and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion Energy and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds. Cost method investments are reported at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same issuer.

OTHER-THAN-TEMPORARY IMPAIRMENT

The Companies periodically review their investments in debt securities and equity method investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in the fair value of any security is determined to be other-than-temporary, the security is written down to its fair value at the end of the reporting period.

Decommissioning Trust Investments —Special Considerations for Debt Securities

• The recognition provisions of other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity.

• Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion Energy and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, Dominion Energy and Virginia Power record the credit loss in earnings and any remaining portion of the unrealized loss in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.

Inventories

Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory is valued using the weighted-average cost method, except for East Ohio gas distribution operations, which are valued using the LIFO method. Under the LIFO method, current stored gas inventory was valued at $12 million and $9 million at December 31, 2018 and December 31, 2017, respectively. Based on the average price of gas purchased during 2018 and 2017, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $87 million and $79 million, respectively.

Gas Imbalances

Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion Energy and Dominion Energy Gas value these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion Energy from other parties are reported in other current assets and imbalances that Dominion Energy and Dominion Energy Gas owe to other parties are

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Combined Notes to Consolidated Financial Statements, Continued

reported in other current liabilities in the Consolidated Balance Sheets.

Goodwill

Dominion Energy and Dominion Energy Gas evaluate goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount.

New Accounting Standards

REVENUE RECOGNITION

In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. The Companies adopted this revised accounting guidance for interim and annual reporting periods beginning January 1, 2018 using the modified retrospective method. Upon the adoption of the standard, Dominion Energy and Dominion Energy Gas recorded the cumulative-effect of a change in accounting principle of $3 million to retained earnings and membership interests, respectively, and to establish a contract asset related to changes in the timing of revenue recognition for three existing contracts with customers at DETI.

As a result of adopting this revised accounting guidance, Dominion Energy and Dominion Energy Gas record offsetting operating revenue and other energy-related purchases for non-cash consideration of performing processing and fractionation services related to NGLs. Such amounts at Dominion Energy were $107 million and at Dominion Energy Gas were $103 million, recorded in the Consolidated Statements of Income for the year ended December 31, 2018. No such amounts were recorded during the year ended December 31, 2017. Dominion Energy and Dominion Energy Gas no longer record offsetting operating revenue and purchased gas for fuel retained to offset costs on certain transportation and storage arrangements. Such amounts at Dominion Energy were $111 million and at Dominion Energy Gas were $79 million, recorded in the Consolidated Statements of Income for the year ended December 31, 2017.

FINANCIAL INSTRUMENTS

In January 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of financial instruments. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018 and the Companies adopted the standard using the modified retrospective method. Upon adoption of this guidance for equity securities held at January 1, 2018, Dominion Energy and Virginia Power recorded the cumulative-effect of a change in accounting principle to reclassify net unrealized gains from AOCI to retained earnings and to recognize equity securities previously categorized as cost method investments at fair value (using NAV) in nuclear decommissioning trust funds in the Consolidated Balance Sheets and a cumulative-effect adjustment to retained earnings. Dominion Energy and Virginia Power reclassified approximately $1.1 billion ($734 million after-tax) and $119 million ($73 million after-tax), respectively, of net unrealized gains from AOCI to retained earnings. Dominion Energy and Virginia Power also recorded approximately $36 million ($22 million after-tax) in net unrealized gains on

equity securities previously classified as cost method investments, of which $3 million was recorded to retained earnings and $33 million was recorded to regulatory liabilities for net unrealized gains subject to cost-based regulation. As a result of adopting this revised accounting guidance, Dominion Energy recorded unrealized losses on equity securities, net of regulatory deferrals, of $190 million ($142 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018, resulting in an $0.22 loss per share for the year ended December 31, 2018. Virginia Power recorded unrealized losses on equity securities, net of regulatory deferrals, of $24 million ($18 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018.

LEASES

In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases currently classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.

The guidance is effective for the Companies’ interim and annual reporting periods beginning January 1, 2019. The Companies will adopt this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Companies are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Companies will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. Dominion Energy, Virginia Power and Dominion Energy Gas anticipate that the adoption of this guidance will result in approximately $450 million to $500 million, $200 million to $250 million and $60 million to $70 million, respectively, of offsetting right-of-use assets and liabilities added to their Consolidated Balance Sheets for operating leases in effect at the adoption date. Dominion Energy’s anticipated right-of-use asset and liability associated with operating leases includes those acquired as part of the SCANA Combination of approximately $30 million to $35 million. No material changes are expected to the Companies’ results of operations.

DERECOGNITION AND PARTIAL SALES OF NONFINANCIAL ASSETS

In February 2017, the FASB issued revised accounting guidance clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, and the Companies adopted the standard using the modified retrospective method. Upon adoption of the standard, Dominion Energy recorded the cumulative-effect of a change in accounting principle to reclassify

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$127 million from noncontrolling interests to common stock related to the sale of a noncontrolling interest in certain merchant solar projects completed in December 2015 and January 2016.

NET PERIODIC PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

In March 2017, the FASB issued revised accounting guidance for the presentation of net periodic pension and other postretirement benefit costs. This guidance became effective for the Companies beginning January 1, 2018 and requires that the service cost component of net periodic pension and other postretirement benefit costs be classified in the same line item as other compensation costs arising from services rendered by employees, while all other components of net periodic pension and other postretirement costs are classified outside of income from operations. In addition, only the service cost component remains eligible for capitalization during construction. These changes do not impact the accounting by participants in a multi-employer plan. The standard also recognizes that in the event that a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in recognition of a regulatory asset or liability. For costs not capitalized for which regulators are expected to provide recovery, a regulatory asset will be established. As such, the amounts eligible for capitalization in the Consolidated Financial Statements of Virginia Power and Dominion Energy Gas, as subsidiary participants in Dominion Energy’s multi-employer plans, will differ from the amounts eligible for capitalization in the Consolidated Financial Statements of Dominion Energy, the plan administrator. These differences will result in a regulatory asset or liability recorded in the Consolidated Financial Statements of Dominion Energy.

TAX REFORM

In December 2017, the staff of the SEC issued guidance which clarifies accounting for income taxes if information is not yet available or complete and provided for up to a one-year measurement period in which to complete the required analyses and accounting. The guidance described three scenarios associated with a company’s status of accounting for income tax reform: (1) a company is complete with its accounting for certain effects of tax reform, (2) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply accounting for income taxes based on the provisions of the tax laws that were in effect immediately prior to the 2017 Tax Reform Act being enacted. The Companies have accounted for the effects of the 2017 Tax Reform Act, although additional changes could occur as guidance is issued and finalized as described below. In addition, certain states in which the Companies operate may or may not conform to some or all of the provisions of the 2017 Tax Reform Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to results of operations and cash flows, and adjustments to tax-related assets and liabilities, and could be material.

In August 2018, the U.S. Department of Treasury issued proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017

through December 31, 2017. The application of these changes decreased Dominion Energy’s net operating loss carryforward utilization on its 2017 tax return as discussed in Note 5.

In November 2018, the U.S. Department of Treasury issued proposed regulations defining interest as any amounts associated with the time value of money or use of funds. These proposed regulations provide guidance for purposes of the exception to the interest limitation for regulated public utilities, the application of the interest limitation to consolidated groups, such as Dominion Energy, and the interest limitation with respect to partnerships and partners in those partnerships. It is unclear when the guidance may be finalized, or whether that guidance could result in a disallowance of a portion of the Companies’ interest deductions in the future.

In February 2018, the FASB issued revised accounting guidance to provide clarification on the application of the 2017 Tax Reform Act for balances recorded within AOCI. The revised guidance provides for stranded amounts within AOCI from the impacts of the 2017 Tax Reform Act to be reclassified to retained earnings. The Companies adopted this guidance for interim and annual reporting periods beginning January 1, 2018 on a prospective basis. In connection with the adoption of this guidance, Dominion Energy reclassified a benefit of $289 million from AOCI to retained earnings, Virginia Power reclassified a benefit of $3 million from AOCI to retained earnings and Dominion Energy Gas reclassified a benefit of $26 million from AOCI to membership interests. The amounts reclassified reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of the Companies’ AOCI.

NOTE 3. ACQUISITIONS AND DISPOSITIONS

DOMINION ENERGY

Acquisition of SCANA

In January 2019, Dominion Energy issued 95.6 million shares of Dominion Energy common stock, valued at $6.8 billion, representing 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock, in connection with the completion of the SCANA Combination. SCANA, through its regulated subsidiaries, is primarily engaged in the generation, transmission and distribution of electricity in the central, southern, and southwestern portions of South Carolina and in the distribution of natural gas in North Carolina and South Carolina. In addition, SCANA markets natural gas to retail customers in the southeast U.S. Following completion of the SCANA Combination, SCANA operates as a wholly-owned subsidiary of Dominion Energy. In addition, SCANA’s outstanding debt totaled $6.9 billion at closing. The SCANA Combination expands Dominion Energy’s portfolio of regulated electric generation, transmission and distribution and regulated natural gas distribution infrastructure and operations.

MERGER APPROVAL AND CONDITIONS

Merger Approval

The SCANA Combination required approval of SCANA’s shareholders, FERC, the North Carolina Commission, the South Carolina Commission, the Georgia Public Service Commission

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Combined Notes to Consolidated Financial Statements, Continued

and the NRC and clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act. All such approvals were received prior to closing of the SCANA Combination.

Various parties filed petitions for rehearing or reconsideration of the SCANA Merger Approval Order. In January 2019, the South Carolina Commission issued a directive (1) granting the request of various parties and finding that SCE&G was imprudent in its actions by not disclosing material information to the South Carolina Office of Regulatory Staff and the South Carolina Commission with regard to costs incurred subsequent to March 2015 and (2) denying the petitions for rehearing or consideration as to other issues raised in the various petitions. The SCANA Merger Approval Order and the order on rehearing are subject to appeal by various parties.

Refunds to Customers

As a condition to the SCANA Merger Approval Order, SCE&G will provide refunds and restitution of $2.0 billion over 20 years with capital support from Dominion Energy.

In September and October 2017, SCE&G received proceeds from Toshiba Corporation totaling $1.1 billion in full satisfaction of its share of a settlement agreement between SCE&G, Santee Cooper and Toshiba Corporation in connection with Westinghouse and WECTEC, both wholly-owned subsidiaries of Toshiba Corporation and responsible for the engineering and construction of the NND Project, filing for bankruptcy. The purchase price allocation below includes a previously established regulatory liability at SCE&G totaling $1.1 billion associated with the monetization of the bankruptcy settlement with Toshiba Corporation. In accordance with the terms of the SCANA Merger Approval Order, this regulatory liability, net of amounts that may be required to satisfy any liens against NND Project property totaling $1.0 billion, will be refunded to SCE&G electric service customers over a 20-year period ending in 2039.

Additionally, SCE&G will reflect in the first quarter of 2019 a reduction in operating revenue and a corresponding regulatory liability of $1.0 billion of which approximately $140 million will be considered current, representing a refund of amounts previously collected from retail electric customers of SCE&G for the NND Project to be credited over an estimated 11-year period. This will result in a $756 million after-tax charge in Dominion Energy’s Consolidated Statements of Income in the first quarter of 2019.

NND Project

As a condition to the SCANA Merger Approval Order, SCE&G will exclude from rate recovery $2.4 billion of costs related to the NND Project and $180 million of costs associated with the purchase of the Columbia Energy Center power station. Regulatory assets included in SCANA’s historical balance sheet at December 31, 2018 reflected these disallowances.

The remaining regulatory asset associated with the NND Project of $2.8 billion will be collected over a 20-year period, including a return on investment. In January 2019, SCE&G filed the NND Project rider in accordance with the terms of the SCANA Merger Approval Order for rates effective in February 2019 for SCE&G’s retail electric customers. The South Carolina Commission approved this filing in January 2019.

Other Terms and Conditions

• SCE&G will not file an application for a general rate case with the South Carolina Commission with a requested effective date earlier than January 2021;

• PSNC will not file an application for a general rate case with the North Carolina Commission with a requested effective date earlier than April 2021;

• Dominion Energy has committed to increasing SCANA’s historical level of corporate contributions to charities by $1 million per year over the next five years;

• Dominion Energy will maintain SCE&G and PSNC’s headquarters in Cayce, South Carolina and Gastonia, North Carolina, respectively; and

• Dominion Energy will seek to minimize reductions in local employment by allowing some DES employees supporting shared and common services functions and activities to be located in Cayce, South Carolina where it makes economic and practical sense to do so.

PURCHASE PRICE ALLOCATION

SCANA’s assets acquired and liabilities assumed will be measured at estimated fair value at closing and will be included in the Southeast Energy operating segment, which was established following the closing of the SCANA Combination. The majority of the operations acquired are subject to the rate setting authority of FERC and the North and South Carolina Commissions and are therefore accounted for pursuant to ASC 980, Regulated Operations. The fair values of SCANA’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the unaudited pro forma financial information, reflect any adjustments related to these amounts.

The fair value of SCANA’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions discussed above and the fair values of SCANA’s investments accounted for under the equity method will be determined using the income approach and the market approach. The valuation of SCANA’s long-term debt is considered a Level 2 fair value measurement. All other valuations will be considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future market prices.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed will be reflected as goodwill in the first quarter of 2019. The goodwill reflects the value associated with enhancing Dominion Energy’s portfolio of regulated operations in the growing southeast region of the U.S. The goodwill to be recognized will not be deductible for income tax purposes, and as such, no deferred taxes will be recorded related to goodwill.

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The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at closing to be reflected in Dominion Energy’s Consolidated Balance Sheet in the first quarter of 2019. The allocation is subject to change during the measurement period as additional information is obtained about the facts and circumstances that existed at closing. The allocation of the purchase price excludes certain contracts and intangible assets related to nonregulated operations, including SEMI, equity method investments and certain income tax-related amounts, which will be included as Dominion Energy completes its valuation analysis. As a result, the amount of goodwill included below may change by a material amount as Dominion Energy finalizes the allocation of the purchase price during the first quarter of 2019.

	Amount
(millions)
Total current assets	$	1,756
Investments		213
Property, plant and equipment, net		10,982
Goodwill		2,438
Regulatory assets		4,219
Other deferred charges and other assets, including intangible assets		314
Total Assets		19,922
Total current liabilities		1,506
Long-term debt		6,707
Deferred income taxes		1,097
Regulatory liabilities		2,664
Other deferred credits and other liabilities		1,109
Total Liabilities		13,083
Total purchase price	$	6,839

INFORMATION ON ASSETS AND LIABILITIES ACQUIRED

Cash, Restricted Cash and Equivalents

The total current assets line above includes $389 million of cash, restricted cash and equivalents, of which $115 million is considered restricted, acquired by Dominion Energy in connection with the SCANA Combination.

Investments

Investments acquired in connection with the SCANA Combination include $20 million pertaining to certain investments accounted for under the equity method, at carrying value. Dominion Energy is still assessing the fair value of these investments.

Income Taxes

Deferred income taxes include a deferred tax asset recorded on a federal net operating loss carryforward of $1.8 billion and a state net operating loss carryforward of $2.4 billion. Based on the available evidence, Dominion Energy believes it is more likely than not that the benefit of the federal net operating loss will be utilized during the carryforward period, and therefore no valuation allowance has been established. Dominion Energy is still assessing whether a valuation allowance is required on the state net operating loss carryforward. Deferred income taxes also include unrecognized tax benefits of $106 million, which could increase as Dominion Energy continues and completes its evaluation of positions taken on SCANA’s federal and state income tax returns.

Property, Plant and Equipment

At the date of the SCANA Combination, major classes of property, plant and equipment and their respective balances for SCANA are as follows:

	2018
(millions)
Utility:
Generation	$	5,720
Transmission		2,416
Distribution		6,044
Storage		99
Nuclear fuel		611
General and other		631
Plant under construction		527
Total utility		16,048
Nonutility, including plant under construction		283
Total property, plant and equipment	$	16,331

In connection with the SCANA Combination, Dominion Energy intends to forego recovery of approximately $105 million of certain assets for which it expects to recognize a $79 million after-tax charge in the first quarter of 2019.

Regulated property will be depreciated on a straight-line basis based on projected service lives. Actual average composite depreciation rates for SCANA’s utility property, plant and equipment were as follows:

	2018
(millions)
Generation		2.61	%
Transmission		2.47
Distribution		2.48
Storage		2.48
General and other		5.64

Nonregulated property, plant and equipment, excluding land, will be depreciated on a straight-line basis over the remaining useful lives of such property, primarily ranging from 5 to 78 years.

SCE&G jointly owns and is the operator of Summer. At December 31, 2018, and subsequent to the SCANA Combination, SCE&G had a 66.7% ownership interest in Summer, of which its proportionate share of plant in service, accumulated depreciation and plant under construction was $1.5 billion, $644 million and $128 million, respectively. The co-owners are obligated to pay their share of all future construction expenditures and operating costs of Summer in the same proportion as their respective ownership interest.

Regulatory Assets

In addition to the items discussed above related to the NND Project, Dominion Energy intends to forego recovery of approximately $190 million of regulatory assets related to certain deferred income taxes for which it expects to recognize a $145 million after-tax charge in the first quarter of 2019.

Intangible Assets

Other current assets presented in the table above include intangible assets subject to regulatory recovery with a gross carrying value of $281 million and related accumulated amortization of $181 million. Such intangible assets have an estimated

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Combined Notes to Consolidated Financial Statements, Continued

weighted-average amortization period of approximately five years. Annual amortization expense for these intangible assets is estimated to be as follows:

	2019		2020		2021		2022		2023
(millions)
SCANA	$	95	$	90	$	80	$	74	$	71

Asset Retirement Obligations

The purchase price allocation above includes $577 million of AROs, of which $23 million is considered to be a current liability. These AROs are associated with SCANA’s legal obligation to decommission Summer, as well as conditional obligations related to generation, transmission and distribution properties, including gas pipelines.

Short-Term and Long-Term Debt

At closing of the SCANA Combination, commercial paper and letters of credit outstanding, as well as capacity available under SCANA’s existing credit facilities were as follows:

	SCANA Corporation			SCE&G			PSNC			Total
(millions, except percentages)
Total facility limit	$	400		$	1,200	(1)	$	200		$	1,800
Letters of credit advances		40	(2)		—			—			40
Weighted-average interest rate		3.87	%		n/a			n/a			3.87	%
Outstanding commercial paper		2			73			98			173
Weighted-average interest rate		3.65	%		3.82	%		3.49	%		3.63	%
Outstanding letters of credit		37			—			—			37
Facility capacity available	$	321		$	1,127		$	102		$	1,550

(1) Includes South Carolina Fuel Company, Inc.’s $500 million credit facility.

(2) In January 2019, SCANA repaid $40 million in letter of credit advances.

In connection with the SCANA Combination, Dominion Energy intends to terminate SCANA, SCE&G and PSNC’s existing credit facilities, scheduled to expire in December 2020, and add SCE&G as a co-borrower to its $6.0 billion joint revolving credit facility in the first quarter of 2019 once certain regulatory approvals are obtained. In January 2019, Virginia Power and SCE&G, as co-borrowers, filed with the Virginia Commission and the South Carolina Commission, respectively, for approval. In February 2019, the Virginia Commission approved the request. SCE&G is required to obtain FERC approval to issue short-term indebtedness, including commercial paper, and to assume liabilities as a guarantor. In February 2019, Dominion Energy terminated South Carolina Fuel Company, Inc.’s existing credit facility, scheduled to expire in December 2020.

At closing of the SCANA Combination, SCANA had the following long-term debt outstanding which is part of the total consideration provided for the transaction.

	Weighted- average Coupon(1)			Amount
(millions, except percentages)
Unsecured medium term notes, due 2020 to 2022		5.42	%	$	800
Unsecured senior notes, due 2019 to 2034		3.44			70
First mortgage bonds, due 2021 to 2065		5.52			4,990
GENCO notes, due 2019 to 2024		5.49			40
Industrial and pollution control bonds, due 2028 to 2038(2)		3.52			122
PSNC senior debentures and notes, due 2020 to 2047		5.07			700
Other, due 2019 to 2027		3.46			73
Total principal				$	6,795
Current maturities of long-term debt					(59	)
Unamortized discount, premium and debt issuance costs, net					(29	)
SCANA total long-term debt				$	6,707

(1) Represents weighted-average coupon rates for debt outstanding at closing of the SCANA Combination.

(2) Includes variable rate debt of $68 million, with a weighted-average interest rate of 1.72%, which is hedged by fixed swaps.

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at closing of the SCANA Combination, were as follows:

	2019			2020			2021			2022			2023			Thereafter			Total
(millions, except percentages)
Unsecured senior notes	$	4		$	4		$	4		$	4		$	4		$	50		$	70
Unsecured medium term notes		—			250			300			250			—			—			800
First mortgage bonds		—			—			330			—			—			4,660			4,990
PSNC senior debentures and notes		—			100			150			—			—			450			700
GENCO notes		7			7			7			7			7			5			40
Industrial and pollution control bonds		—			—			—			—			—			122			122
Other		48			7			6			5			3			4			73
Total	$	59		$	368		$	797		$	266		$	14		$	5,291		$	6,795
Weighted-average coupon		3.91	%		6.26	%		4.20	%		5.22	%		3.29	%		5.51	%		5.36	%

In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any and all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of $1.0 billion. SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer.

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Preferred Stock

At the closing of the SCANA Combination, authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were held by SCANA.

REGULATORY MATTERS AND PROCEEDINGS

Base Load Review Act

In 2016, the South Carolina Commission approved revised rates under the Base Load Review Act allowing the incorporation of financing costs associated with SCE&G’s incremental construction work in progress incurred for the NND Project and setting an allowed ROE of 10.5%. In July 2018, the South Carolina Commission issued orders implementing a June 2018 legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from its electric utility customers under the Base Load Review Act and altering certain provisions previously applicable under the Base Load Review Act, including redefining the standard of care required by the associated regulations and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the NND Project. These orders reduced the portion of SCE&G’s retail electric rates associated with the NND Project from approximately 18% of the average residential electric customer’s bill, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 2018. These lower rates remained in effect until February 2019, when the new rates pursuant to the SCANA Merger Approval Order became effective.

In June 2018, SCE&G filed a lawsuit in the U.S. District Court for the District of South Carolina challenging the constitutionality of the rate reductions under the Base Load Review Act. In the lawsuit, which was subsequently amended, SCE&G sought a declaration that the new laws are unconstitutional. In January 2019, SCE&G voluntarily dismissed this lawsuit.

2017 Tax Reform Act

In connection with the SCANA Merger Approval Order, the South Carolina Commission approved SCE&G’s provision of approximately $100 million in bill credits related to the 2017 Tax Reform Act’s impact on retail electric customer rates for the period beginning January 2018 through January 2019. These credits have been included in bills rendered on and after the first billing cycle of February 2019. In addition, the South Carolina Commission approved a tax rider whereby the effects of the reduction in the corporate income tax rate resulting from the 2017 Tax Reform Act will benefit retail electric customers. This tax rider is expected to reduce base rates to retail electric customers by approximately $67 million in each of 2019 and 2020, effective with the first billing cycle of February 2019.

In October 2018, the South Carolina Commission issued an order approving adjustment to SCE&G’s natural gas rate schedules, under the terms of the Natural Gas Rate Stabilization Act, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. The approved natural gas rate schedules also included a tax reform rate rider to refund certain income tax amounts previously collected from customers. These lower rates, representing a $20 million decreased revenue requirement, became effective for bills rendered on and after the first billing cycle in November 2018.

In December 2018, the North Carolina Commission issued an order approving PSNC’s proposed adjustments to customer rates, representing a $13 million decreased revenue requirement, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. These lower rates became effective for service rendered on and after January 1, 2019. Amounts collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC’s next general rate case proceeding or in three years, whichever is sooner. The reduction in the federal corporate tax rate and its impact on PSNC’s various rate riders will be addressed in future proceedings related to those riders.

DSM Programs

SCE&G has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2019, SCE&G filed an application with the South Carolina Commission seeking approval to recover $30 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. This matter is pending.

LEGAL PROCEEDINGS

The following describes certain legal proceedings to which SCANA or SCE&G were a party to at closing of the SCANA Combination. Dominion Energy intends to vigorously contest the lawsuits, claims and assessments which have been filed or initiated against SCANA and SCE&G. No reference to, or disclosure of, any proceeding, item or matter described below shall be construed as an admission or indication that such proceeding, item or matter is material. Due to the uncertainty surrounding these matters, Dominion Energy is unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on its results of operations, financial condition and/or cash flows.

Ratepayer Class Actions

In May 2018, a consolidated complaint against SCE&G, SCANA, and the State of South Carolina was filed in the State Court of Common Pleas in Hampton County, South Carolina (the SCE&G Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that SCE&G was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the NND Project, and that SCE&G committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that SCE&G may not charge its customers for any past or continuing costs of the NND Project, sought to have SCANA and SCE&G’s assets frozen and all monies recovered from Toshiba Corporation and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the NND Project.

In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the SCE&G Ratepayer Case. The settlement agreement, contingent upon the closing of the SCANA Combination, provides that SCANA and SCE&G would establish an escrow account and proceeds from the escrow account would be distributed to the

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class members, after payment of certain taxes, attorneys’ fees and other expenses and administrative costs. The escrow account would include (1) up to $2.0 billion, net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the escrow account in favor of class members over a period of time established by the South Carolina Commission in its order related to matters before the South Carolina Commission related to the NND Project, (2) a cash payment of $115 million and (3) the transfer of certain SCE&G-owned real estate or sales proceeds from the sale of such properties, which counsel for the SCE&G Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and SCE&G have funded this escrow account. The court has scheduled a fairness hearing on the settlement in May 2019. Any distribution from the escrow account is subject to court approval. As a result, Dominion Energy expects to reflect an approximately $180 million ($135 million after-tax) charge in the first quarter of 2019.

In September 2017, a purported class action was filed against Santee Cooper, SCE&G, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the State Court of Common Pleas in Hampton County, South Carolina (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the SCE&G Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the NND Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants, including certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina. In December 2018, Santee Cooper filed its answer to the plaintiffs’ fourth amended complaint and filed cross claims against SCE&G. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

RICO Class Action

In January 2018, a purported class action was filed, and subsequently amended, against SCANA, SCE&G and certain former executive officers in the U.S. District Court for the District of South Carolina. The plaintiff alleges, among other things, that SCANA, SCE&G and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. The SCE&G Ratepayer Class Action settlement described previously contemplates dismissal of claims by SCE&G ratepayers in this case against SCE&G, SCANA and their officers. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

State Court Shareholder Actions

In September 2017, a purported shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina. In September 2018, this action was consolidated with another action in the Business Court Pilot

Program in Richland County. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the NND Project, and that the defendants were unjustly enriched by bonuses they were paid in connection with the project. The defendants have filed a motion to dismiss the consolidated action in favor of the pending federal derivative action. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal has been consolidated with a similar appeal and remains pending. In October 2018, the U.S. District Court for the District of South Carolina granted Dominion Energy’s motion to stay pending appeal. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

In February 2018, a purported class action was filed against certain former directors of SCANA and SCE&G and Dominion Energy in the State Court of Common Pleas in Richland County, South Carolina. The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the City of Warren Lawsuit. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the State Court of Common Pleas in Richland County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal has been consolidated with the City of Warren Lawsuit. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

Federal Court Shareholder Action

In November 2017, a purported shareholder derivative action was filed against SCANA and certain former executive officers and directors in the U.S. District Court of the District of South Carolina. Another purported shareholder derivative action was filed against nearly all of these defendants. In January 2018, the U.S. District Court for the District of South Carolina consolidated these suits, and the plaintiffs filed a consolidated amended complaint. The plaintiffs allege, among other things, that the defendants violated their fiduciary duties to shareholders by

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disseminating false and misleading information about the NND Project, failing to maintain proper internal controls, failing to properly oversee and manage SCANA and that the individual defendants were unjustly enriched in their compensation. In June 2018, the court denied the defendants’ motions to dismiss and in October 2018, the court denied SCANA’s motion to stay all proceedings pending investigation by a Special Litigation Committee, with leave to refile after the SCANA Merger Approval Order was issued. The plaintiffs have agreed to a stay of this action on the condition that defendants file a motion for judgment on the pleadings, which was filed in January 2019. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

Federal Court 10b-5 and Merger Actions

In September 2017, a purported class action was filed against SCANA and certain former executive officers and directors in the U.S. District Court for the District of South Carolina. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants. In January 2018, the U.S. District Court for the District of South Carolina consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated thereunder, and that the individually named defendants are liable under §20(a) of same act. In June 2018, the defendants filed motions to dismiss, which are pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

Employment Class Action and Indemnification

In July 2018, a case filed in the U.S. District Court for the District of South Carolina was certified as a class action on behalf of persons who were formerly employed at the NND Project. The plaintiffs allege, among other things, that SCANA, Fluor Corporation and Fluor Enterprises, Inc. violated the Worker Adjustment and Retraining Notification Act in connection with the decision to stop construction at the NND Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment, which is estimated to be as much as $75 million. SCE&G as co-owner of the NND project would have a 55% proportional share in the ultimate outcome. The ultimate loss could rise due to the Fluor defendants seeking indemnification from SCE&G.

In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against SCE&G and Santee Cooper. The plaintiffs make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants’ alleged failure and refusal to defend and indemnify the Fluor defendants in the aforementioned case. These cases are pending.

FILOT Litigation and Related Matters

In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against SCE&G in the State Court of Common Pleas in Fairfield County, South Carolina,

making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of implied duty of good faith and fair dealing and unfair trade practices related to SCE&G’s termination of the FILOT agreement between SCE&G and Fairfield County related to the NND Project. The plaintiff sought a temporary and permanent injunction to prevent SCE&G from terminating the FILOT agreement. The plaintiff withdrew the motion for temporary injunction in December 2017. Dominion Energy is currently unable to make an estimate of the potential impacts to its consolidated financial statements related to this matter. This case is pending.

Governmental Proceedings and Investigations

In June 2018, SCE&G received a notice of proposed assessment of approximately $410 million, excluding interest, from the SCDOR following its audit of SCE&G’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NND Project, is based on the SCDOR’s position that SCE&G’s sales and use tax exemption for the NND Project does not apply because the facility will not become operational. SCE&G has protested the proposed assessment, which remains pending, and recorded an $11 million liability in its Consolidated Balance Sheet as of December 31, 2018 for its share of any taxes ultimately due.

In September and October 2017, SCANA was served with subpoenas issued by the U.S. Attorney’s Office for the District of South Carolina and the Staff of the SEC’s Division of Enforcement seeking documents related to the NND Project. In addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and SCE&G. These matters are pending. SCANA and SCE&G are cooperating fully with the investigations; however, Dominion Energy cannot currently predict whether or to what extent SCANA or SCE&G may incur a material liability.

Other

In December 2018, arbitration proceedings commenced between SCE&G and Cameco Corporation related to a supply agreement signed in May 2008. This agreement provides the terms and conditions under which SCE&G agreed to purchase uranium hexafluoride from Cameco Corporation over a period from 2010 to 2020. Cameco Corporation alleges that SCE&G violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for 2017 and 2018 delivery years. SCE&G denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement. Dominion Energy cannot determine the outcome or timing of this matter.

COMMITMENTS AND CONTINGENCIES

Abandoned NND Project

SCE&G, for itself and as agent for Santee Cooper, entered into an engineering, construction and procurement contract with Westinghouse and WECTEC in 2008 for the design and construction of the NND Project, of which SCE&G’s ownership share is 55%. Various difficulties were encountered in connection with the project. The ability of Westinghouse and WECTEC to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the con

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Combined Notes to Consolidated Financial Statements, Continued

struction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters preceded the filing for bankruptcy protection by Westinghouse and WECTEC in March 2017, and were the subject of comprehensive analyses performed by SCANA and Santee Cooper.

Based on the results of SCANA’s analysis, and in light of Santee Cooper’s decision to suspend construction on the NND Project, in July 2017, SCANA determined to stop the construction of the units and to pursue recovery of costs incurred in connection with the construction under the abandonment provisions of the Base Load Review Act or through other means. This decision by SCANA became the focus of numerous legislative, regulatory and legal proceedings. Some of these proceedings remain unresolved and are described above under the heading Legal Proceedings.

In September 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of Westinghouse and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by Westinghouse and WECTEC of the contract, and assert against Westinghouse and WECTEC any and all claims that are based thereon or that may be related thereto. SCE&G and Santee Cooper remain responsible for any claims that may be made by Westinghouse and WECTEC against them relating to the contract.

Westinghouse’s reorganization plan was confirmed by the Bankruptcy Court and became effective in August 2018. In connection with the effectiveness of the reorganization plan, the contract associated with the NND Project was deemed rejected. SCE&G is contesting approximately $285 million of filed liens in Fairfield County, South Carolina. Most of these asserted liens are claims that relate to work performed by Westinghouse subcontractors before the Westinghouse bankruptcy, although some of them are claims arising from work performed after the Westinghouse bankruptcy.

Westinghouse has indicated that some unsecured creditors have sought or may seek amounts beyond what Westinghouse allocated when it submitted its reorganization plan to the Bankruptcy Court. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the bankruptcy reorganization plan allocated by Westinghouse, it is possible that the reorganization plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant.

SCE&G and Santee Cooper are responsible for amounts owed to Westinghouse for valid work performed by Westinghouse subcontractors on the NND Project after the Westinghouse bankruptcy filing until termination of the interim assessment agreement. SCE&G does not believe that the claims asserted related to the interim assessment agreement period will exceed the amounts previously funded, whether relating to claims already paid or those remaining to be paid. SCE&G intends to oppose

any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the interim assessment agreement. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.

Further, some Westinghouse subcontractors who have made claims against Westinghouse in the bankruptcy proceeding also filed against SCE&G and Santee Cooper in South Carolina state court for damages. Many of these claimants have also asserted construction liens against the NND Project site. SCE&G also intends to oppose these claims and liens. With respect to claims of Westinghouse Subcontractors, SCE&G believes there were sufficient amounts previously funded during the interim assessment agreement period to pay such validly asserted claims. With respect to the Westinghouse subcontractor claims which relate to other periods, SCE&G understands that such claims will be paid pursuant to Westinghouse’s confirmed bankruptcy reorganization plan. SCE&G further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, SCE&G believes that the Westinghouse subcontractors may be paid substantially (and potentially in full) by Westinghouse. While Dominion Energy cannot be assured that it will not have any exposure on account of unpaid Westinghouse subcontractor claims, which SCE&G is presently disputing, Dominion Energy believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.

Environmental Matters

Contingencies involving environmental matters, including ash pond and landfill closure costs, affecting SCANA have been included within Note 22.

Nuclear Insurance and Spent Nuclear Fuel

SCE&G’s maximum assessment for a nuclear incident under the Price-Anderson Amendments Act of 1988 would be $92 million per incident, but not more than $14 million per year, for its proportionate ownership interest in Summer. SCE&G currently maintains insurance policies, for itself and on behalf of Santee Cooper, with NEIL. The policies provide coverage to Summer for property damage and outage costs up to $2.8 billion resulting from an event of nuclear origin. The NEIL policies, in aggregate, are subject to a maximum loss of $2.8 billion for any single loss occurrence. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $23 million.

In addition, SCE&G currently maintains an excess property insurance policy, for itself and on behalf of Santee Cooper. The policy provides coverage to Summer for property damage and outage costs up to $415 million resulting from an event of non-nuclear origin. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $2 million.

SCE&G entered into a contract with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982.

Long-Term Purchase Agreements

SCANA has the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and

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that a third party has used to secure financing for the facility that will provide the contracted goods or services:

	2019		2020		2021		2022		2023		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	31	$	30	$	30	$	30	$	30	$	310	$	461

(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities which expire at various dates through 2046. Capacity payments under the contracts are generally based on fixed dollar amounts per month.

Lease Commitments

SCANA is obligated under various operating leases for land, office space, furniture, equipment, rail cars and airplanes. Such leases expire at various dates through 2057.

	2019		2020		2021		2022		2023		Thereafter		Total
(millions)
Operating leases	$	10	$	8	$	7	$	6	$	4	$	30	$	65

Unaudited Pro Forma Information

Dominion Energy incurred transaction costs of $27 million, recorded in other operations and maintenance expense in the Consolidated Statements of Income for the year end December 31, 2018. These costs consist of professional fees and other miscellaneous costs.

The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the SCANA Combination had taken place on January 1, 2018. The unaudited pro forma financial information has been presented for illustrative purposes only and may change as Dominion Energy finalizes its valuation of certain assets acquired and liabilities assumed at the acquisition date. The unaudited pro forma financial information is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.

	Twelve Months Ended December 31,
	2018(1)
(millions, except EPS)
Operating Revenue	$	17,505
Net income attributable to Dominion Energy		2,081
Earnings Per Common Share – Basic	$	2.78
Earnings Per Common Share – Diluted	$	2.77

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

ACQUISITION OF DOMINION ENERGY QUESTAR

In September 2016, Dominion Energy completed the Dominion Energy Questar Combination and Dominion Energy Questar, a Rockies-based integrated natural gas company consisting of Questar Gas, Wexpro and Dominion Energy Questar Pipeline, became a wholly-owned subsidiary of Dominion Energy. Questar Gas has regulated gas distribution operations in Utah, southwestern Wyoming and southeastern Idaho. Wexpro develops and produces natural gas from reserves supplied to Questar Gas under a cost-of-service framework. Dominion Energy Questar Pipeline provides FERC-regulated interstate natural gas transportation and storage services in Utah, Wyoming and western Colorado. The Dominion Energy Questar Combination provides Dominion Energy with pipeline infrastructure that provides a principal

source of gas supply to Western states. Dominion Energy Questar’s regulated businesses also provide further balance between Dominion Energy’s electric and gas operations.

In accordance with the terms of the Dominion Energy Questar Combination, at closing, each share of issued and outstanding Dominion Energy Questar common stock was converted into the right to receive $25.00 per share in cash. The total consideration was $4.4 billion based on 175.5 million shares of Dominion Energy Questar outstanding at closing.

Dominion Energy financed the Dominion Energy Questar Combination through the: (1) August 2016 issuance of $1.4 billion of 2016 Equity Units, (2) August 2016 issuance of $1.3 billion of senior notes, (3) September 2016 borrowing of $1.2 billion under a term loan agreement and (4) $500 million of the proceeds from the April 2016 issuance of common stock.

Purchase Price Allocation

Dominion Energy Questar’s assets acquired and liabilities assumed were measured at estimated fair value at the closing date and are included in the Gas Infrastructure operating segment. The majority of operations acquired are subject to the rate-setting authority of FERC, as well as the Utah Commission and/or the Wyoming Commission and therefore are accounted for pursuant to ASC 980, Regulated Operations. The fair values of Dominion Energy Questar’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts.

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

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

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at closing which reflects the following adjustments from the preliminary valuation recognized during the measurement period. During the fourth quarter of 2016, certain modifications were made to preliminary valuation amounts for acquired property, plant and equipment, current liabilities, and deferred income taxes, resulting in a $6 million net decrease to goodwill, which related primarily to

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Combined Notes to Consolidated Financial Statements, Continued

the sale of Questar Fueling Company in December 2016 as further described in the Sale of Questar Fueling Company. In the third quarter of 2017, certain modifications were made to the valuation amounts for regulatory liabilities, current liabilities and deferred income taxes, resulting in a $6 million net increase to goodwill recorded in Dominion Energy’s Consolidated Balance Sheets. The modifications relate primarily to the finalization of Dominion Energy Questar’s 2016 tax return for the period January 1, 2016 through the Dominion Energy Questar Combination, as well as certain regulatory adjustments.

	Amount
(millions)
Total current assets	$	224
Investments(1)		58
Property, plant and equipment, net(2)		4,131
Goodwill		3,111
Total deferred charges and other assets, excluding goodwill		75
Total Assets		7,599
Total current liabilities(3)		793
Long-term debt(4)		963
Deferred income taxes		807
Regulatory liabilities		259
Asset retirement obligations		160
Other deferred credits and other liabilities		220
Total Liabilities		3,202
Total purchase price		4,397

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

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

(3) Includes $301 million of short-term debt, of which no amounts remain outstanding at December 31, 2018, as well as a $250 million variable interest rate term loan due in August 2017 that was paid in July 2017.

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

Regulatory Matters

The transaction required approval of Dominion Energy Questar’s shareholders, clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act and approval from both the Utah Commission and the Wyoming Commission. In February 2016, the Federal Trade Commission granted antitrust approval of the Dominion Energy Questar Combination under the Hart-Scott-Rodino Act. In May 2016, Dominion Energy Questar’s shareholders voted to approve the Dominion Energy Questar Combination. In August 2016 and September 2016, approvals were granted by the Utah Commission and the Wyoming Commission, respectively. Information regarding the transaction was also provided to the Idaho Commission, who acknowledged the Dominion Energy Questar Combination in October 2016, and directed Dominion Energy Questar to notify the Idaho Commission when it makes filings with the Utah Commission.

With the approval of the Dominion Energy Questar Combination in Utah and Wyoming, Dominion Energy agreed to the following:

• Contribution of $75 million to Dominion Energy Questar’s qualified and non-qualified defined-benefit pension plans and its other post-employment benefit plans within

six months of the closing date. This contribution was made in January 2017.

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

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

Results of Operations and Unaudited Pro Forma Information

The impact of the Dominion Energy Questar Combination on Dominion Energy’s operating revenue and net income attributable to Dominion Energy in the Consolidated Statements of Income for the twelve months ended December 31, 2016 was an increase of $379 million and $73 million, respectively.

Dominion Energy incurred transaction and transition costs in 2018, 2017 and 2016, of which $9 million, $26 million and $58 million was recorded in other operations and maintenance expense, respectively, and $16 million was recorded in interest and related charges in 2016 in Dominion Energy’s Consolidated Statements of Income. These costs consist of the amortization of financing costs, the charitable contribution commitment described above, employee-related expenses, professional fees, and other miscellaneous costs.

The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the Dominion Energy Questar Combination had taken place on January 1, 2016. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.

	Twelve Months Ended December 31,
	2016(1)
(millions, except EPS)
Operating Revenue	$	12,497
Net income attributable to Dominion Energy		2,300
Earnings Per Common Share – Basic	$	3.73
Earnings Per Common Share – Diluted	$	3.73

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

Contribution of Dominion Energy Questar Pipeline to Dominion Energy Midstream

In October 2016, Dominion Energy entered into the Contribution Agreement under which Dominion Energy contributed Dominion Energy Questar Pipeline to Dominion Energy Midstream. Upon closing of the agreement on December 1, 2016, Dominion Energy Midstream became the owner of all of the issued and outstanding membership interests of Dominion Energy Questar Pipeline in exchange for consideration consisting

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of Dominion Energy Midstream common and convertible preferred units with a combined value of $467 million and cash payment of $823 million, $300 million of which is considered a debt-financed distribution, for a total of $1.3 billion. In addition, under the terms of the Contribution Agreement, Dominion Energy Midstream repurchased 6,656,839 common units from Dominion Energy, and repaid its $301 million promissory note to Dominion Energy in December 2016. The cash proceeds from these transactions were utilized in December 2016 to repay the $1.2 billion term loan agreement borrowed in September 2016. Since Dominion Energy consolidates Dominion Energy Midstream for financial reporting purposes, the transactions associated

with the Contribution Agreement were eliminated upon consolidation. See Note 5 for the tax impacts of the transactions.

Sale of Questar Fueling Company

In December 2016, Dominion Energy completed the sale of Questar Fueling Company. The proceeds from the sale were $28 million, net of transaction costs. No gain or loss was recorded in Dominion Energy’s Consolidated Statements of Income, as the sale resulted in measurement period adjustments to the net assets acquired of Dominion Energy Questar. See the Purchase Price Allocation section above for additional details on the measurement period adjustments recorded.

Wholly-Owned Merchant Solar Projects

ACQUISITIONS

The following table presents significant completed acquisitions of wholly-owned merchant solar projects by Dominion Energy.

Completed Acquisition Date	Seller	Number of Projects			Project Location	Project Name(s)	Initial Acquisition (millions)(1)		Project Cost (millions)(2)		Date of Commercial Operations	MW Capacity
February 2017	Community Energy Solar, LLC		1		Virginia	Amazon Solar Farm Virginia—Southhampton	$	29	$	205	December 2017		100
March 2017	Solar Frontier Americas Holding LLC		1	(3)	California	Midway II		77		78	June 2017		30
May 2017	Cypress Creek Renewables, LLC		1		North Carolina	IS37		154		160	June 2017		79
June 2017	Hecate Energy Virginia C&C LLC		1		Virginia	Clarke County		16		16	August 2017		10
June 2017	Strata Solar Development, LLC/Moorings Farm 2 Holdco, LLC		2		North Carolina	Fremont, Moorings 2		20		20	November 2017		10
September 2017	Hecate Energy Virginia C&C LLC		1		Virginia	Cherrydale		40		41	November 2017		20
October 2017	Strata Solar Development, LLC		2		North Carolina	Clipperton, Pikeville		20		21	November 2017		10

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

(2) Includes acquisition cost.

(3) In April 2017, Dominion Energy discontinued efforts on the acquisition of the additional 20 MW solar project from Solar Frontier Americas Holding LLC.

In addition during 2016, Dominion Energy acquired 100% of the equity interests of seven solar projects in Virginia, North Carolina and South Carolina for an aggregate purchase price of $32 million, all of which was allocated to property, plant and equipment. The projects cost $421 million in total, including initial acquisition costs, and generate 221 MW combined. One of the projects commenced commercial operations in 2016 and the remaining projects commenced commercial operations in 2017.

Long-term power purchase, interconnection and operation and maintenance agreements have been executed for all of the projects described above. These projects are included in the Power Generation operating segment. Dominion Energy has claimed federal investment tax credits on these solar projects.

SALE OF INTEREST IN MERCHANT SOLAR PROJECTS

In September 2015, Dominion Energy 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 425 MW, to SunEdison. 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.

Non-Wholly-Owned Merchant Solar Projects

ACQUISITIONS OF FOUR BROTHERS AND THREE CEDARS

In June 2015, Dominion Energy acquired 50% of the units in Four Brothers from SunEdison for $64 million of consideration. Four Brothers operates four solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, generating 320 MW, at a cost of approximately $670 million.

In September 2015, Dominion Energy acquired 50% of the units in Three Cedars from SunEdison for $43 million of consideration. Three Cedars operates three solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, generating 210 MW, at a cost of approximately $450 million.

The Four Brothers and Three Cedars facilities operate under long-term power purchase, interconnection and operation and maintenance agreements. Dominion Energy claimed 99% of the federal investment tax credits on the projects.

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Combined Notes to Consolidated Financial Statements, Continued

Dominion Energy has assumed the majority of the agreements to provide administrative and support services in connection with 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 years ended December 31, 2018, 2017 and 2016.

In November 2016, NRG acquired the 50% of units in Four Brothers and Three Cedars previously held by SunEdison. Subsequent to Dominion Energy’s acquisition of Four Brothers and

Three Cedars, SunEdison and NRG made contributions to Four Brothers and Three Cedars of $301 million in aggregate through December 31, 2017, which are reflected as noncontrolling interests in the Consolidated Balance Sheets. In August 2018, NRG’s ownership in Four Brothers and Three Cedars was transferred to GIP.

DOMINION ENERGY AND DOMINION ENERGY GAS

Blue Racer

See Note 9 for a discussion of transactions related to Blue Racer.

NOTE 4. OPERATING REVENUE

The Companies’ operating revenue, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, consists of the following:

Year Ended December 31,	2018
(millions)
Dominion Energy
Regulated electric sales:
Residential	$	3,413
Commercial		2,503
Industrial		490
Government and other retail		854
Wholesale		137
Nonregulated electric sales		1,294
Regulated gas sales:
Residential		818
Commercial		221
Other		36
Nonregulated gas sales		214
Regulated gas transportation and storage:
FERC-regulated		1,091
State-regulated		640
Nonregulated gas transportation and storage		442
Other regulated revenues		179
Other nonregulated revenues(1)(2)		563
Total operating revenue from contracts with customers		12,895
Other revenues(2)(3)		471
Total operating revenue	$	13,366
Virginia Power
Regulated electric sales:
Residential	$	3,413
Commercial		2,503
Industrial		490
Government and other retail		854
Wholesale		137
Other regulated revenues		132
Other nonregulated revenues(1)(2)		55
Total operating revenue from contracts with customers		7,584
Other revenues(1)(3)		35
Total operating revenue	$	7,619
Dominion Energy Gas
Regulated gas sales:
Residential	$	81
Other		27
Nonregulated gas sales(1)		13
Regulated gas transportation and storage:
FERC-regulated(1)		763
State-regulated(1)		605
NGL revenue(1)(2)		223
Management service revenue(1)		205
Other regulated revenues(1)		22
Other nonregulated revenues(1)		10
Total operating revenue from contracts with customers		1,949
Other revenues		(9	)
Total operating revenue	$	1,940

116

(1) See Notes 9 and 24 for amounts attributable to related parties and affiliates.

(2) Amounts above include $241 million and $206 million for the year ended December 31, 2018 primarily consisting of NGL sales at Dominion Energy and Dominion Energy Gas, respectively, which are considered to be goods transferred at a point in time. In addition, the amounts include $17 million and $11 million of sales of renewable energy credits at both Dominion Energy and Virginia Power for the year ended December 31, 2018, respectively, which are considered to be goods transferred at a point in time.

(3) Amounts above include $15 million of alternative revenue at Dominion Energy and Virginia Power for the year ended December 31, 2018.

The table below discloses the aggregate amount of the transaction price allocated to fixed-price performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and when the Companies expect to recognize this revenue. These revenues relate to contracts containing fixed prices where the Companies will earn the associated revenue over time as they stand ready to perform services provided. This disclosure does not include revenue related to performance obligations that are part of a contract with original durations of one year or less. In addition, this disclosure does not include expected consideration related to performance obligations for which the Companies elect to recognize revenue in the amount they have a right to invoice.

Revenue expected to be recognized on multi-year contracts in place at December 31, 2018	2019		2020		2021		2022		2023		Thereafter		Total
(millions)
Dominion Energy	$	1,643	$	1,563	$	1,448	$	1,319	$	1,154	$	13,693	$	20,820
Virginia Power		21		3		1		—		—		—		25
Dominion Energy Gas		600		560		475		384		268		1,612		3,899

Contract assets represent an entity’s right to consideration in exchange for goods and services that the entity has transferred to a customer. At December 31, 2018 and December 31, 2017, Dominion Energy’s contract asset balances were $42 million and $46 million, respectively. Dominion Energy Gas’ contract asset balances were $58 million and $66 million at December 31, 2018 and December 31, 2017, respectively. Dominion Energy and Dominion Energy Gas’ contract assets are recorded in other deferred charges and other assets in the Consolidated Balance Sheets. Contract liabilities represent an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration, or the amount that is due, from the customer. At December 31, 2018 and December 31, 2017, Dominion Energy’s contract liability balances were $106 million and $132 million, respectively. At December 31, 2018 and December 31, 2017, Virginia Power’s contract liability balances were $22 million and $50 million, respectively. At December 31, 2018 and December 31, 2017, Dominion Energy Gas’ contract liability balances were $40 million and $41 million, respectively. During the year ended December 31, 2018, Dominion Energy, Virginia Power and Dominion Energy Gas recognized revenue of $94 million, $25 million and $41 million, respectively, from the beginning contract liability balances as the Companies fulfilled their obligations to provide service to their customers. The Companies’ contract liabilities are recorded in other current liabilities and other deferred credits and other liabilities in the Consolidated Balance Sheets.

The Companies’ operating revenue, prior to the adoption of revised guidance for revenue recognition from contracts with customers, consisted of the following:

Year Ended December 31,	2017		2016
(millions)
Dominion Energy
Electric sales:
Regulated	$	7,383	$	7,348
Nonregulated		1,429		1,519
Gas sales:
Regulated		1,067		500
Nonregulated		457		354
Gas transportation and storage		1,786		1,636
Other		464		380
Total operating revenue	$	12,586	$	11,737
Virginia Power
Regulated electric sales	$	7,383	$	7,348
Other		173		240
Total operating revenue	$	7,556	$	7,588
Dominion Energy Gas
Gas sales:
Regulated	$	87	$	119
Nonregulated		20		13
Gas transportation and storage		1,435		1,307
NGL revenue		91		62
Other		181		137
Total operating revenue	$	1,814	$	1,638

NOTE 5. INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. The Companies are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

117

Combined Notes to Consolidated Financial Statements, Continued

The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies as discussed in Note 2. The 2017 Tax Reform Act reduced the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. At the date of enactment, deferred tax assets and liabilities were remeasured based upon the new 21% enacted tax rate expected to apply when temporary differences are realized or settled. The specific provisions related to regulated public utilities in the 2017 Tax Reform Act generally allow for the continued deductibility of interest expense, changed the tax depreciation of certain property acquired after September 27, 2017, and continued certain rate normalization requirements for accelerated depreciation benefits.

As indicated in Note 2, certain of the Companies’ operations, including accounting for income taxes, are subject to regulatory accounting treatment. For regulated operations, many of the changes in deferred taxes represent amounts probable of collection from or refund to customers, and were recorded as either an

increase to a regulatory asset or liability. The 2017 Tax Reform Act included provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred taxes may be determined by our regulators. See Note 13 for more information.

The Companies have accounted for the effects of the 2017 Tax Reform Act, although changes could occur as additional guidance is issued and finalized. In addition, certain states in which the Companies operate may or may not conform to some or all of the provisions of the 2017 Tax Reform Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities and could be material. The changes in deferred taxes resulting from the 2017 Tax Reform Act, and the Companies’ interpretations of proposed regulations issued in 2018, were recorded as either an increase to a regulatory liability or as an adjustment to the deferred tax provision.

Continuing Operations

Details of income tax expense for continuing operations including noncontrolling interests were as follows:

	Dominion Energy									Virginia Power									Dominion Energy Gas
Year Ended December 31,	2018			2017			2016			2018			2017			2016			2018			2017			2016
(millions)
Current:
Federal	$	(45	)	$	(1	)	$	(155	)	$	36		$	432		$	168		$	23		$	16		$	(27	)
State		108			(26	)		85			40			73			90			30			8			4
Total current expense (benefit)		63			(27	)		(70	)		76			505			258			53			24			(23	)
Deferred:
Federal
2017 Tax Reform Act impact		46			(851	)		—			21			(93	)		—			(11	)		(197	)		—
Taxes before operating loss carryforwards and investment tax credits		436			739			1,050			199			319			435			48			199			239
Tax utilization expense (benefit) of operating loss carryforwards		92			174			(161	)		—			4			(2	)		—			5			(2	)
Investment tax credits		(56	)		(200	)		(248	)		(51	)		(23	)		(25	)		—			—			—
State		(1	)		132			50			55			59			27			(4	)		20			1
Total deferred expense (benefit)		517			(6	)		691			224			266			435			33			27			238
Investment tax credit-gross deferral		2			5			35			2			5			35			—			—			—
Investment tax credit-amortization		(2	)		(2	)		(1	)		(2	)		(2	)		(1	)		—			—			—
Total income tax expense (benefit)	$	580		$	(30	)	$	655		$	300		$	774		$	727		$	86		$	51		$	215

The 2017 Tax Reform Act reduced the statutory federal income tax rate to 21% beginning in January 2018. Accordingly, current income taxes, and deferred income taxes that originate in 2018, are recorded at the new 21% rate. Dominion Energy had less than $1 million of state deferred income tax expense as a result of the reversal of deferred taxes upon the sale of its interest in Blue Racer and Fairless and Manchester. Dominion Energy’s current federal income taxes primarily include the recognition of a $47 million benefit related to a carryback claim for specified liability losses involving prior tax years.

The accounting for the reduction in the corporate income tax rate decreased deferred income tax expense by $851 million at Dominion Energy, $93 million at Virginia Power, and $197 million for Dominion Energy Gas for the year ending December 31, 2017. The decrease in deferred income taxes at Dominion Energy primarily relates to the remeasurement of deferred taxes on merchant operations and includes the effects at Virginia Power and Dominion Energy Gas. Virginia Power and Dominion Energy Gas have certain regulatory assets and liabilities that have not yet been charged or returned to customers through rates, or on which they do not earn a return, including unrecognized pension and other postretirement benefits. The remeasurement of the deferred taxes on these regulatory balances was charged to continuing operations in 2017. For ratemaking purposes, Dominion Energy Gas’ subsidiary DETI follows the cash method on pension contributions. Deferred taxes recorded on pension balances as required by GAAP are not included as a component of rates and therefore the remeasurement of these deferred taxes were charged to continuing operations in 2017.

In 2016, Dominion Energy realized a taxable gain resulting from the contribution of Dominion Energy Questar Pipeline to Dominion Energy Midstream. The contribution and related transactions resulted in increases in the tax basis of Dominion Energy Questar Pipeline’s assets and the number of Dominion Energy Midstream’s common and convertible preferred units held by noncontrolling interests. The direct tax effects of the transactions included a provision for current income taxes ($212 million) and an offsetting benefit for deferred income taxes ($96 million) and were charged to common shareholders’ equity. The federal tax liability was reduced by $129 million of tax

118

credits generated in 2016 that otherwise would have resulted in additional credit carryforwards and a $17 million benefit provided by the domestic production activities deduction. These benefits, as indirect effects of the contribution transaction, were reflected in Dominion Energy’s 2016 current federal income tax expense.

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

	Dominion Energy									Virginia Power									Dominion Energy Gas
Year Ended December 31,	2018			2017			2016			2018			2017			2016			2018			2017			2016
U.S. statutory rate		21.0	%		35.0	%		35.0	%		21.0	%		35.0	%		35.0	%		21.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		3.0			2.0			2.4			4.7			3.7			3.8			3.2			2.4			0.5
Investment tax credits		(1.9	)		(6.3	)		(11.7	)		(3.5	)		(0.8	)		—			—			—			—
Production tax credits		(0.7	)		(0.7	)		(0.8	)		(0.7	)		(0.4	)		(0.5	)		—			—			—
Valuation allowances		0.3			0.2			1.2			—			—			0.1			1.8			0.3			—
Reversal of excess deferred income taxes		(2.0	)		—			—			(3.2	)		—			—			(1.7	)		—			—
Federal legislative change		1.5			(27.5	)		—			1.3			(4.0	)		—			(2.8	)		(29.5	)		—
State legislative change		(0.6	)		—			(0.6	)		—			—			—			0.2			—			—
AFUDC—equity		(0.8	)		(1.4	)		(0.6	)		(0.5	)		(0.6	)		(0.6	)		(0.6	)		(0.9	)		(0.2	)
Employee stock ownership plan deduction		(0.4	)		(0.6	)		(0.6	)		—			—			—			—			—			—
Other, net		(0.9	)		(1.7	)		(1.4	)		(0.1	)		0.6			(0.4	)		1.2			0.4			0.1
Effective tax rate		18.5	%		(1.0	)%		22.9	%		19.0	%		33.5	%		37.4	%		22.3	%		7.7	%		35.4	%

For the Companies’ rate-regulated entities, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, which in some cases will be 35%. The Companies have recorded an estimate of the portion of excess deferred income tax amortization in 2018, and changes in estimates of amounts probable of collection from or return to customers. The reversal of these excess deferred income taxes will impact the effective tax rate, and may ultimately impact rates charged to customers. As described in Note 13 to the Consolidated Financial Statements, the Companies decreased revenue and increased regulatory liabilities to offset these deferred tax impacts in accordance with applicable regulatory commission orders or formula rate mechanisms.

In 2018, the Companies applied the provisions of recently proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017 through December 31, 2017. The application of these changes increased Dominion Energy’s 2017 net operating loss carryforward, the benefit of which will be recognized at the 21% rate. As a result, Dominion Energy’s effective tax rate reflects a $23 million increase to deferred income tax expense associated with the remeasurement of this deferred tax asset. The application of these proposed regulations at Dominion Energy Gas had no impact on income tax expense as the changes in, and remeasurement of, deferred tax liabilities increased regulatory liabilities by $35 million. The effects of these changes at Virginia Power were immaterial. These amounts and adjustments represent the Companies’ best estimate based on available information, and could be subject to change based on additional guidance in yet to be finalized regulations. In addition, changes in estimates of amounts probable of return to or collection from customers increased deferred income tax expense at Virginia Power by $23 million and increased regulatory liabilities by $31 million. At Dominion Energy Gas similar changes in estimates decreased income tax expense by $11 million and regulatory liabilities by $16 million. These changes also impacted Dominion Energy. In addition, Dominion Energy and Dominion Energy Gas’ effective tax rates reflect the impacts of a state legislative change enacted in the second quarter of 2018 that was retroactive to January 1, 2018.

In 2017, the Companies’ effective tax rates reflect the net benefit of remeasurement of deferred taxes resulting from the lower corporate income tax rate promulgated by the 2017 Tax Reform Act, and the completion of audits by state tax authorities that resulted in the recognition of previously unrecognized tax benefits. At December 31, 2016, Virginia Power’s unrecognized tax benefits included state refund claims for open tax years through 2011. Management believed settlement of the claims, including interest thereon, within the next twelve months was remote. In June 2017, Virginia Power received and accepted a cash offer to settle the refund claims. As a result of the settlement, Virginia Power decreased its unrecognized tax benefits by $8 million, and recognized a $2 million tax benefit, which impacted its effective tax rate. Also in connection with this settlement, Virginia Power realized interest income of $11 million, which is reflected in other income in the Consolidated Statements of Income.

In 2016, Dominion Energy’s effective tax rate reflects a valuation allowance on a state credit not expected to be utilized by a Dominion Energy subsidiary which files a separate state return.

119

Combined Notes to Consolidated Financial Statements, Continued

The Companies’ deferred income taxes consist of the following:

	Dominion Energy						Virginia Power						Dominion Energy Gas
At December 31,	2018			2017			2018			2017			2018			2017
(millions)
Deferred income taxes:
Total deferred income tax assets	$	2,748		$	2,686		$	1,054			$   923			$   318		$	320
Total deferred income tax liabilities		7,813			7,158			4,020			3,600			1,783			1,774
Total net deferred income tax liabilities	$	5,065		$	4,472		$	2,966			$2,677			$1,465		$	1,454
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	$	4,933		$	5,056		$	3,367			$2,969			$1,170		$	1,132
Excess deferred income taxes		(993	)		(1,050	)		(678	)		(687	)		(254	)		(244	)
Nuclear decommissioning		815			829			273			260			—			—
Deferred state income taxes		626			834			284			378			175			227
Federal benefit of deferred state income taxes		(132	)		(175	)		(60	)		(79	)		(37	)		(48	)
Deferred fuel, purchased energy and gas costs		60			1			59			(3	)		1			2
Pension benefits		81			141			(132	)		(104	)		431			419
Other postretirement benefits		(5	)		(51	)		55			44			(1	)		(2	)
Loss and credit carryforwards		(1,546	)		(1,536	)		(183	)		(111	)		(7	)		(4	)
Valuation allowances		158			146			5			5			12			3
Partnership basis differences		1,135			473			—			—			26			26
Other		(67	)		(196	)		(24	)		5			(51	)		(57	)
Total net deferred income tax liabilities	$	5,065		$	4,472		$	2,966			$2,677			$1,465		$	1,454
Deferred Investment Tax Credits – Regulated Operations		51			51			51			51			—			—
Total Deferred Taxes and Deferred Investment Tax Credits	$	5,116		$	4,523		$	3,017			$2,728			$1,465		$	1,454

The most significant impact reflected for the 2017 Tax Reform Act is the adjustment of the net accumulated deferred income tax liability for the reduction in the corporate income tax rate to 21%. In addition to amounts recognized in deferred income tax expense, the impacts of the 2017 Tax Reform Act decreased the accumulated deferred income tax liability by $3.1 billion at Dominion Energy, $1.9 billion at Virginia Power and $0.8 billion at Dominion Energy Gas at December 31, 2017. At Dominion Energy, the December 31, 2017 balance sheet reflected the impact of the 2017 Tax Reform Act on our regulatory liabilities which increased our regulatory liabilities by $4.2 billion, and created a corresponding deferred tax asset of $1.1 billion. At Virginia Power, our regulatory liabilities increased $2.6 billion, and created a deferred tax asset of $0.7 billion. At Dominion Energy Gas, our regulatory liabilities increased $1.0 billion, and created a deferred tax asset of $0.2 billion. These adjustments had no impact on 2017 cash flows.

At December 31, 2018, Dominion Energy had the following deductible loss and credit carryforwards:

	Deductible Amount		Deferred Tax Asset		Valuation Allowance			Expiration Period
(millions)
Federal losses		$   120	$	25		$    —			2034
Federal investment credits		—		1,007		—			2033-2038
Federal production credits		—		150		—			2031-2038
Other federal credits		—		62		—			2031-2038
State losses		1,126		73		(61	)		2019-2038
State minimum tax credits		—		122		—			No expiration
State investment and other credits		—		107		(90	)		2019-2025
Total		$1,246	$	1,546		$(151)

At December 31, 2018, Virginia Power had the following deductible loss and credit carryforwards:

	Deductible Amount		Deferred Tax Asset		Valuation Allowance			Expiration Period
(millions)
Federal losses		$  1		$   —		$ —			2034
Federal investment credits		—		113		—			2034-2038
Federal production and other credits		—		61		—			2031-2038
State investment credits		—		9		(5	)		2024
Total		$  1		$183		$(5	)

At December 31, 2018, Dominion Energy Gas had the following deductible loss and credit carryforwards:

	Deductible Amount		Deferred Tax Asset		Valuation Allowance			Expiration Period
(millions)
Other federal credits	$	—	$	1	$	—			2032-2037
State losses		53		5		(5	)		2036-2038
Total	$	53	$	6	$	(5	)

A reconciliation of changes in the Companies’ unrecognized tax benefits follows:

	Dominion Energy									Virginia Power									Dominion Energy Gas
	2018			2017			2016			2018			2017			2016			2018		2017			2016
(millions)
Balance at January 1	$	38		$	64		$	103		$	4		$	13		$	12			$ —	$	7			$29
Increases-prior period positions		10			1			9			—			—			4			—		—			1
Decreases-prior period positions		—			(9	)		(44	)		—			(1	)		(3	)		—		—			(19	)
Increases-current period positions		10			5			6			—			—			—			—		—			—
Settlements with tax authorities		(6	)		(23	)		(8	)		(1	)		(8	)		—			—		(7	)		(4	)
Expiration of statutes of limitations		(8	)		—			(2	)		(1	)		—			—			—		—			—
Balance at December 31	$	44		$	38		$	64		$	2		$	4		$	13			$—	$	—			$  7

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities

120

and expiration of statutes of limitations. For Dominion Energy and its subsidiaries, these unrecognized tax benefits were $37 million, $31 million and $45 million at December 31, 2018, 2017 and 2016, respectively. For Dominion Energy, the change in these unrecognized tax benefits increased income tax expense by $5 million in 2018 and decreased income tax expense by $9 million and $18 million in 2017 and 2016 respectively. For Virginia Power, these unrecognized tax benefits were $2 million, $3 million, and $9 million at December 31, 2018, 2017 and 2016, respectively. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by $2 million and $6 million in 2018 and 2017, respectively, and increased income tax expense by $1 million in 2016. For Dominion Energy Gas, these unrecognized tax benefits were less than $1 million, at December 31, 2018 and 2017, and $5 million at December 31, 2016. For Dominion Energy Gas, the change in these unrecognized tax benefits decreased income tax expense by less than $1 million, $5 million, and $11 million in 2018, 2017, and 2016, respectively.

Dominion Energy participates in the IRS Compliance Assurance Process which provides the opportunity to resolve complex tax matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions agreed to by the IRS. In 2018, Dominion Energy submitted carryback claims for specified liability losses involving prior tax years. These claims will be subject to IRS examination. With the exception of these claims, the IRS has completed its audit of tax years through 2017. The statute of limitations has not yet expired for tax years after 2012. Although Dominion Energy has not received a final letter indicating no changes to its taxable income for tax year 2017, no material adjustments are expected. The IRS examination of tax year 2018 is ongoing.

It is reasonably possible that settlement negotiations and expiration of statutes of limitations could result in a decrease in unrecognized tax benefits in 2019 by up to $18 million for Dominion Energy and less than $1 million for Virginia Power and Dominion Energy Gas. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could increase by up to $17 million for Dominion Energy and less than $1 million for Virginia Power and Dominion Energy Gas.

Otherwise, with regard to 2018 and prior years, Dominion Energy, Virginia Power and Dominion Energy Gas cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2019.

For each of the major states in which Dominion Energy operates, the earliest tax year remaining open for examination is as follows:

State	Earliest Open Tax Year
Pennsylvania(1)		2012
Connecticut		2015
Virginia(2)		2015
West Virginia(1)		2015
New York(1)		2011
Utah		2015

(1) Considered a major state for Dominion Energy Gas’ operations.

(2) Considered a major state for Virginia Power’s operations.

The Companies are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion Energy utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are generally subject to examination.

NOTE 6. FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of the Companies’ own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion Energy applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments, and other investments including those held in nuclear decommissioning, Dominion Energy’s rabbi, and pension and other postretirement benefit plan trusts, in accordance with the requirements discussed above. Virginia Power applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments and other investments including those held in the nuclear decommissioning trust, in accordance with the requirements discussed above. Dominion Energy Gas applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments and other investments including those held in pension and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above.

Inputs and Assumptions

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including industry publications, and to a lesser extent, broker quotes. When evaluating pricing information provided by Designated Contract Market settlement pricing, other pricing services, or brokers, the Companies consider the ability to transact at the quoted price, i.e. if the quotes are based on an active market or an inactive market and to the extent which pricing models are used, if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases the unobservable inputs are developed and substantiated using historical information, avail-

121

Combined Notes to Consolidated Financial Statements, Continued

able 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 sources.

For options and contracts with option-like characteristics where observable pricing information is not available from external sources, Dominion Energy and Virginia Power generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. Dominion Energy and Virginia Power use other option models under special circumstances, including but not limited to Spread Approximation Model and a Swing Option Model. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.

The inputs and assumptions used in measuring fair value include the following:

For commodity derivative contracts:

• Forward commodity prices

• Transaction prices

• Price volatility

• Price correlation

• Volumes

• Commodity location

• Interest rates

• Credit quality of counterparties and the Companies

• Credit enhancements

• Time value

For interest rate derivative contracts:

• Interest rate curves

• Credit quality of counterparties and the Companies

• Notional value

• Credit enhancements

• Time value

For foreign currency derivative contracts:

• Foreign currency forward exchange rates

• Interest rates

• Credit quality of counterparties and the Companies

• Notional value

• Credit enhancements

• Time value

For investments:

• Quoted securities prices and indices

• Securities trading information including volume and restrictions

• Maturity

• Interest rates

• Credit quality

Levels

The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

• Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as certain exchange-traded derivatives, and exchange-listed equities, U.S. and international equity securities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion Energy and Virginia Power, benefit plan trust funds for Dominion Energy and Dominion Energy Gas, and rabbi trust funds for Dominion Energy.

• Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include commodity forwards and swaps, interest rate swaps, foreign currency swaps and cash and cash equivalents, corporate debt instruments, government securities and other fixed income investments held in nuclear decommissioning trust funds for Dominion Energy and Virginia Power, benefit plan trust funds for Dominion Energy and Dominion Energy Gas and rabbi trust funds for Dominion Energy.

• Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for the Companies consist of long-dated commodity derivatives, FTRs, certain natural gas and power options and other modeled commodity derivatives.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. Alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments held in nuclear decommissioning and benefit plan trust funds, are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date. Alternative investments recorded at NAV are not classified in the fair value hierarchy.

Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became

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observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.

Level 3 Valuations

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, certain forward market prices and implied price volatilities are considered unobservable.

The following table presents Dominion Energy’s quantitative information about Level 3 fair value measurements at December 31, 2018. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques		Unobservable Input		Range		Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)		$42		Discounted cash flow		Market price (per Dth)(3)		(2) - 8		(1	)
FTRs		15		Discounted cash flow		Market price (per MWh)(3)		(2) - 7		1
Physical options:
Natural gas		2		Option model		Market price (per Dth)(3)		1 - 8		3
						Price volatility (4)		18% - 73%		30	%
Electricity		11		Option model		Market price (per MWh)(3)		34 - 50		42
						Price volatility (4)		39% - 60%		49	%
Total assets		$70
Liabilities
Financial forwards:
FTRs		$  6		Discounted cash flow		Market price (per MWh)(3)		(2) - 6		—
Total liabilities		$  6

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

123

Combined Notes to Consolidated Financial Statements, Continued

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)

Nonrecurring Fair Value Measurements

DOMINION ENERGY

See Note 9 for information regarding an impairment charge recognized associated with Dominion Energy’s equity method investment in Fowler Ridge.

ATLANTIC COAST PIPELINE GUARANTEE AGREEMENT

In October 2017, Dominion Energy entered into a guarantee agreement in connection with Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility. See Note 22 for more information about the guarantee agreement associated with Atlantic Coast Pipeline’s revolving credit facility. Dominion Energy recorded a liability of $30 million, the fair value of the guarantee at inception, associated with the guarantee agreement. The fair value was estimated using a discounted cash flow method and is considered a Level 3 fair value measurement due to the use of a significant unobservable input related to the interest rate differential between the interest rate charged on the guaranteed revolving credit facility and the estimated interest rate that would have been charged had the loan not been guaranteed.

DOMINION ENERGY GAS

In the fourth quarter of 2018, subsequent to the announcement of the sale of Dominion Energy’s interest in Blue Racer, Dominion Energy Gas conducted a review of strategic alternatives of its remaining gathering and processing assets at DGP. Based on an evaluation of DGP’s long-lived assets for recoverability under a probability weighted approach, Dominion Energy Gas determined the assets were impaired. As a result of this evaluation, Dominion Energy Gas recorded a charge of $219 million ($165 million after-tax) in impairment of assets and related charges in its Consolidated Statements of Income to write down DGP’s property, plant and equipment to its estimated fair value of $190 million. The fair value of the property, plant and equipment was estimated using an income approach and market approach. The valuation is considered a Level 3 fair value measurement due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risks inherent in the future cash flows and market prices.

Recurring Fair Value Measurements

Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion Energy and Dominion Energy Gas’ pension and other postretirement benefit plans are presented in Note 21.

124

DOMINION ENERGY

The following table presents Dominion Energy’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)
December 31, 2018
Assets
Derivatives:
Commodity	$	—	$	180		$  70	$	250
Interest rate		—		18		—		18
Foreign currency		—		26		—		26
Investments(1):
Equity securities:
U.S.		3,277		—		—		3,277
Fixed income:
Corporate debt instruments		—		431		—		431
Government securities		455		688		—		1,143
Cash equivalents and other		11		—		—		11
Total assets	$	3,743	$	1,343		$  70	$	5,156
Liabilities
Derivatives:
Commodity	$	—	$	129		$    6	$	135
Interest rate		—		142		—		142
Foreign currency		—		2		—		2
Total liabilities	$	—	$	273		$    6	$	279
December 31, 2017
Assets
Derivatives:
Commodity	$	—	$	101		$157	$	258
Interest rate		—		17		—		17
Foreign currency		—		32		—		32
Investments(1):
Equity securities:
U.S.		3,493		—		—		3,493
Fixed income:
Corporate debt instruments		—		444		—		444
Government securities		307		794		—		1,101
Cash equivalents and other		34		—		—		34
Total assets	$	3,834	$	1,388		$157	$	5,379
Liabilities
Derivatives:
Commodity	$	—	$	190		$    7	$	197
Interest rate		—		85		—		85
Foreign currency		—		2		—		2
Total liabilities	$	—	$	277		$    7	$	284

(1) Includes investments held in the nuclear decommissioning and rabbi trusts. Excludes $220 million and $88 million of assets at December 31, 2018 and 2017, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

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

	2018			2017			2016
(millions)
Balance at January 1,	$	150		$	139		$	95
Total realized and unrealized gains (losses):
Included in earnings:
Operating Revenue		(2	)		3			—
Electric fuel and other energy-related purchases		(15	)		(42	)		(35	)
Purchased gas		—			1			—
Included in other comprehensive income (loss)		1			(2	)		—
Included in regulatory assets/liabilities		(44	)		42			(39	)
Settlements		(27	)		6			38
Purchases		—			—			87
Transfers out of Level 3		1			3			(7	)
Balance at December 31,	$	64		$	150		$	139
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date:
Operating Revenue	$	—		$	2		$	—
Electric fuel and other energy-related purchases		—			—			(1	)

125

Combined Notes to Consolidated Financial Statements, Continued

VIRGINIA POWER

The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2018. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques		Unobservable Input		Range		Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)		$38		Discounted cash flow		Market price (per Dth)(3)		(2)-8		(1	)
FTRs		15		Discounted cash flow		Market price (per MWh)(3)		(2)-7		1
Physical options:
Natural gas		2		Option model		Market price (per Dth)(3)		1-8		3
						Price volatility (4)		18%-73%		30	%
Electricity		11		Option model		Market price (per MWh)(3)		34-50		42
						Price volatility (4)		39%-60%		49	%
Total assets		$66
Liabilities
Financial forwards:
FTRs		$  6		Discounted cash flow		Market price (per MWh)(3)		(2)-6		—
Total liabilities		$  6

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

126

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

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

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

	Level 1		Level 2		Level 3		Total
(millions)
December 31, 2018
Assets
Derivatives:
Commodity	$	—	$	24	$	66	$	90
Interest rate		—		3		—		3
Investments(1):
Equity securities:
U.S.		1,476		—		—		1,476
Fixed income:
Corporate debt instruments		—		221		—		221
Government securities		164		343		—		507
Total assets	$	1,640	$	591	$	66	$	2,297
Liabilities
Derivatives:
Commodity	$	—	$	9	$	6	$	15
Interest rate		—		88		—		88
Total liabilities	$	—	$	97	$	6	$	103
December 31, 2017
Assets
Derivatives:
Commodity	$	—	$	14	$	152	$	166
Investments(1):
Equity securities:
U.S.		1,566		—		—		1,566
Fixed income:
Corporate debt instruments		—		224		—		224
Government securities		168		326		—		494
Cash equivalents and other		16		—		—		16
Total assets	$	1,750	$	564	$	152	$	2,466
Liabilities
Derivatives:
Commodity	$	—	$	4	$	5	$	9
Interest rate		—		57		—		57
Total liabilities	$	—	$	61	$	5	$	66

(1) Includes investments held in the nuclear decommissioning trusts. Excludes $160 million and $27 million of assets at December 31, 2018 and 2017, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

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:

	2018			2017			2016
(millions)
Balance at January 1,	$	147		$	143		$	93
Total realized and unrealized gains (losses):
Included in earnings:
Electric fuel and other energy-related purchases		(17	)		(43	)		(35	)
Included in regulatory assets/liabilities		(45	)		40			(37	)
Settlements		(25	)		7			35
Purchases		—			—			87
Balance at December 31,	$	60		$	147		$	143

There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2018, 2017 and 2016.

DOMINION ENERGY GAS

The following table presents Dominion Energy 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)
December 31, 2018
Assets
Commodity		$ —		$  3		$ —		$  3
Foreign currency		—		26		—		26
Total assets		$ —		$29		$ —		$29
Liabilities
Interest rate		$ —		$17		$ —		$17
Foreign currency		—		2		—		2
Total liabilities		$ —		$19		$ —		$19
December 31, 2017
Assets
Foreign currency		$ —		$32		$ —		$32
Total assets		$ —		$32		$ —		$32
Liabilities
Commodity		$ —		$  4		$   2		$  6
Foreign currency		—		2		—		2
Total liabilities		$ —		$  6		$   2		$  8

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

	2018			2017			2016
(millions)
Balance at January 1,	$	(2	)	$	(2	)	$	6
Total realized and unrealized gains (losses):
Included in other comprehensive income (loss)		1			(3	)		—
Transfers out of Level 3		1			3			(8	)
Balance at December 31,	$	—		$	(2	)	$	(2	)

127

Combined Notes to Consolidated Financial Statements, Continued

There were no gains and losses included in earnings in the Level 3 fair value category for the years ended December 31, 2018, 2017 and 2016. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2018, 2017 and 2016.

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, restricted cash and equivalents, customer and other receivables, affiliated 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:

December 31,	2018				2017
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion Energy
Long-term debt, including securities due within one year(2)	$	29,952		$31,045	$	28,666		$31,233
Credit facility borrowings		73		73		—		—
Junior subordinated notes(3)		3,430		3,358		3,981		4,102
Remarketable subordinated notes(3)		1,386		1,340		1,379		1,446
Virginia Power
Long-term debt, including securities due within one year(3)	$	11,671		$12,400	$	11,346		$12,842
Dominion Energy Gas
Long-term debt, including securities due within one year(4)	$	4,058		$  4,072	$	3,570		$  3,719

(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 issuances 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 or premium, and foreign currency remeasurement adjustments. At December 31, 2018, and 2017, includes the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt of $(20) million and $(22) million, respectively.

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

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

NOTE 7. DERIVATIVES AND HEDGE ACCOUNTING ACTIVITIES

See Note 2 for the Companies’ accounting policies, objectives, and strategies for using derivative instruments. See Note 6 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 Energy’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. Virginia Power and Dominion Energy Gas’ derivative contracts include over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. 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. See Note 23 for further information regarding credit-related contingent features for the Companies derivative instruments.

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DOMINION ENERGY

Balance Sheet Presentation

The tables below present Dominion Energy’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

			December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	175	$	12	$	—	$	163	$	174	$	9	$	—	$	165
Exchange		68		68		—		—		80		80		—		—
Interest rate contracts:
Over-the-counter		18		1		—		17		17		8		—		9
Foreign currency contracts:
Over-the-counter		26		2		—		24		32		2		—		30
Total derivatives, subject to a master netting or similar arrangement	$	287	$	83	$	—	$	204	$	303	$	99	$	—	$	204

(1) Excludes $7 million and $4 million of derivative assets at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.

	December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	19	$	12	$	—	$	7	$	76	$	9	$	6	$	61
Exchange		115		68		47		—		120		80		40		—
Interest rate contracts:
Over-the-counter		142		1		—		141		85		8		—		77
Foreign currency contracts:
Over-the-counter		2		2		—		—		2		2		—		—
Total derivatives, subject to a master netting or similar arrangement	$	278	$	83	$	47	$	148	$	283	$	99	$	46	$	138

(1) Excludes $1 million of derivative liabilities at December 31, 2018 and 2017, which are not subject to master netting or similar arrangements.

129

Combined Notes to Consolidated Financial Statements, Continued

Volumes

The following table presents the volume of Dominion Energy’s derivative activity as of December 31, 2018. 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)		56		27
Basis		214		557
Electricity (MWh):
Fixed price(1)		11,101,869		1,537,200
FTRs		45,351,415		—
Liquids (Gal)(2)		14,413,200		—
Interest rate(3)	$	2,700,000,000	$	3,915,839,913
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 years ended December 31, 2018, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were immaterial. 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 Energy’s Consolidated Balance Sheet at December 31, 2018:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12  Months After-Tax			Maximum Term
(millions)
Commodities:
Gas		$     —			$   1			36 months
Electricity		27			26			24 months
Other		2			2			3 months
Interest rate		(276	)		(29	)		396 months
Foreign currency		12			(2	)		90 months
Total		$(235	)		$ (2	)

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.

130

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of Dominion Energy’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 December 31, 2018
ASSETS
Current Assets
Commodity		$  55		$154	$	209
Interest rate		14		—		14
Total current derivative assets(1)		69		154		223
Noncurrent Assets
Commodity		6		35		41
Interest rate		4		—		4
Foreign currency		26		—		26
Total noncurrent derivative assets(2)		36		35		71
Total derivative assets		$105		$189	$	294
LIABILITIES
Current Liabilities
Commodity		$  17		$112	$	129
Interest rate		26		—		26
Foreign currency		2		—		2
Total current derivative liabilities(3)		45		112		157
Noncurrent Liabilities
Commodity		5		1		6
Interest rate		116		—		116
Total noncurrent derivative liabilities(4)		121		1		122
Total derivative liabilities		$166		$113	$	279
At December 31, 2017
ASSETS
Current Assets
Commodity		$    5		$158	$	163
Interest rate		6		—		6
Total current derivative assets(1)		11		158		169
Noncurrent Assets
Commodity		—		95		95
Interest rate		11		—		11
Foreign currency		32		—		32
Total noncurrent derivative assets(2)		43		95		138
Total derivative assets		$  54		$253	$	307
LIABILITIES
Current Liabilities
Commodity		$103		$  92	$	195
Interest rate		53		—		53
Foreign currency		2		—		2
Total current derivative liabilities(3)		158		92		250
Noncurrent Liabilities
Commodity		1		1		2
Interest rate		32		—		32
Total noncurrent derivative liabilities(4)		33		1		34
Total derivative liabilities		$191		$  93	$	284

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

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

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

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

The following tables present the gains and losses on Dominion Energy’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)
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$  (90	)
Electric fuel and other energy-related purchases					14
Total commodity		$  64			$(76	)		$ —
Interest rate(3)		(18	)		(48	)		39
Foreign currency(4)		(6	)		(13	)		—
Total		$  40			$(137	)		$39
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$  81
Purchased gas					(2	)
Total commodity		$    1			$  79			$ —
Interest rate(3)		(8	)		(52	)		(58	)
Foreign currency(4)		18			20			—
Total		$  11			$  47			$(58	)
Year Ended December 31, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$330
Purchased gas					(13	)
Electric fuel and other energy-related purchases					(10	)
Total commodity		$164			$307			$ —
Interest rate(3)		(66	)		(31	)		(26	)
Foreign currency(4)		(6	)		(17	)		—
Total		$  92			$259			$(26	)

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

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

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

131

Combined Notes to Consolidated Financial Statements, Continued

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2018			2017			2016
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue		$(28	)		$  18			$  2
Purchased gas		11			(3	)		4
Electric fuel and other energy-related purchases		(9	)		(59	)		(70	)
Other operations & maintenance		—			(1	)		1
Total		$(26	)		$(45	)		$(63	)

(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy’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, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

	December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter		$64		$  6		$—		$58		$155		$  4		$—		$151
Interest rate contracts:
Over-the-counter		3		—		—		3		—		—		—		—
Total derivatives, subject to a master netting or similar arrangement		$67		$  6		$—		$61		$155		$  4		$—		$151

(1) Excludes $26 million and $11 million of derivative assets at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.

	December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet						Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts:
Over-the-counter		$  6		$  6		$—		$—		$  4		$  4		$—		$ —
Interest rate contracts:
Over-the-counter		88		—		—		88		57		—		—		57
Total derivatives, subject to a master netting or similar arrangement		$94		$  6		$—		$88		$61		$  4		$—		$57

(1) Excludes $9 million and $5 million of derivative liabilities at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.

132

Volumes

The following table presents the volume of Virginia Power’s derivative activity at December 31, 2018. 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)		29		8
Basis		136		488
Electricity (MWh):
Fixed price(1)		367,019		—
FTRs		45,351,415		—
Interest rate(2)	$	700,000,000	$	1,200,000,000

(1) Includes options.

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

Ineffectiveness and AOCI

For the years ended December 31, 2018, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective were immaterial.

The following table presents selected information related to losses on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at December 31, 2018:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Interest rate	$	(13	)	$	(1	)		396 months
Total	$	(13	)	$	(1	)

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

133

Combined Notes to Consolidated Financial Statements, Continued

Fair Value and Gains and Losses on Derivative Instruments

The following tables present 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 December 31, 2018
ASSETS
Current Assets
Commodity		$ —		$   60		$   60
Interest rate		3		—		3
Total current derivative assets(1)		3		60		63
Noncurrent Assets
Commodity		—		30		30
Total noncurrent derivative assets(2)		—		30		30
Total derivative assets		$  3		$   90		$   93
LIABILITIES
Current Liabilities
Commodity		$ —		$   15		$   15
Interest rate		10		—		10
Total current derivative liabilities(3)		10		15		25
Noncurrent Liabilities
Interest rate		78		—		78
Total noncurrent derivatives liabilities(4)		78		—		78
Total derivative liabilities		$88		$   15		$103
At December 31, 2017
ASSETS
Current Assets
Commodity		$ —		$   75		$   75
Total current derivative assets(1)		—		75		75
Noncurrent Assets
Commodity		—		91		91
Total noncurrent derivative assets(2)		—		91		91
Total derivative assets		$ —		$166		$166
LIABILITIES
Current Liabilities
Commodity		$ —		$     9		$     9
Interest rate		44		—		44
Total current derivative liabilities(3)		44		9		53
Noncurrent Liabilities
Interest rate		13		—		13
Total noncurrent derivative liabilities(4)		13		—		13
Total derivative liabilities		$57		$     9		$   66

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

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

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

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

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

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Interest rate(3)	$	2		$	(1	)	$	39
Total	$	2		$	(1	)	$	39
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Interest rate(3)	$	(8	)	$	(1	)	$	(58	)
Total	$	(8	)	$	(1	)	$	(58	)
Year Ended December 31, 2016
Derivative type and location of gains (losses):
Interest rate(3)	$	(3	)	$	(1	)	$	(26	)
Total	$	(3	)	$	(1	)	$	(26	)

(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.

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2018		2017		2016
(millions)
Derivative type and location of gains (losses):
Commodity(2)		$2		$(57)		$(70)
Total		$2		$(57)		$(70)

(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.

134

DOMINION ENERGY GAS

Balance Sheet Presentation

The tables below present Dominion Energy Gas’ derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

	December 31, 2018								December 31, 2017
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	3	$	—	$	—	$	3	$	—	$	—	$	—	$	—
Foreign currency contracts:
Over-the-counter		26		2		—		24		32		2		—		30
Total derivatives, subject to a master netting or similar arrangement	$	29	$	2	$	—	$	27	$	32	$	2	$	—	$	30

	December 31, 2018								December 31, 2017
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Off set in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts
Over-the-counter	$	—	$	—	$	—	$	—	$	6	$	—	$	—	$	6
Interest rate contracts:
Over-the-counter		17		—		—		17		—		—		—		—
Foreign currency contracts:
Over-the-counter		2		2		—		—		2		2		—		—
Total derivatives, subject to a master netting or similar arrangement	$	19	$	2	$	—	$	17	$	8	$	2	$	—	$	6

135

Combined Notes to Consolidated Financial Statements, Continued

Volumes

The following table presents the volume of Dominion Energy Gas’ derivative activity at December 31, 2018. 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
NGLs (Gal)		14,413,200		—
Interest rate(1)	$	300,000,000	$	750,000,000
Foreign currency(1)(2)	$	—	$	280,000,000

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

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

Ineffectiveness and AOCI

For the years ended December 31, 2018, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective were immaterial.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2018:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
NGLs		$     2			$   2			3 months
Interest rate		(39	)		(4	)		312 months
Foreign currency		12			(2	)		90 months
Total		$(25	)		$(4	)

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

Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of Dominion Energy 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 December 31, 2018
ASSETS
Current Assets
Commodity		$  3		$—		$  3
Total current derivative assets(1)		3		—		3
Noncurrent Assets
Foreign currency		26		—		26
Total noncurrent derivative assets(2)		26		—		26
Total derivative assets		$29		$—		$29
LIABILITIES
Current Liabilities
Interest rate		$  9		$—		$  9
Foreign currency		2		—		2
Total current derivative liabilities(3)		11		—		11
Noncurrent Liabilities
Interest rate		8		—		8
Total noncurrent derivative liabilities(4)		8		—		8
Total derivative liabilities		$19		$—		$19
At December 31, 2017
ASSETS
Noncurrent Assets
Foreign currency	$32		$—		$32
Total noncurrent derivative assets(2)		32		—		32
Total derivative assets		$32		$—		$32
LIABILITIES
Current Liabilities
Commodity		$  6		$—		$  6
Foreign currency		2		—		2
Total current derivative liabilities(3)		8		—		8
Total derivative liabilities		$  8		$—		$  8

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

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

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

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

136

The following tables present the gains and losses on Dominion Energy 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)
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$  (8	)
Total commodity		$   1			$  (8	)
Interest rate(2)		(18	)		(6	)
Foreign currency(3)		(6	)		(13	)
Total		$(23	)		$(27	)
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$  (8	)
Total commodity		$(10	)		$  (8	)
Interest rate(2)		—			(5	)
Foreign currency(3)		18			20
Total		$   8			$   7
Year Ended December 31, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$   4
Total commodity		$(12	)		$   4
Interest rate(2)		(8	)		(2	)
Foreign currency(3)		(6	)		(17	)
Total		$(26	)		$(15	)

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

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

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

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives
Year Ended December 31,	2018			2017		2016
(millions)
Derivative type and location of gains (losses):
Commodity
Operating revenue		$(11	)		$—		$1
Total		$(11	)		$—		$1

NOTE 8. EARNINGS PER SHARE

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

	2018		2017		2016
(millions, except EPS)
Net Income Attributable to Dominion Energy	$	2,447	$	2,999	$	2,123
Average shares of common stock outstanding – Basic		654.2		636.0		616.4
Net effect of dilutive securities(1)		0.7		—		0.7
Average shares of common stock outstanding – Diluted		654.9		636.0		617.1
Earnings Per Common Share – Basic	$	3.74	$	4.72	$	3.44
Earnings Per Common Share – Diluted	$	3.74	$	4.72	$	3.44

(1) Dilutive securities for 2018 consist primarily of forward sale agreements, effective April 2018 to December 2018. Dilutive securities for 2016 consist primarily of the 2013 Equity Units. See Notes 17 and 19 for more information.

The 2014 Equity Units were excluded from the calculation of diluted EPS for the year ended December 31, 2016 as the dilutive stock price threshold was not met. The 2016 Equity Units were excluded from the calculation of diluted EPS for the years ended December 31, 2018, 2017 and 2016, as the dilutive stock price threshold was not met. See Note 17 for more information. The Dominion Energy Midstream convertible preferred units were potentially dilutive securities but had no effect on the calculation of diluted EPS for the years ended December 31, 2018, 2017 and 2016. See Note 19 for more information.

137

Combined Notes to Consolidated Financial Statements, Continued

NOTE 9. INVESTMENTS

DOMINION ENERGY

Equity and Debt Securities

RABBI TRUST SECURITIES

Equity and debt securities and cash equivalents in Dominion Energy’s rabbi trusts and classified as trading totaled $111 million and $112 million at December 31, 2018 and 2017, respectively.

DECOMMISSIONING TRUST SECURITIES

Dominion Energy holds equity and debt securities, cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion Energy’s decommissioning trust funds are summarized below:

	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Fair Value
(millions)
December 31, 2018
Equity securities:(1)
U.S.		$1,741		$1,640		$(51)			$3,330
Fixed income securities:(2)
Corporate debt instruments		435		5		(9)			431
Government securities		1,092		17		(12)			1,097
Common/collective trust funds		76		—		—			76
Cash equivalents and other(3)		4		—		—			4
Total		$3,348		$1,662		$(72)	(4)		$4,938
December 31, 2017
Equity securities:(2)
U.S.		$1,569		$1,857		$ —			$3,426
Fixed income securities:(2)
Corporate debt instruments		430		15		(1)			444
Government securities		1,039		27		(5)			1,061
Common/collective trust funds		60		—		—			60
Cost method investments		68		—		—			68
Cash equivalents and other(3)		34		—		—			34
Total		$3,200		$1,899		$  (6)	(4)		$5,093

(1) Effective January 2018, unrealized gains and losses on equity securities, including those previously classified as cost method investments, are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(2) Unrealized gains and losses on equity securities (for 2017) and fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(3) Includes pending sales of securities of $5 million at December 31, 2017.

(4) The fair value of securities in an unrealized loss position was $833 million and $565 million at December 31, 2018 and 2017, respectively.

The portion of unrealized gains and losses that relates to equity securities held within Dominion Energy’s nuclear decommissioning trusts is summarized below:

	Twelve Months Ended December 31, 2018
(millions)
Net losses recognized during the period	$	(245	)
Less: Net gains recognized during the period on securities sold during the period		(58	)
Unrealized losses recognized during the period on securities still held at December 31, 2018(1)	$	(303	)

(1) Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

The fair value of Dominion Energy’s debt securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2018 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	167
Due after one year through five years		389
Due after five years through ten years		376
Due after ten years		672
Total	$	1,604

138

Presented below is selected information regarding Dominion Energy’s equity and debt securities with readily determinable fair values held in nuclear decommissioning trust funds.

Year Ended December 31,	2018		2017		2016
(millions)
Proceeds from sales	$	1,804	$	1,831	$	1,422
Realized gains(1)		140		166		128
Realized losses(1)		91		71		55

(1) Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.

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

Year Ended December 31,	2018			2017			2016
(millions)
Total other-than-temporary impairment losses(1)	$	30		$	44		$	51
Losses recorded to the nuclear decommissioning trust regulatory liability		—			(16	)		(16	)
Losses recognized in other comprehensive income (before taxes)		(30	)		(5	)		(12	)
Net impairment losses recognized in earnings	$	—		$	23		$	23

(1) Amounts include other-than-temporary impairment losses for debt securities of $5 million and $13 million at December 31, 2017 and 2016, respectively.

VIRGINIA POWER

Virginia Power holds equity and debt securities, 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		Total Unrealized Losses			Fair Value
(millions)
December 31, 2018
Equity securities:(1)
U.S.		$858		$751		$(24	)		$1,585
Fixed income securities:(2)
Corporate debt instruments		224		2		(5	)		221
Government securities		504		7		(5	)		506
Common/collective trust funds		51		—		—			51
Cash equivalents and other(3)		6		—		—			6
Total		$1,643		$760		$(34)	(4)		$2,369
December 31, 2017
Equity securities:(2)
U.S.		$   734		$831		$—			$1,565
Fixed income securities:(2)
Corporate debt instruments		216		8		—			224
Government securities		482		13		(2	)		493
Common/collective trust funds		27		—		—			27
Cost method investments		68		—		—			68
Cash equivalents and other(3)		22		—		—			22
Total		$1,549		$852		$(2	)(4)		$2,399

(1) Effective January 2018, unrealized gains and losses on equity securities, including those previously classified as cost method investments, are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(2) Unrealized gains and losses on equity securities (for 2017) and fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(3) Includes pending sales of securities of $6 million at both December 31, 2018 and 2017.

(4) The fair value of securities in an unrealized loss position was $404 million and $234 million at December 31, 2018 and 2017, respectively.

The portion of unrealized gains and losses that relates to equity securities held within Virginia Power’s nuclear decommissioning trusts is summarized below:

	Twelve Months Ended December 31, 2018
(millions)
Net losses recognized during the period	$	(105	)
Less: Net gains recognized during the period on securities sold during the period		(32	)
Unrealized losses recognized during the period on securities still held at December 31, 2018(1)	$	(137	)

(1) Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

The fair value of Virginia Power’s debt securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2018, by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	54
Due after one year through five years		156
Due after five years through ten years		210
Due after ten years		358
Total	$	778

Presented below is selected information regarding Virginia Power’s equity and debt securities with readily determinable fair values held in nuclear decommissioning trust funds.

Year Ended December 31,	2018		2017		2016
(millions)
Proceeds from sales	$	887	$	849	$	733
Realized gains(1)		60		75		63
Realized losses(1)		27		30		27

(1) Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.

139

Combined Notes to Consolidated Financial Statements, Continued

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

Year Ended December 31,	2018			2017			2016
(millions)
Total other-than-temporary impairment losses(1)	$	15		$	20		$	26
Losses recorded to the nuclear decommissioning trust regulatory liability		—			(16	)		(16	)
Losses recognized in other comprehensive income (before taxes)		(15	)		(2	)		(7	)
Net impairment losses recognized in earnings	$	—		$	2		$	3

(1) Amounts include other-than-temporary impairment losses for debt securities of $2 million and $8 million at December 31, 2017 and 2016 , respectively.

Equity Method Investments

DOMINION ENERGY AND DOMINION ENERGY GAS

Investments that Dominion Energy and Dominion Energy Gas account for under the equity method of accounting are as follows:

Company	Ownership%			Investment Balance				Description
As of December 31,				2018		2017
(millions)
Dominion Energy
Atlantic Coast Pipeline		48	%	$	820	$	382		Gas transmission system
Blue Racer		50	%		—		691		Midstream gas and     related services
Iroquois		50	%(1)		302		311		Gas transmission system
Fowler Ridge		50	%		82		81		Wind-powered merchant     generation facility
Other(2)		various			74		79
Total				$	1,278	$	1,544
Dominion Energy Gas
Iroquois		24.07	%	$	91	$	95		Gas transmission system
Total				$	91	$	95

(1) Comprised of Dominion Energy Midstream’s interest of 25.93% and Dominion Energy Gas’ interest of 24.07%. See Note 15 for more information.

(2) Liability of less than $1 million and $17 million associated with NedPower recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets as of December 31, 2018 and 2017, respectively. See additional discussion of NedPower below.

Dominion Energy’s equity earnings on its investments totaled $197 million, $14 million and $111 million in 2018, 2017 and 2016, respectively, included in other income in Dominion Energy’s Consolidated Statements of Income. Dominion Energy received distributions from these investments of $209 million, $419 million and $104 million in 2018, 2017 and 2016, respectively. As of December 31, 2018 and 2017, the carrying amount of Dominion Energy’s investments exceeded its share of underlying equity in net assets by $161 million and $249 million, respectively. At December 31, 2018 these differences are comprised of $146 million of equity method goodwill that is not being amortized and $15 million related to basis differences from Dominion Energy’s investments in wind projects, which are being amortized over the useful lives of the underlying assets, and in Atlantic Coast Pipeline, which is being amortized over the term of its credit facility. At December 31, 2017 these differences are

comprised of $176 million of equity method goodwill and $73 million related to basis differences from Dominion Energy’s investments in Blue Racer and wind projects, and in Atlantic Coast Pipeline.

Dominion Energy Gas’ equity earnings on its investment totaled $24 million in 2018 and $21 million in 2017 and 2016. Dominion Energy Gas received distributions from its investment of $28 million, $24 million and $22 million in 2018, 2017 and 2016, respectively. As of December 31, 2018 and 2017, the carrying amount of Dominion Energy Gas’ investment 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 Energy Gas sold 0.65% of the noncontrolling partnership interest in Iroquois to TransCanada for approximately $7 million, which resulted in a $5 million ($3 million after-tax) gain, included in other income in Dominion Energy Gas’ Consolidated Statements of Income.

DOMINION ENERGY

ATLANTIC COAST PIPELINE

In September 2014, Dominion Energy, along with Duke and Southern Company Gas, announced the formation of Atlantic Coast Pipeline. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion Energy an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. In October 2016, Dominion Energy purchased an additional 3% membership interest in Atlantic Coast Pipeline from Duke for $14 million. As of December 31, 2018, the members hold the following membership interests: Dominion Energy, 48%; Duke, 47%; and Southern Company Gas, 5%.

Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. Subsidiaries and affiliates of all three members plan to be customers of the pipeline under 20-year contracts. Atlantic Coast Pipeline is considered an equity method investment as Dominion Energy has the ability to exercise significant influence, but not control, over the investee. See Note 15 for more information.

DETI provides services to Atlantic Coast Pipeline which totaled $203 million, $129 million and $95 million in 2018, 2017 and 2016, respectively, included in operating revenue in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income. Amounts receivable related to these services were $13 million and $12 million at December 31, 2018 and 2017, respectively, composed entirely of accrued unbilled revenue, included in other receivables in Dominion Energy and Dominion Energy Gas’ Consolidated Balance Sheets.

In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under its credit facility. See Note 22 for more information.

Dominion Energy contributed $414 million, $310 million and $184 million during 2018, 2017 and 2016, respectively, to Atlantic Coast Pipeline.

Dominion Energy received distributions of $36 million and $270 million during 2018 and 2017, respectively, from Atlantic Coast Pipeline. No distributions were received in 2016.

140

During the third and fourth quarters of 2018, a FERC stop work order together with delays in obtaining permits necessary for construction along with construction delays due to judicial actions impacted the cost and schedule for the project. As a result project cost estimates have increased from between $6.0 billion to $6.5 billion to between $7.0 billion to $7.5 billion, excluding financing costs. Atlantic Coast Pipeline expects to achieve a late 2020 in-service date for at least key segments of the project, while the remainder may extend into early 2021. Alternatively, if it takes longer to resolve the judicial issues, such as through appeal to the Supreme Court of the U.S., full in-service could extend to the end of 2021 with total project cost estimated to increase an additional $250 million, resulting in total project cost estimates of $7.25 billion to $7.75 billion excluding financing costs. Abnormal weather, work delays (including due to judicial or regulatory action) and other conditions may result in further cost or schedule modifications in the future, which could result in a material impact to Dominion Energy’s cash flows, financial position and/or results of operations.

BLUE RACER

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

In December 2016, Dominion Energy Gas repurchased a portion of the Western System from Blue Racer for $10 million.

In December 2018, Dominion Energy sold its 50% limited partnership interest in Blue Racer for up-front cash consideration of $1.05 billion and additional consideration of $150 million, subject to increase for interest costs effective March 2019, payable upon the purchaser’s availability of cash. The additional consideration was recorded at a fair value of $150 million on the date of sale following a discounted cash flow model and is included within other receivables in the Consolidated Balance Sheets at December 31, 2018. The valuation is considered a Level 3 fair value measurement due to the use of judgment and unobservable inputs, including projected timing and amount of future cash flows and a discount rate reflecting risks inherent in the future cash flows. As a result of the sale, Dominion Energy recognized a gain of $546 million ($390 million after-tax), included in other income in its Consolidated Statements of Income. Also, the purchaser agreed to pay additional consideration contingent upon the achievement of certain financial performance milestones of Blue Racer from 2019 through 2021. Pursuant to the purchase agreement, the aggregate will not exceed $300 million, which represents a gain contingency, and, as a result, Dominion Energy will not recognize any additional gain unless such consideration is realizable.

FOWLER RIDGE & NEDPOWER

In the fourth quarter of 2017, Dominion Energy recorded a charge of $126 million ($76 million after-tax) in other income in

its Consolidated Statements of Income reflecting its share of a long-lived asset impairment of property, plant and equipment recorded by NedPower, which resulted in losses in excess of Dominion Energy’s investment balance. Dominion Energy recorded the excess losses due to its commitment to provide further financial support for NedPower, resulting in a liability of $17 million at December 31, 2017, recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets.

As a result of the impairment recorded by NedPower, Dominion Energy evaluated its equity method investment in Fowler Ridge, a similar wind-powered merchant generation facility, determined its fair value was other than-temporarily impaired and recorded an impairment charge of $32 million ($20 million after-tax) in other income in its Consolidated Statements of Income. The fair value of $81 million was estimated using a discounted cash flow method and is considered a Level 3 fair value measurement due to the use of significant unobservable inputs related to the timing and amount of future equity distributions based on the investee’s future wind generation and operating costs.

OTHER – CATALYST OLD RIVER HYDROELECTRIC LIMITED PARTNERSHIP

In September 2018, Dominion Energy completed the sale of its 25% limited partnership interest in Catalyst Old River Hydroelectric Limited Partnership and received proceeds of $91 million. The sale resulted in a gain of $87 million ($63 million after-tax), which is included in other income in Dominion Energy’s Consolidated Statement of Income.

NOTE 10. PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment and their respective balances for the Companies are as follows:

At December 31,	2018		2017
(millions)
Dominion Energy
Utility:
Generation	$	19,250	$	17,602
Transmission		16,669		15,335
Distribution		18,549		17,408
Storage		2,905		2,887
Nuclear fuel		1,626		1,599
Gas gathering and processing		307		219
Oil and gas		1,763		1,720
General and other		1,476		1,514
Plant under construction		2,385		7,765
Total utility		64,930		66,049
Nonutility:
Merchant generation-nuclear		1,550		1,452
Merchant generation-other		3,802		4,992
Nuclear fuel		1,025		968
Gas gathering and processing		185		630
LNG facility		3,977		—
Other-including plant under construction		1,109		732
Total nonutility		11,648		8,774
Total property, plant and equipment	$	76,578	$	74,823

141

Combined Notes to Consolidated Financial Statements, Continued

At December 31,	2018		2017
(millions)
Virginia Power
Utility:
Generation	$	19,250	$	17,602
Transmission		9,392		8,332
Distribution		11,785		11,151
Nuclear fuel		1,626		1,599
General and other		821		794
Plant under construction		1,639		2,840
Total utility		44,513		42,318
Nonutility-other		11		11
Total property, plant and equipment	$	44,524	$	42,329
Dominion Energy Gas
Utility:
Transmission	$	4,758	$	4,732
Distribution		3,527		3,267
Storage		1,691		1,688
Gas gathering and processing		210		202
General and other		233		216
Plant under construction		494		293
Total utility		10,913		10,398
Nonutility:
Gas gathering and processing		185		630
Other-including plant under construction		140		145
Total nonutility		325		775
Total property, plant and equipment	$	11,238	$	11,173

Jointly-Owned Power Stations

Dominion Energy and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2018 is as follows:

	Bath County Pumped Storage Station(1)			North Anna Units 1 and 2(1)			Clover Power Station(1)			Millstone Unit 3(2)
(millions, except percentages)
Ownership interest		60	%		88.4	%		50	%		93.5	%
Plant in service		1,058			2,560			590			1,231
Accumulated depreciation		(639	)		(1,305	)		(240	)		(400	)
Nuclear fuel		—			721			—			571
Accumulated amortization of nuclear fuel		—			(608	)		—			(423	)
Plant under construction		6			103			9			66

(1) Units jointly owned by Virginia Power.

(2) Unit jointly owned by Dominion Energy.

The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion Energy and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.

Sale of Certain Retail Energy Marketing Assets

In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy

marketing operations for total consideration of $143 million, subject to customary approvals and certain adjustments. In December 2017, the first phase of the agreement closed for $79 million, which resulted in the recognition of a $78 million ($48 million after-tax) benefit, included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. In October 2018, the second phase of the agreement closed for $63 million, which resulted in the recognition of a $65 million ($49 million after-tax) benefit included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. Pursuant to the agreement, Dominion Energy entered into a commission agreement with the buyer upon the first closing in December 2017 under which the buyer will pay a commission in connection with the right to use Dominion Energy’s brand in marketing materials and other services over a ten-year term.

Sale of Certain Merchant Generation Facilities

In December 2018, Dominion Energy completed the sale of Fairless and Manchester for total consideration of $1.2 billion, subject to customary closing adjustments. Dominion Energy recognized a gain of $210 million ($198 million after-tax) included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. The after-tax gain reflects Dominion Energy’s assessment and more-likely-than-not conclusion that the utilization of state tax incentives will reduce the income tax expense associated with the sale of these facilities.

Acquisition of Solar Projects

In September 2017, Virginia Power entered into agreements to acquire two solar development projects in North Carolina. The first acquisition closed in October 2018. The facility commenced commercial operations in December 2018 at a cost of $140 million, including the initial acquisition cost. The second acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2019, and cost approximately $140 million once constructed, including the initial acquisition cost. The projects are expected to generate approximately 155 MW combined. Virginia Power anticipates claiming federal investment tax credits on these solar projects.

In February 2019, Virginia Power completed the acquisition of a solar development project in Virginia. The project is expected to commence commercial operations in the first quarter 2019, and cost approximately $37 million once constructed, including the initial acquisition cost. The project is expected to generate approximately 20 MW. Virginia Power anticipates claiming federal investment tax credits on this solar project.

In August 2018, Virginia Power entered into agreements to acquire two solar development projects in North Carolina and Virginia. The first acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2019, and cost approximately $120 million once constructed, including the initial acquisition cost. The second acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2020, and cost approximately $130 million, including the initial acquisition cost. The projects are expected to generate approximately 155 MW combined. Virginia Power anticipates claiming federal investment tax credits on these solar projects.

142

Assignment of Tower Rental Portfolio

Virginia Power rents space on certain of its electric transmission towers to various wireless carriers for communications antennas and other equipment. In March 2017, Virginia Power sold its rental portfolio to Vertical Bridge Towers II, LLC for $91 million in cash. The proceeds are subject to Virginia Power’s FERC-regulated tariff, under which it is required to return half of the proceeds to customers. Virginia Power recorded $6 million in operating revenue and $11 million in other income during 2018 and 2017, respectively, with $29 million remaining to be recognized ratably through 2023.

Assignments of Shale Development Rights

In December 2013, Dominion Energy Gas closed on agreements with two natural gas producers to convey over time approximately 100,000 acres of Marcellus Shale development rights underneath several of its natural gas storage fields. The agreements provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In 2013, Dominion Energy Gas received approximately $100 million in cash proceeds. In 2014, Dominion Energy Gas received $16 million in additional cash proceeds resulting from post-closing adjustments. In March 2015, Dominion Energy Gas and one of the natural gas producers 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 Energy Gas’ Consolidated Statements of Income. In April 2016, Dominion Energy 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 gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income. In August 2017, Dominion Energy Gas and the natural gas producer signed an amendment to the agreement, which included the finalization of contractual matters on previous conveyances, the conveyance of Dominion Energy Gas’ remaining 68% interest in approximately 70,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. Dominion Energy Gas received total consideration of $130 million, with $65 million received in 2017 and $65 million received in September 2018 in connection with the final conveyance. As a result of this amendment, in 2017, Dominion Energy Gas recognized a $56 million ($33 million after-tax) gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the finalization of the contractual matters on previous conveyances, a $9 million ($5 million after-tax) gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the elimination of its overriding royalty interest and in 2018, a

$65 million ($47 million after-tax) gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the final conveyance of acreage.

In November 2014, Dominion Energy Gas closed 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. The agreement provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $120 million over a period of four years, and an overriding royalty interest in gas produced from the acreage. In November 2014, Dominion Energy Gas closed on the agreement and received proceeds of $60 million associated with an initial conveyance of approximately 12,000 acres. In connection with that agreement, in 2016, Dominion Energy Gas conveyed a 50% interest in approximately 4,000 acres of Marcellus Shale development rights and received proceeds of $10 million and an overriding royalty interest in gas produced from the acreage. These transactions resulted in a $10 million ($6 million after-tax) gain. In July 2017, in connection with the existing agreement, Dominion Energy Gas conveyed an additional 50% interest in 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. The gains are included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income. In January 2018, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the conveyance of Dominion Energy Gas’ remaining 50% interest in approximately 18,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. Dominion Energy Gas received proceeds of $28 million, resulting in an approximately $28 million ($20 million after-tax) gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.

In March 2018, Dominion Energy Gas closed an agreement with a natural gas producer to convey approximately 11,000 acres of Utica and Point Pleasant Shale development rights underneath one of its natural gas storage fields. The agreement provided for a payment to Dominion Energy Gas, subject to customary adjustments, of $16 million. In March 2018, Dominion Energy Gas received cash proceeds of $16 million associated with the conveyance of the acreage, resulting in a $16 million ($12 million after-tax) gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.

In June 2018, Dominion Energy Gas closed an amendment to an agreement with a natural gas producer for the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from approximately 9,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields previously conveyed in December 2013. In June 2018, Dominion Energy Gas received proceeds of $6 million associated with the transaction, resulting in a $6 million ($4 million after-tax) gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.

143

Combined Notes to Consolidated Financial Statements, Continued

NOTE 11. GOODWILL AND INTANGIBLE ASSETS

Goodwill

The changes in Dominion Energy and Dominion Energy Gas’ carrying amount and segment allocation of goodwill are presented below:

	Power Generation		Gas Infrastructure			Power Delivery		Corporate and Other(1)		Total
(millions)
Dominion Energy
Balance at December 31, 2016(2)	$	1,422	$	4,051		$	926	$	—	$	6,399
Dominion Energy Questar Combination		—		6(3	)		—		—		6
Balance at December 31, 2017(2)	$	1,422	$	4,057		$	926	$	—	$	6,405
Purchase Accounting Adjustment		—		5			—		—		5
Balance at December 31, 2018(2)	$	1,422	$	4,062		$	926	$	—	$	6,410
Dominion Energy Gas
Balance at December 31, 2016(2)	$	—	$	542		$	—	$	—	$	542
No events affecting goodwill		—		—			—		—		—
Balance at December 31, 2017(2)	$	—	$	542		$	—	$	—	$	542
Purchase Accounting Adjustment		—		5			—		—		5
Balance at December 31, 2018(2)	$	—	$	547		$	—	$	—	$	547

(1) Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.

(2) Goodwill amounts do not contain any accumulated impairment losses.

(3) See Note 3.

Other Intangible Assets

The Companies’ other intangible assets are subject to amortization over their estimated useful lives. Dominion Energy’s amortization expense for intangible assets was $82 million, $80 million and $73 million for 2018, 2017 and 2016, respectively. In 2018, Dominion Energy acquired $127 million of intangible assets, primarily representing software and right-of-use assets, with an estimated weighted-average amortization period of approximately 15 years. Amortization expense for Virginia Power’s intangible assets was $31 million for both 2018 and 2017 and $29 million for 2016. In 2018, Virginia Power acquired $49 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 11 years. Dominion Energy Gas’ amortization expense for intangible assets was $14 million for both 2018 and 2017 and $6 million for 2016. In 2018, Dominion Energy Gas acquired $14 million of intangible assets, primarily representing software and right-of-use

assets, with an estimated weighted-average amortization period of approximately 10 years. The components of intangible assets are as follows:

	2018				2017
At December 31,	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Dominion Energy
Software, licenses and other	$	1,033	$	363	$	1,043	$	358
Virginia Power
Software, licenses and other	$	384	$	134	$	347	$	114
Dominion Energy Gas
Software, licenses and other	$	174	$	65	$	165	$	56

Annual amortization expense for these intangible assets is estimated to be as follows:

	2019		2020		2021		2022		2023
(millions)
Dominion Energy	$	67	$	56	$	44	$	34	$	23
Virginia Power	$	29	$	23	$	16	$	12	$	6
Dominion Energy Gas	$	14	$	13	$	12	$	8	$	7

144

NOTE 12. REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities include the following:

At December 31,	2018		2017
(millions)
Dominion Energy
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	174	$	23
Deferred rate adjustment clause costs(2)		96		70
Deferred nuclear refueling outage costs(3)		69		54
Unrecovered gas costs(4)		14		38
Other		143		109
Regulatory assets-current		496		294
Unrecognized pension and other postretirement benefit costs(5)		1,497		1,336
Deferred rate adjustment clause costs(2)		329		401
Utility reform legislation(6)		204		147
PJM transmission rates(7)		192		222
Derivatives(8)		184		223
Deferred cost of fuel used in electric generation(1)		83		—
Other		187		151
Regulatory assets-noncurrent		2,676		2,480
Total regulatory assets	$	3,172	$	2,774
Regulatory liabilities:
Provision for future cost of removal and AROs(9)	$	117	$	101
Cost-of-service impact of 2017 Tax Reform Act(10)		104		—
Reserve for rate credits to electric utility customers(11)		71		—
Other		64		92
Regulatory liabilities-current(12)		356		193
Income taxes refundable through future rates(13)		4,071		4,058
Provision for future cost of removal and AROs(9)		1,409		1,384
Nuclear decommissioning trust(14)		1,070		1,121
Derivatives(8)		25		69
Other		265		284
Regulatory liabilities-noncurrent		6,840		6,916
Total regulatory liabilities	$	7,196	$	7,109
Virginia Power
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	174	$	23
Deferred rate adjustment clause costs(2)		78		56
Deferred nuclear refueling outage costs(3)		69		54
Other		103		72
Regulatory assets-current		424		205
Deferred rate adjustment clause costs(2)		230		312
PJM transmission rates(7)		192		222
Derivatives(8)		151		190
Deferred cost of fuel used in electric generation(1)		83		—
Other		81		86
Regulatory assets-noncurrent		737		810
Total regulatory assets	$	1,161	$	1,015
Regulatory liabilities:
Cost-of-service impact of 2017 Tax Reform Act(10)	$	95	$	—
Provision for future cost of removal(9)		92		80
Reserve for rate credits to customers(11)		71		—
Other		41		47
Regulatory liabilities-current		299		127
Income taxes refundable through future rates(13)		2,579		2,581
Nuclear decommissioning trust(14)		1,070		1,121
Provision for future cost of removal(9)		940		915
Derivatives(8)		25		69
Other		33		74
Regulatory liabilities-noncurrent		4,647		4,760
Total regulatory liabilities	$	4,946	$	4,887

At December 31,	2018		2017
(millions)
Dominion Energy Gas
Regulatory assets:
Deferred rate adjustment clause costs(2)	$	18	$	14
Unrecovered gas costs(4)		9		8
Other		2		4
Regulatory assets-current(16)		29		26
Unrecognized pension and other postretirement benefit costs(5)		392		258
Utility reform legislation(6)		204		147
Deferred rate adjustment clause costs(2)		99		89
Other		32		17
Regulatory assets-noncurrent		727		511
Total regulatory assets	$	756	$	537
Regulatory liabilities:
Provision for future cost of removal and AROs(9)	$	14	$	13
PIPP(15)		3		20
Other		4		5
Regulatory liabilities-current(12)		21		38
Income taxes refundable through future rates(13)		1,011		998
Provision for future cost of removal and AROs(9)		158		160
Cost-of-service impact of 2017 Tax Reform Act(10)		19		—
Other		97		69
Regulatory liabilities-noncurrent		1,285		1,227
Total regulatory liabilities	$	1,306	$	1,265

 (1) Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Dominion Energy and Virginia Power’s generation operations. See Note 13 for more information.

 (2) Primarily reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects net of income taxes refundable from the 2017 Tax Reform Act for Virginia Power and deferrals of costs associated with certain current and prospective rider projects for Dominion Energy Gas. See Note 13 for more information.

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

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

 (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 Energy and Dominion Energy Gas’ rate-regulated subsidiaries.

 (6) Ohio legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future.

 (7) Reflects amounts related to the PJM transmission cost allocation matter. See Note 13 for more information.

 (8) As discussed under Derivative Instruments in Note 2, 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.

 (9) 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.

(10) Balance refundable to customers related to the decrease in revenue requirements for recovery of income taxes at the Companies’ regulated electric generation and electric and natural gas distribution operations. See Note 13 for more information.

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(11) Charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers. See Note 13 for more information.

(12) Current regulatory liabilities are presented in other current liabilities in Dominion Energy and Dominion Energy Gas’ Consolidated Balance Sheets.

(13) Amounts recorded to pass the effect of reduced income tax rates from the 2017 Tax Reform Act to customers in future periods, which will reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity.

(14) 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.

(15) 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 rider according to East Ohio tariff provisions. See Note 13 for more information.

(16) Current regulatory assets are presented in other current assets in Dominion Energy Gas’ Consolidated Balance Sheets.

At December 31, 2018, $396 million of Dominion Energy’s, $300 million of Virginia Power’s and $12 million of Dominion Energy Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. With the exception of the PJM transmission cost allocation matter, the majority of these expenditures are expected to be recovered within the next two years.

NOTE 13. 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 regulatory matters that the Companies cannot estimate, 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 that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.

FERC—ELECTRIC

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public util-

ities. Virginia Power purchases and sells electricity in the PJM wholesale market and sells electricity to wholesale purchasers in Virginia and North Carolina. Dominion Energy’s merchant generators sell electricity in the PJM, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California, South Carolina and Utah, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. 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 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 investment in electric transmission infrastructure.

In March 2010, ODEC 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.

In October 2017, FERC issued an order determining the calculation of the incremental costs of undergrounding the transmission projects and affirming that the costs are to be recovered from the wholesale transmission customers with loads located in Virginia. FERC directed Virginia Power to rebill all wholesale transmission customers retroactively to March 2010 within 30 days of when the proceeding becomes final and no longer subject to rehearing. In November 2017, Virginia Power, North Carolina Electric Membership Corporation and the wholesale transmission customers filed petitions for rehearing. In July

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2018, FERC denied the rehearing requests related to the October 2017 order determining the calculation of the undergrounding costs. Several parties have appealed FERC’s decision to the U.S. Court of Appeals for the D.C. Circuit. This matter is pending. While Virginia Power cannot predict the outcome of the matter, it is not expected to have a material effect on results of operations.

In January 2019, FERC issued an order denying PJM’s request to waive certain provisions of the PJM Tariff regarding the liquidation of a portfolio of FTRs owned by GreenHat who had defaulted on its financial obligations. As a result of FERC’s order, PJM is required to use the existing tariff provisions to liquidate GreenHat’s FTR portfolio and allocate the resulting costs to PJM members. In February 2019, PJM filed a request for clarification and rehearing with FERC. While the impacts of this order could be material to 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.

PJM Transmission Rates

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

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

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. In May 2018, FERC issued an order accepting the settlement agreement and directed PJM to make a compliance filing with revised tariff records. As a result, in August 2018, Virginia Power began to make payments to PJM, to continue for the next 10 years totaling $276 million, under the terms of revised tariff records, which was partially offset by a $265 million regulatory asset for the amount that will be recovered through retail rates in Virginia. At December 31, 2018, Virginia Power’s Consolidated Balance Sheet includes $126 million in other current liabilities and $50 million included in other

deferred credits and other liabilities for amounts owed to PJM.

FERC—GAS

In July 2017, FERC audit staff communicated to DETI that it had substantially completed an audit of DETI’s compliance with the accounting and reporting requirements of FERC’s Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report which could have the potential to result in adjustments which could be material to Dominion Energy and Dominion Energy Gas’ results of operations. In December 2017, DETI provided its response to the audit report. DETI requested FERC review of contested findings and submitted its plan for compliance with the uncontested portions of the report. In connection with one uncontested issue, DETI recognized a charge of $15 million ($9 million after-tax) recorded within impairment of assets and related charges in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income during 2017 to write-off the balance of a regulatory asset, originally established in 2008, that is no longer considered probable of recovery. DETI recognized a charge of $129 million ($94 million after-tax) recorded primarily within impairment of assets and related charges in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income during 2018 for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with FERC. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the remaining finding and no amounts have been recognized.

2017 TAX REFORM ACT

Subsequent to the enactment of the 2017 Tax Reform Act, the Companies’ state regulators issued orders requesting that public utilities evaluate the total tax impact on the entity’s cost of service and accrue a regulatory liability attributable to the benefits of the reduction in the corporate income tax rate. Certain of the orders requested that the public utilities submit a response to the state regulatory commissions detailing the total tax impact on the utility’s cost of service.

The Companies began to reserve the impacts of the cost-of-service reduction as regulatory liabilities in January 2018 and will continue until rates are reset pursuant to state regulators’ approvals. The Companies have recorded a reasonable estimate of net income taxes refundable through future rates in the jurisdictions in which they operate and are currently assessing these actions and decisions, which could have a material impact on the Companies’ results of operations, financial condition and/or cash flows.

In September 2018, the Virginia Commission issued an order directing Virginia Power to submit a filing quantifying the impacts of the 2017 Tax Reform Act in advance of the April 1, 2019 implementation as required by legislation. In October 2018, Virginia Power filed testimony with the Virginia Commission to implement adjustments in its base rates reflecting actual annual reductions in corporate income taxes resulting from the 2017 Tax Reform Act, which included a proposed annual revenue reduction of approximately $151 million effective April 2019. In December 2018, the Staff of the Virginia Commission proposed an annual revenue reduction of approximately $190 million. In January 2019, Virginia Power filed updated testimony with a proposed

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annual revenue reduction of approximately $171 million. Additionally, Virginia Power proposed to issue a one-time bill credit to customers within 90 days of this effective date, to true-up the difference between the final revenue reduction for the period January 1, 2018 through March 31, 2019 and the $125 million interim rate reduction implemented on July 1, 2018. Based on Virginia Power’s current proposed annual revenue reduction, this one-time bill credit is expected to total approximately $120 million. The actual credit will be based on actual billing data and customer usage during that 15-month period. This matter is pending.

In August 2018, Virginia Power filed with FERC to waive protocols and begin reflecting projected tax reform benefits of approximately $100 million through the transmission formula rate prior to the normal formula rate process. FERC granted the waiver and the amounts began being reflected in customer billings in November 2018 reflecting the adjustment effective January 1, 2018.

In October 2018, the North Carolina Commission issued an order requesting companies file to reduce base rates expeditiously. Virginia Power made its compliance filing in October 2018 and submitted an annual base rate revenue decrease of approximately $14 million effective in early 2019. Virginia Power also proposed to issue a one-time bill credit in early 2019 for its 2018 tax savings collected provisionally from customers, which is estimated to be approximately $13 million. The order allowed for the disposition of excess deferred income taxes to be deferred for consideration until the utilities’ next base rate case, but no longer than 3 years, and initiated a quarterly reporting requirement for such deferred amounts. This matter is pending.

In May 2018, the Utah Commission approved a stipulation submitted by Questar Gas proposing the cost-of-service component of customer rates be reduced by $15 million annually beginning in June 2018. In July 2018, the Utah Commission approved Questar Gas’ request to return an additional $9 million to Utah customers representing the amounts related to the corporate income tax reduction that had been deferred from January 1, 2018 to May 31, 2018. This additional reduction began amortizing on August 1, 2018 and will be amortized over a one-year period. In October 2018, the Wyoming Commission approved Questar Gas’ request to return deferred amounts through a surcredit beginning November 1, 2018. The surcredit will remain in effect until rates become effective in the next Wyoming general rate case. The impact of excess deferred income taxes resulting from the 2017 Tax Reform Act on rates charged to customers will be reported to the Utah and Wyoming Commissions by the first quarter of 2019.

In October 2018, the Ohio Commission issued an order requiring rate-regulated utilities to file an application reflecting the impact of the 2017 Tax Reform Act on current rates by January 1, 2019. In December 2018, East Ohio filed its application proposing an approach to establishing rates and charges by and through which to return tax reform benefits to its customers. This case is pending.

As directed by the West Virginia Commission, Hope is utilizing regulatory accounting to track the effects of the 2017 Tax Reform Act beginning in January 2018 and submitted testimony in July 2018 detailing such effects. In August 2018, the West Virginia Commission approved a settlement implementing base

rate reductions effective September 1, 2018. In November 2018, the West Virginia Commission issued an order requiring Hope to file a calculation of prospective tax reform savings based on 2017 financial statements, using federal income tax rates reduced for consolidated tax savings, and to record as a regulatory liability the difference between the amount calculated based on 2017 financial statements and the amount included in the voluntary base rate reduction effective September 1, 2018. In December 2018, Hope filed the required calculation setting forth an annual regulatory liability deferral amount of $0.4 million. The disposition of the additional regulatory liability will be determined in a future rate proceeding. These reductions are not expected to have a material impact on Hope’s financial condition.

In March 2018, FERC announced actions to address the income tax allowance component of regulated entities’ cost-of-service rates as a result of the 2017 Tax Reform Act. FERC required all interstate natural gas pipelines to make a one-time informational filing with FERC to provide financial information to allow FERC and other interested parties to analyze the impacts of the changes in tax law. The actions also included the reversal of FERC’s policy allowing master limited partnerships to recover an income tax allowance in cost-of-service rates and requiring other pass-through entities to justify the inclusion of an income tax allowance.

In July 2018, FERC issued a final rule adopting and modifying the procedures for determining whether jurisdictional natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the corporate income tax rate. Specifically, this final rule does not require master limited partnerships to eliminate their income tax allowances when completing the informational filing and allows entities that are wholly-owned by corporations to include an income tax allowance.

During 2018, Dominion Energy’s FERC-regulated pipelines, including those accounted for as equity method investments, filed the required informational reports with FERC. Dominion Energy Overthrust Pipeline, LLC, White River Hub, Dominion Energy Questar Pipeline and Cove Point have reached resolution through settlement, which did not result in a material impact to results of operations, financial condition and/or cash flows of Dominion Energy, waiver or FERC terminating the 501-G proceeding. In January 2019, Iroquois reached a settlement in principle with its customers, which if approved would not have a material impact to Dominion Energy or Dominion Energy Gas, and expects to file a settlement agreement with FERC in the first quarter of 2019. The FERC dockets for DETI and DECG remain open. While the informational filings for these two pipelines indicated that no changes to current rates charged to customers were necessary, given the associated uncertainty, Dominion Energy and Dominion Energy Gas are currently unable to predict the outcome of these matters; however, any change in rates permitted to be charged to customers could have a material impact on results of operations, financial condition and/or cash flows.

Other Regulatory Matters

VIRGINIA REGULATION

The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers.

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The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, underground distribution lines, environmental compliance, conservation and energy efficiency programs, renewable energy programs and nuclear license renewals, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.

If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.

Grid Transformation and Security Act of 2018

In March 2018, the GTSA reinstated base rate reviews on a triennial basis, other than the first review which will be a quadrennial review, occurring for Virginia Power in 2021 for the four successive 12-month test periods beginning January 1, 2017 and ending December 31, 2020. This review for Virginia Power will occur one year earlier than under the Regulation Act legislation enacted in February 2015.

In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized return on equity that might have been refunded to customers and served as the basis for a reduction in future rates, may be reduced by approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include in a customer credit reinvestment offset. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a customer credit reinvestment offset. Any costs that are the subject of a customer credit reinvestment offset may not be recovered in base rates for the service life of the projects and may not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized return on equity, base rates are subject to reduction prospectively and customer refunds would be due unless the total customer credit reinvestment offset elected by the utility equals or exceeds the amount of earnings in excess of the 70 basis points. In the 2021 review, any such rate reduction is limited to $50 million.

The legislation also includes provisions requiring Virginia Power to provide current customers one-time rate credits totaling $200 million and to reduce base rates to reflect reductions in income tax expense resulting from the 2017 Tax Reform Act. As a result, Virginia Power incurred a $215 million ($160 million after-tax) charge in connection with this legislation, including the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology. In July 2018 and January 2019, Virginia Power credited $138 million and $77 million, respectively, to current customers’ bills.

In addition, Virginia Power reduced base rates on an annual basis by $125 million effective July 2018, to reflect the estimated effect of the 2017 Tax Reform Act, which is subject to adjustment

effective April 2019. In May and June 2018, Virginia Power submitted filings detailing the implementation plan for interim reductions in rates for generation and distribution services pursuant to the GTSA.

In July 2018, Virginia Power filed a petition with the Virginia Commission for approval of the first three years of its ten-year plan for electric distribution grid transformation projects as authorized by the GTSA. During the first three years of the plan, Virginia Power proposes to focus on the following seven foundational components of the overall grid transformation plan: (i) smart meters; (ii) customer information platform; (iii) reliability and resilience; (iv) telecommunications infrastructure; (v) cyber and physical security; (vi) predictive analytics; and (vii) emerging technology. The total estimated capital investment during 2019-2021 is $816 million and the proposed operations and maintenance expenses are $102 million. In January 2019, the Virginia Commission issued its final order approving capital spending for the first three years of the plan-totaling $68 million on cyber and physical security and related telecommunications infrastructure. The Virginia Commission declined to approve the remainder of the proposed components for the first three years of the plan, the proposed spending for which was not found reasonable and prudent based on the record in the proceeding. Virginia Power intends to file a revised plan in mid-2019 that will address the elements needed for a comprehensive plan, as outlined by the Virginia Commission in its order.

Virginia Fuel Expenses

In May 2018, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.5 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2018. Virginia Power’s proposed fuel rate represented a fuel revenue increase of $222 million when applied to projected kilowatt-hour sales for the period July 1, 2018 to June 30, 2019. In August 2018, the Virginia Commission approved Virginia Power’s fuel rate with an increase of $209 million.

Solar Facility Projects

In July 2018, Virginia Power filed an application with the Virginia Commission for CPCNs to construct two solar facilities. Colonial Trail West and Spring Grove 1 are estimated to cost approximately $410 million, excluding financing costs. Colonial Trail West and Spring Grove 1 are expected to commence commercial operations, subject to regulatory approvals associated with the projects, in the fourth quarter of 2019 and the fourth quarter of 2020, respectively. Virginia Power also applied for approval of Rider US-3 associated with these projects with a proposed $10 million total revenue requirement for the rate year beginning March 1, 2019. In January 2019, the Virginia Commission issued a final order granting CPCNs to construct the solar facilities, subject to a 20-year performance guarantee of the facilities at a 25% solar capacity factor when normalized for force majeure events. The matter regarding Rider US-3 is pending.

Rate Adjustment Clauses

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

• The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2018, Virginia Power proposed a $755 million total revenue requirement consisting of $468 million for the transmission component of Virginia

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Power’s base rates and $287 million for Rider T1. This total revenue requirement represents a $146 million increase versus the revenues to be produced during the rate year under current rates. In August 2018, the Virginia Commission approved a total revenue requirement of $630 million, including Rider T1, subject to true-up, for the rate year beginning September 1, 2018. The Virginia Commission’s order required an adjustment to Rider T1 to begin providing projected benefits associated with the 2017 Tax Reform Act to customers in rates effective September 1, 2018. Such projected benefits were not included in the underlying transmission formula rates approved by FERC. Also in August 2018, Virginia Power filed a petition with the Virginia Commission seeking limited reconsideration and rehearing of this approval to adjust the total revenue requirement to $636 million. In November 2018, the Virginia Commission denied the petition for limited reconsideration and rehearing and adjusted the total revenue requirement to $628 million.

• The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by Virginia legislation. In March 2018, Virginia Power requested approval of its third phase of conversions totaling $179 million and a balance of $65 million in second phase conversions not previously approved for recovery through Rider U. Virginia Power also proposed a total $73 million revenue requirement for the rate year beginning February 1, 2019 for continuing recovery of the previously approved first and second phase conversions and the proposed second and third phase conversions. In December 2018, the Virginia Commission approved a total $70 million annual revenue requirement effective February 1, 2019, a total capital investment of $179 million for third phase conversions and a balance of $64 million for second phase conversions not previously approved for recovery through Rider U.

• The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In October 2018, Virginia Power requested approval to implement ten new energy efficiency programs and one new demand-response DSM program for five years, subject to future extensions, with a $262 million cost cap, and proposed a total $49 million revenue requirement for the rate year beginning July 1, 2019, which represents an $18 million increase over the previous year. This matter is pending.

Additional significant riders associated with various Virginia Power projects are as follows:

Rider Name	Application Date	Approval Date	Rate Year Beginning	Total Revenue Requirement (millions)		Increase (Decrease) Over Previous Year (millions)
Rider S	June 2018	February 2019	April 2019	$	215	$	(3	)
Rider GV	June 2018	February 2019	April 2019		120		38
Rider W	June 2018	February 2019	April 2019		105		(4	)
Rider R	June 2018	February 2019	April 2019		57		(9	)
Rider B	June 2018	February 2019	April 2019		38		(9	)
Rider BW	October 2018	Pending	September 2019		123		7
Rider US-2	October 2018	Pending	September 2019		16		3
Rider E	December 2018	Pending	November 2019		114		N/A

Coastal Virginia Offshore Wind Project

In November 2018, Virginia Power received approval from the Virginia Commission for its petition seeking a prudency determination as provided in the GTSA with respect to the proposed Coastal Virginia Offshore Wind project consisting of two 6 MW wind turbine generators located approximately 27 miles off the coast of Virginia Beach, Virginia in federal waters, and for a CPCN, for the generation tie line connecting the generators to shore. This project is expected to cost approximately $300 million and to be placed into service by the end of 2020.

Electric Transmission Projects

In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry switching station in Surry County to a new Skiffes Creek switching station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed new Skiffes Creek switching station to Virginia Power’s existing Whealton substation in the City of Hampton. As of July 2017, Virginia Power has received all major required permits and approvals and is proceeding with construction of the project. In connection with the receipt of the permit from the U.S. Army Corps of Engineers in July 2017, Virginia Power was required to make payments totaling approximately $90 million to fund improvements to historical and cultural resources near the project. Accordingly, in July 2017, Virginia Power recorded an increase to property, plant and equipment and a corresponding liability for these payment obligations. Through December 31, 2017, Virginia Power had made $90 million of such payments. Also in July 2017, the National Parks Conservation Association filed a lawsuit in U.S. District Court for the D.C. Circuit seeking to set aside the permit granted by the U.S. Army Corps of Engineers for the project and requested a preliminary injunction against the permit. In August 2017, the National Trust for Historic Preservation and Preservation Virginia filed a similar lawsuit in U.S. District Court for the D.C. Circuit. In October 2017, the preliminary injunction requests were denied. In May 2018, the District Court granted summary judgment in favor of the U.S. Army Corps of Engineers and Virginia Power and dismissed both lawsuits. In June 2018, the National Parks Conservation Association and the National Trust for Historic Preservation and Preservation Virginia appealed that decision to the U.S. Court of Appeals for the D.C. Circuit. The appeal is pending. Also in June 2018, the National Parks Conservation Association filed requests with the U.S. District Court for the District of Columbia and the U.S. Court of Appeals for the D.C. Circuit for an injunction against the permit pending appeal. The U.S. District Court for the District of Columbia denied the injunction request in June 2018 and the U.S. Court of Appeals for the D.C. Circuit similarly denied the request in July 2018.

In November 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to convert an existing transmission line to 230 kV in Prince William County, Virginia, and Loudoun County, Virginia, and to construct and operate a new approximately five mile overhead 230 kV double circuit transmission line between a tap point near the Gainesville substation and a new to-be-constructed Haymarket substation. The

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total estimated cost of the project is approximately $180 million. In April 2017, the Virginia Commission issued an interim order instructing Virginia Power to construct and operate the project along an approved route if Virginia Power could obtain all necessary rights-of-way. Otherwise, the Virginia Commission ruled that Virginia Power can construct and operate the project along an approved alternative route. In June 2017, the Virginia Commission issued a final order approving the alternative route for the project, and granted the necessary CPCN. In July 2017, the Virginia Commission retained jurisdiction over the case to evaluate two requests to reconsider its decisions. Also in July 2017, Virginia Power requested that the Virginia Commission stay the proceeding while Virginia Power discusses the proposed route with leaders of Prince William County. In December 2017, the Virginia Commission granted in part the two motions for reconsideration, retained jurisdiction for further proceedings in the case and stayed the effectiveness of its final order. In March 2018, Virginia Power and the two parties seeking reconsideration entered into a stipulation settlement filed with the Virginia Commission agreeing that the project should be placed into an underground pilot program created by the GTSA. In July 2018, Virginia Power filed a request with the Virginia Commission to allow the project to participate in the underground pilot program. Subsequently, in July 2018, the Virginia Commission issued a final order granting the CPCN for the project and allowing the project to participate in the underground pilot program.

In June 2018, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in King and Queen, King William, and New Kent Counties, Virginia four separate segments of 230 kV transmission line between Lanexa and the Northern Neck in Virginia. In February 2019, Virginia Power withdrew two of the segments from the application. As a result, the total estimated cost of the project is approximately $30 million. This matter is pending.

Additional significant Virginia Power electric transmission projects approved and applied for in 2018 are as follows:

Description and Location of Project	Application Date	Approval Date	Type of Line		Miles of Lines		Cost Estimate (millions)
Rebuild and operate existing 115 kV transmission lines between the Possum Point Switching Station and Northern Virginia Electric Cooperative’s Smoketown delivery point	June 2017	February 2018		230 kV		9	$	20
Rebuild and operate between the Dooms substation and the Valley substation, along with associated substation work	September 2017	September 2018		500 kV		18		65
Build and operate between the Idylwood and Tysons substations, along with associated substation work	November 2017	September 2018		230 kV		4		125
Rebuild and operate between the Chesterfield and Hopewell substations, along with associated substation work	May 2018	November 2018		230 kV		8		30
Rebuild and operate between the Chesterfield and Lakeside substations, along with associated substation work	May 2018	December 2018		230 kV		21		35
Rebuild and operate between the Landstown and Thrasher substations, along with associated substation work	June 2018	December 2018		230 kV		8.5		20
Partial rebuild of overhead transmission lines in Alleghany County, Virginia and Covington, Virginia	August 2018	Pending		138 kV		5		15
Build a new substation and connect three existing transmission lines thereto in Fluvanna County, Virginia	October 2018	Pending		230 kV		<1		30

NORTH CAROLINA REGULATION

In August 2018, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed a total $24 million increase to the fuel component of its electric rates for the rate year beginning February 1, 2019. As a mitigation alternative, Virginia Power proposed recovering 50% in the February 1, 2019 to the January 31, 2020 rate period and the remaining 50% in the following rate period. In January 2019, the North Carolina Commission approved Virginia Power’s full proposed fuel charge adjustment of $24 million.

OHIO REGULATION

PIR Program

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In March 2015, East Ohio filed an application with the Ohio Commission requesting approval to extend the PIR program for an additional five years and to increase the annual capital investment, with corresponding increases in the annual rate-increase caps. In September 2016, the Ohio Commission approved a stipulation filed jointly by East Ohio and the Staff of the Ohio Commission to settle East Ohio’s pending application. As requested, the PIR program and associated cost recovery will continue for another five-year term, calendar years 2017 through 2021, and East Ohio will be permit-

ted to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio.

In April 2018, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2017 costs. The filing reflects gross plant investment for 2017 of $204 million, cumulative gross plant investment of $1.4 billion and a revenue requirement of $165 million.

AMR Program

In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. The AMR program approved by the Ohio Commission was completed in 2012. Although no further capital investment will be added, East Ohio is approved to recover depreciation, property taxes, carrying charges and a return until East Ohio has another rate case.

In April 2018, the Ohio Commission approved East Ohio’s application to adjust its AMR cost recovery rate for 2017 costs. The filing reflects a revenue requirement of approximately $5 million.

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

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Combined Notes to Consolidated Financial Statements, Continued

the rules of the Ohio Commission. In May 2018, East Ohio filed its annual update of the PIPP rider with the Ohio Commission. In July 2018, 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 recovery over the twelve-month period from July 2018 through June 2019 of projected deferred program costs of approximately $10 million from April 2018 through June 2019, net of a refund for over-recovery of accumulated arrearages of approximately $4 million as of March 31, 2018.

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 September 2018, the Ohio Commission approved East Ohio’s application requesting approval of its UEX Rider to reflect a refund of over-recovered accumulated bad debt expense of approximately $11 million as of March 31, 2018, and recovery of prospective net bad debt expense projected to total $16 million for the twelve-month period from April 2018 to March 2019.

DSM Rider

East Ohio has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In November 2018, East Ohio filed an application with the Ohio Commission seeking approval of an adjustment to the DSM rider to recover a total of $4 million, which includes an over-recovery of costs during the preceding 12-month period. This application was approved by the Ohio Commission in January 2019.

WEST VIRGINIA REGULATION

In May 2018, Hope filed a PREP application with the West Virginia Commission requesting approval to recover PREP costs related to $31 million and $36 million of projected capital investment for 2018 and 2019, respectively. The application also includes a true-up of PREP costs related to the 2017 actual capital investment of $28 million and sets forth $8 million of annual PREP costs to be recovered in proposed rates effective November 2018. In October 2018, the West Virginia Commission approved PREP rates effective November 2018. Approved rates recover $7 million of annual PREP costs related to actual cumulative PREP investment through December 31, 2017 of $48 million and projected PREP investment for calendar years 2018 and 2019 of $31 million and $29 million, respectively.

UTAH AND WYOMING REGULATION

Fuel Deferral

In May 2018, Questar Gas submitted filings with both the Utah Commission and the Wyoming Commission for an approximately $86 million gas cost decrease reflecting forecasted decreases in commodity costs. The Utah Commission and the Wyoming Commission both approved the filings in May 2018 with rates effective June 2018.

In October 2018, Questar Gas submitted filings with both the Utah Commission and the Wyoming Commission for an approximately $48 million gas cost decrease reflecting forecasted decreases in commodity costs. The Utah Commission and the

Wyoming Commission both approved the filings in October 2018 with rates effective November 2018.

In October 2018, the Utah Commission denied Questar Gas’ request for pre-approval to construct an LNG peaking storage facility with a liquefaction rate of 8.2 million cubic feet per day. Questar Gas is reviewing the order and assessing its options, which include filing supplemental information with the Utah Commission for reconsideration.

Infrastructure Replacement Tracker

During 2018, Questar Gas filed applications with the Utah Commission to increase its infrastructure replacement surcharge to collect an additional $11 million in revenue in 2019 related to $85 million in 2018 capital investment. The Utah Commission approved the applications in the fourth quarter of 2018.

FERC—GAS

Cove Point

In March 2018, Cove Point submitted its annual electric power cost adjustment to FERC requesting approval to recover $30 million. FERC approved the adjustment in March 2018.

In June 2015, Cove Point executed two binding precedent agreements for the approximately $150 million Eastern Market Access Project. In January 2018, Cove Point received FERC authorization to construct and operate the project facilities, which are expected to be placed in service in the second half of 2019. In October 2018, Cove Point announced it is evaluating alternatives to a proposed Charles County, Maryland compressor station that was initially part of this project and in December 2018, after working with project customers for alternative solutions, decided not to pursue further construction at this location resulting in a revised project estimate of approximately $45 million and a write-off of $37 million pre-tax ($28 million after-tax) recorded within impairment of assets and related charges in Dominion Energy’s Consolidated Statements of Income.

DETI

In September 2018, DETI submitted its annual transportation cost rate adjustment to FERC requesting approval to recover $37 million. Also in September 2018, DETI submitted its annual electric power cost adjustment to FERC requesting approval to recover $7 million. In October 2018, FERC approved these adjustments.

In August 2018, DETI executed a binding precedent agreement with a customer for the West Loop project. The project is expected to cost approximately $95 million and provide 150,000 Dth per day of firm transportation service from Pennsylvania to Ohio for delivery to a proposed combined-cycle, natural gas-fired electric power generation facility to be located in Columbiana County, Ohio. In December 2018, DETI filed an application to request FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service by the end of 2021.

NOTE 14. ASSET RETIREMENT OBLIGATIONS

AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of the Companies’ long-lived assets. Dominion Energy and Virginia Power’s AROs are primarily associated with the decom-

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missioning of their nuclear generation facilities and ash pond and landfill closures. Dominion Energy Gas’ AROs primarily include plugging and abandonment of gas and oil wells and the interim retirement of natural gas gathering, transmission, distribution and storage pipeline components.

The Companies have also identified, but not recognized, AROs related to the retirement of Dominion Energy’s LNG facility, Dominion Energy and Dominion Energy Gas’ storage wells in their underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in Dominion Energy and Virginia Power’s generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs during 2017 and 2018 were as follows:

	Amount
(millions)
Dominion Energy
AROs at December 31, 2016	$	2,485
Obligations incurred during the period		37
Obligations settled during the period		(214	)
Revisions in estimated cash flows		7
Accretion		117
AROs at December 31, 2017(1)	$	2,432
Obligations incurred during the period		20
Obligations settled during the period		(159	)
Revisions in estimated cash flows(2)		120
Accretion		119
AROs at December 31, 2018(1)	$	2,532
Virginia Power
AROs at December 31, 2016	$	1,443
Obligations incurred during the period		11
Obligations settled during the period		(152	)
Revisions in estimated cash flows		(1	)
Accretion		64
AROs at December 31, 2017	$	1,365
Obligations incurred during the period		14
Obligations settled during the period		(119	)
Revisions in estimated cash flows(2)		120
Accretion		65
AROs at December 31, 2018	$	1,445
Dominion Energy Gas
AROs at December 31, 2016	$	156
Obligations incurred during the period		2
Obligations settled during the period		(7	)
Accretion		9
AROs at December 31, 2017(3)	$	160
Obligations incurred during the period		4
Obligations settled during the period		(6	)
Accretion		9
AROs at December 31, 2018(3)	$	167

(1) Includes $263 million and $282 million reported in other current liabilities at December 31, 2017, and 2018, respectively.

(2) Reflects future ash pond and landfill closure costs at certain utility generation facilities. See Note 22 for further information.

(3) Includes $146 million and $153 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities, at December 31, 2017 and 2018, respectively.

Dominion Energy and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31, 2018 and 2017, the aggregate fair value of Dominion Energy’s trusts, consisting primarily of equity and debt securities, totaled $4.9 billion and $5.1 billion, respectively. At December 31, 2018 and 2017, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $2.4 billion for both periods.

NOTE 15. 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 ENERGY

At December 31, 2018, Dominion Energy owned the general partner, 60.9% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owned a preferred equity interest and the general partner interest in Cove Point. In January 2019, Dominion Energy acquired all outstanding partnership interests not owned by Dominion Energy and Dominion Energy Midstream became a wholly-owned subsidiary of Dominion Energy. Dominion Energy previously concluded that Dominion Energy Midstream was a VIE due to the limited partners lacking the characteristics of a controlling financial interest. Dominion Energy was the primary beneficiary of Dominion Energy Midstream and Dominion Energy Midstream was the primary beneficiary of Cove Point as they had the power to direct the activities that most significantly impact their economic performance as well as to absorb losses and benefits which could be significant to them.

At December 31, 2018, Dominion Energy owns the manager and 67% of the membership interest in certain merchant solar facilities, as discussed in Note 2. Dominion Energy has concluded that these entities are VIEs due to the members lacking the characteristics of a controlling financial interest. In addition, in 2016 Dominion Energy created a wholly owned subsidiary, SBL Holdco, as a holding company of its interest in the VIE merchant solar facilities and accordingly SBL Holdco is a VIE. Dominion Energy is the primary beneficiary of SBL Holdco and the merchant solar facilities, as it has 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 Energy’s securities due within one year and long-term debt include $31 million and $299 million, respectively, of debt issued by SBL Holdco net of issuance costs that is nonrecourse to Dominion Energy and is secured by SBL Holdco’s interest in certain merchant solar facilities.

Dominion Energy owns a 48% membership interest in Atlantic Coast Pipeline. See Note 9 for more details regarding the

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Combined Notes to Consolidated Financial Statements, Continued

nature of this entity. Dominion Energy concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion Energy 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 Energy is obligated to provide capital contributions based on its ownership percentage. Dominion Energy’s maximum exposure to loss is limited to its current and future investment as well as any obligations under a guarantee provided. See Note 22 for more information.

DOMINION ENERGY AND VIRGINIA POWER

Dominion Energy and Virginia Power’s nuclear decommissioning trust funds and Dominion Energy’s rabbi trusts hold investments in limited partnerships or similar type entities (see Note 9 for further details). Dominion Energy and Virginia Power concluded that these partnership investments are VIEs due to the limited partners lacking the characteristics of a controlling financial interest. Dominion Energy 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 Energy and Virginia Power are obligated to provide capital contributions to the partnerships as required by each partnership agreement based on their ownership percentages. Dominion Energy and Virginia Power’s maximum exposure to loss is limited to their current and future investments.

DOMINION ENERGY AND DOMINION ENERGY GAS

Dominion Energy 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 2016, such right no longer existed and, as a result, Dominion Energy concluded that Iroquois is no longer a VIE.

VIRGINIA POWER

Virginia Power had long-term power and capacity contracts with three non-utility generators, which contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. Contracts with two of these non-utility generators expired during 2017, leaving a remaining aggregate summer generation capacity of approximately 218 MW. 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 remaining entity during the remaining terms of Virginia Power’s contract and for the years the entity is expected to operate after its contractual relationship expires. The remaining contract expires in 2021. Virginia Power is not subject to any risk of loss from this potential VIE other than its remaining purchase commitments which totaled $150 million as of December 31, 2018. Virginia

Power paid $50 million, $86 million, and $144 million for electric capacity to non-utility generators and $18 million, $24 million, and $31 million for electric energy to non-utility generators for the years ended December 31, 2018, 2017 and 2016, respectively.

DOMINION ENERGY GAS

DETI 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 DETI holds a membership interest in Atlantic Coast Pipeline, therefore DETI 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. DETI 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. DETI has no obligation to absorb any losses of the VIE. See Note 24 for information about associated related party receivable balances.

VIRGINIA POWER AND DOMINION ENERGY GAS

Virginia Power and Dominion Energy Gas purchased shared services from DES, an affiliated VIE, of $335 million and $126 million, $340 million and $126 million, and $346 million and $123 million for the years ended December 31, 2018, 2017 and 2016, respectively. Virginia Power and Dominion Energy Gas’ Consolidated Balance Sheets included amounts due to DES of $107 million and $46 million, respectively, at December 31, 2018, and $36 million and $14 million, respectively, at December 31, 2017, recorded in payables to affiliates in the Consolidated Balance Sheets. Virginia Power and Dominion Energy Gas determined that neither is the primary beneficiary of DES 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. DES provides accounting, legal, finance and certain administrative and technical services to all Dominion Energy subsidiaries, including Virginia Power and Dominion Energy Gas. Virginia Power and Dominion Energy Gas have no obligation to absorb more than their allocated shares of DES costs.

NOTE 16. SHORT-TERM DEBT AND CREDIT AGREEMENTS

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 Energy utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties.

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DOMINION ENERGY

In March 2018, Dominion Energy replaced its two existing joint revolving credit facilities with a $6.0 billion joint revolving credit facility. Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities were as follows:

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit		Facility Capacity Available
(millions)
At December 31, 2018
Joint revolving credit facility(2)	$	6,000		$   324		$88	$	5,588
At December 31, 2017
Joint revolving credit facility(3)	$	5,000		$3,298		$—	$	1,702
Joint revolving credit facility(3)		500		—		76		424
Total	$	5,500		$3,298		$76	$	2,126

(1) The weighted-average interest rates of the outstanding commercial paper supported by Dominion Energy’s credit facilities were 2.93% and 1.61% at December 31, 2018 and 2017, respectively.

(2) This credit facility matures in March 2023 and can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

(3) These credit facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. The facilities were scheduled to mature in April 2020 and were 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.

In connection with the SCANA Combination, Dominion Energy intends to terminate SCANA, SCE&G and PSNC’s existing credit facilities and add SCE&G as a co-borrower to its $6.0 billion joint revolving credit facility in the first quarter of 2019 once certain regulatory approvals are obtained. In January 2019, Virginia Power and SCE&G, as co-borrowers, filed with the Virginia Commission and the South Carolina Commission, respectively, for approval. In February 2019, the Virginia Commission approved the request.

Questar Gas’ short-term financing is supported through its access as co-borrower to the joint revolving credit facility discussed above with Dominion Energy, Virginia Power and Dominion Energy Gas. At December 31, 2018, the sub-limit for Questar Gas was $250 million.

In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which had an original stated maturity date of December 2017 with automatic one-year renewals through the maturity of the SBL Holdco term loan agreement in 2023. Dominion Solar Projects III, Inc. has $25 million of credit facilities which had an original stated maturity date of May 2018 with automatic one-year renewals through the maturity of the Dominion Solar Projects III, Inc. term loan agreement in 2024. At December 31, 2018, no amounts were outstanding under either of these facilities.

In February and June 2018, Dominion Energy borrowed $950 million and $500 million, respectively, under 364-Day

Term Loan Agreements that bore interest at a variable rate. In September 2018, the principal outstanding plus accrued interest for both borrowings was repaid.

In March 2018, Dominion Energy Midstream entered into a $500 million revolving credit facility. The credit facility was scheduled to mature in March 2021, bore interest at a variable rate, and was used to support bank borrowings and the issuance of commercial paper, as well as to support up to $250 million of letters of credit. At December 31, 2018, Dominion Energy Midstream had $73 million outstanding under this credit facility. In February 2019, Dominion Energy Midstream terminated the facility subsequent to repaying the outstanding balance, plus accrued interest.

In October 2018, Dominion Energy entered into a credit agreement, which allows Dominion Energy to issue up to approximately $21 million in letters of credit. The facility terminates in June 2020. At December 31, 2018, Dominion Energy had $21 million in letters of credit outstanding under this agreement.

VIRGINIA POWER

In March 2018, Dominion Energy replaced its two existing joint revolving credit facilities with a $6.0 billion joint revolving credit facility. Virginia Power’s short-term financing is supported through its access as co-borrower to the joint revolving credit facility. The credit facility can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

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

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit
(millions)
At December 31, 2018
Joint revolving credit facility(2)		$6,000		$314		$16
At December 31, 2017
Joint revolving credit facility(3)		$5,000		$542		$—
Joint revolving credit facility(3)		500		—		—
Total		$5,500		$542		$—

(1) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 2.94% and 1.65% at December 31, 2018 and 2017, respectively.

(2) The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Virginia Power was $1.5 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

(3) These facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. The full amount of the facilities was available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. These facilities were scheduled to mature in April 2020 and were 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.

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Combined Notes to Consolidated Financial Statements, Continued

In addition to the credit facility commitments mentioned above, Virginia Power also had a $100 million credit facility with a maturity date of April 2020. In March 2018, Virginia Power redeemed its variable rate tax-exempt financings supported by this credit facility and terminated the facility.

DOMINION ENERGY GAS

In March 2018, Dominion Energy replaced its two existing joint revolving credit facilities with a $6.0 billion joint revolving credit facility. Dominion Energy Gas’ short-term financing is supported by its access as co-borrower to the joint revolving credit facility. The credit facility can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

Dominion Energy Gas’ share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion Energy, Virginia Power and Questar Gas were as follows:

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit
(millions)
At December 31, 2018
Joint revolving credit facility(2)		$1,500		$  10		$—
At December 31, 2017
Joint revolving credit facility(3)		$1,000		$629		$—
Joint revolving credit facility(3)		500		—		—
Total		$1,500		$629		$—

(1) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 2.58% and 1.57% at December 31, 2018 and 2017, respectively.

(2) A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. The sub-limit for Dominion Energy Gas is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Dominion Energy Gas was $750 million. If Dominion Energy 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

(3) These facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. A maximum of a combined $1.5 billion of the facilities was available to Dominion Energy Gas, assuming adequate capacity was available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. These credit facilities were scheduled to mature in April 2020 and were used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

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NOTE 17. LONG-TERM DEBT

At December 31,	2018 Weighted- average Coupon(1)			2018			2017
(millions, except percentages)
Dominion Energy Gas Holdings, LLC:
Unsecured Senior Notes:
Variable rate, due 2021		3.39	%	$	500		$	—
2.5% to 3.55%, due 2019 to 2023		2.90	%		1,800			1,800
3.317% to 4.8%, due 2024 to 2044(2)		4.12	%		1,787			1,800
Dominion Energy Gas Holdings, LLC total principal				$	4,087		$	3,600
Securities due within one year		2.50	%		(449	)		—
Unamortized discount and debt issuance costs					(29	)		(30	)
Dominion Energy Gas Holdings, LLC total long-term debt				$	3,609		$	3,570
Virginia Electric and Power Company:
Unsecured Senior Notes:
1.2% to 5.4%, due 2018 to 2023		3.35	%	$	1,800		$	2,650
2.95% to 8.875%, due 2024 to 2048		4.61	%		9,290			7,990
Tax-Exempt Financings(3):
Variable rates, due 2024 to 2027					—			100
1.75% to 5.6%, due 2023 to 2041		2.18	%		664			678
Virginia Electric and Power Company total principal				$	11,754		$	11,418
Securities due within one year		5.00	%		(350	)		(850	)
Unamortized discount, premium and debt issuances costs, net					(83	)		(72	)
Virginia Electric and Power Company total long-term debt				$	11,321		$	10,496
Dominion Energy, Inc.:
Unsecured Senior Notes(4):
Variable rates, due 2019 and 2020		3.23	%	$	800		$	800
1.5% to 6.4%, due 2018 to 2022		2.75	%		2,550			5,800
2.85% to 7.0%, due 2024 to 2044		4.81	%		4,849			5,049
Unsecured Junior Subordinated Notes:
2.579% to 4.104%, due 2019 to 2021		3.08	%		2,100			2,100
Payable to Affiliated Trust, 8.4%, due 2031		8.40	%		10			10
Enhanced Junior Subordinated Notes:
5.25% and 5.75%, due 2054 and 2076		5.48	%		1,485			1,485
Variable rates, due 2066		5.26	%		422			422
Remarketable Subordinated Notes, 2.0%, due 2021 and 2024		2.00	%		1,400			1,400
Unsecured Debentures and Senior Notes(5):
6.8% and 6.875%, due 2026 and 2027		6.81	%		89			89
Unsecured Senior and Medium-Term Notes(6):
5.31% and 6.3%, due 2018					—			120
2.98% to 7.20%, due 2024 to 2051		4.25	%		750			600
Secured Senior Notes, 4.82%, due 2042(7)		4.82	%		362			—
Term Loans, variable rates, due 2023 and 2024(8)		4.85	%		582			638
Tax-Exempt Financing, 1.55%, due 2033(9)		1.55	%		27			27
Capital leases, 4.14% to 6.04%, due 2019 to 2029		5.99	%		39			—
Dominion Energy Midstream Partners, LP:
Term Loans, variable rates, due 2019 and 2021(10)(11)		4.13	%		3,300			300
Revolving Credit Agreement, variable rates, due 2021(11)		3.55	%		73			—
Unsecured Senior and Medium-Term Notes, 5.83% and 6.48%, due 2018(12)					—			255
Unsecured Senior Notes, 3.53% to 4.875%, due 2028 to 2041(12)		4.23	%		430			180
Dominion Energy Gas Holdings, LLC total principal (from above)					4,087			3,600
Virginia Electric and Power Company total principal (from above)					11,754			11,418
Dominion Energy, Inc. total principal				$	35,109		$	34,293
Fair value hedge valuation(13)					(20	)		(22	)
Securities due within one year(14)(15)		3.23	%		(3,624	)		(3,078	)
Credit facility borrowings(11)		3.55	%		(73	)		—
Unamortized discount, premium and debt issuance costs, net					(248	)		(245	)
Dominion Energy, Inc. total long-term debt				$	31,144		$	30,948

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2018.

157

Combined Notes to Consolidated Financial Statements, Continued

(2) Amount includes foreign currency remeasurement adjustments.

(3) These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. In March 2018, Virginia Power redeemed certain variable rate tax-exempt financings supported by its $100 million credit facility and terminated the facility. In December 2018, Virginia Power redeemed its $14 million Economic Development Authority of the County of Chesterfield Solid Waste and Sewage Disposal Revenue Bonds due in 2031.

(4) In November and December 2018, Dominion Energy redeemed certain senior notes prior to their stated maturity. See below for a discussion of the senior note redemptions.

(5) Represents debt assumed by Dominion Energy from the merger of its former CNG subsidiary.

(6) Represents debt obligations of Questar Gas. See Note 3 for more information.

(7) Represents debt obligations of Eagle Solar. The debt is nonrecourse to Dominion Energy and is secured by Eagle Solar’s interest in certain merchant solar facilities.

(8) Represents debt associated with SBL Holdco and Dominion Solar Projects III, Inc. The debt is nonrecourse to Dominion Energy and is secured by SBL Holdco and Dominion Solar Projects III, Inc.’s interest in certain merchant solar facilities.

(9) Represents debt obligations of a DGI subsidiary.

(10) Includes debt obligations of Cove Point that are secured by Dominion Energy’s common equity interest in Cove Point.

(11) In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2018.

(12) Represents debt obligations of Dominion Energy Questar Pipeline. See Note 3 for more information.

(13) Represents the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt.

(14) 2017 excludes $250 million of Dominion Energy Questar Pipeline’s senior notes that matured in February 2018 using proceeds from the January 2018 issuance, through private placements, of $100 million and $150 million of senior notes that mature in 2028 and 2038, respectively.

(15) Includes $20 million of estimated mandatory prepayments due within one year based on estimated cash flows in excess of debt service at SBL Holdco and Dominion Solar Projects III, Inc.

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2018, were as follows:

	2019			2020			2021			2022			2023			Thereafter			Total
(millions, except percentages)
Dominion Energy Gas	$	450		$	700		$	500		$	—		$	650		$	1,787		$	4,087
Weighted-average Coupon		2.50	%		2.80	%		3.39	%					3.29	%		4.12	%
Virginia Power
Unsecured Senior Notes	$	350		$	—		$	—		$	750		$	700		$	9,290		$	11,090
Tax-Exempt Financings		—			—			—			—			40			624			664
Total	$	350		$	—		$	—		$	750		$	740		$	9,914		$	11,754
Weighted-average Coupon		5.00	%								3.15	%		2.87	%		4.45	%
Dominion Energy
Term Loans(1)(2)	$	336		$	35		$	3,035		$	34		$	273		$	169		$	3,882
Credit Facility Borrowings(2)		—			—			73			—			—			—			73
Unsecured Senior Notes		2,700			1,000			900			1,500			1,350			17,195			24,645
Secured Senior Notes		17			15			17			19			16			278			362
Tax-Exempt Financings		—			—			—			—			40			651			691
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts		—			—			—			—			—			10			10
Unsecured Junior Subordinated Notes		550			1,000			550			—			—			—			2,100
Enhanced Junior Subordinated Notes		—			—			—			—			—			1,907			1,907
Remarketable Subordinated Notes		—			—			700			—			—			700			1,400
Capital leases		4			4			4			3			3			21			39
Total	$	3,607		$	2,054		$	5,279		$	1,556		$	1,682		$	20,931		$	35,109
Weighted-average Coupon		3.23	%		2.80	%		3.64	%		3.02	%		3.41	%		4.51	%

(1) Excludes mandatory prepayments associated with SBL Holdco and Dominion Solar Projects III, Inc. based on cash flows in excess of debt service. At December 31, 2018, $20 million of estimated mandatory prepayments due within one year were included in securities due within one year in Dominion Energy’s Consolidated Balance Sheets.

(2) In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2018.

The Companies’ short-term credit facility and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2018, there were no events of default under these covenants.

Senior Note Redemptions

In November 2018 and December 2018, Dominion Energy redeemed the following outstanding series of senior notes: 2011 Series A 4.45% Senior Notes due 2021, 2014 Series B 2.50%

Senior Notes due 2019, 2014 Series C 3.625% Senior Notes due 2024 and 2018 Series A Floating Rate Senior Notes due 2020 with an aggregate outstanding principal of $2.2 billion. The aggregate redemption price paid was $2.2 billion and represents the principal amount outstanding, accrued and unpaid interest and the applicable make-whole premium of $34 million. Total charges of $69 million, including the make-whole premium, were recognized and recorded in interest expense in Dominion Energy’s Consolidated Statements of Income.

158

Enhanced Junior Subordinated Notes

In June 2006 and September 2006, Dominion Energy issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids bear interest at three-month LIBOR plus 2.825%, reset quarterly. Previously, interest was fixed at 7.5% per year. The September 2006 hybrids bear interest at the three-month LIBOR plus 2.3%, reset quarterly.

In October 2014, Dominion Energy issued $685 million of October 2014 hybrids that will bear interest at 5.75% per year until October 1, 2024. Thereafter, they will bear interest at the three-month LIBOR plus 3.057%, reset quarterly.

Dominion Energy may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion Energy may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion Energy may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.

Dominion Energy executed RCCs in connection with its issuance of the June 2006 hybrids and the September 2006 hybrids. Under the terms of the RCCs, Dominion Energy covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion Energy shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion Energy has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids at that time, as more fully described in the RCCs. In September 2011, Dominion Energy amended the RCCs of the June 2006 hybrids and September 2006 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock issuances from 180 days to 365 days. The proceeds Dominion Energy receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.

In the first quarter of 2016, Dominion Energy purchased and cancelled $38 million and $4 million of the June 2006 hybrids and the September 2006 hybrids, respectively. In July 2016, Dominion Energy 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 Energy 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 RCC. Also in July 2016, Dominion Energy issued $800 million of 5.25% July 2016 hybrids. The proceeds were used for general corporate purposes, including to finance the tender offer. The July 2016 hybrids are listed on the NYSE under the symbol DRUA.

Remarketable Subordinated Notes

In June 2013, Dominion Energy issued $550 million of 2013 Series A 6.125% Equity Units and $550 million of 2013 Series B 6.0% Equity Units, initially in the form of Corporate Units. In July 2014, Dominion Energy issued $1.0 billion of 2014 Series A 6.375% Equity Units, initially in the form of Corporate Units. The Corporate Units were listed on the NYSE under the symbols DCUA, DCUB and DCUC respectively.

Each Corporate Unit consisted of a stock purchase contract and 1/20 interest in a RSN issued by Dominion Energy. The stock purchase contracts obligated the holders to purchase shares of Dominion Energy common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price paid under the stock purchase contracts was $50 per Corporate Unit and the number of shares purchased was determined under a formula based upon the average closing price of Dominion Energy common stock near the settlement date. The RSNs were pledged as collateral to secure the purchase of common stock under the related stock purchase contracts.

In May 2017, Dominion Energy successfully remarketed the $1.0 billion 2014 Series A 1.50% RSNs due 2020 pursuant to the terms of the related 2014 Equity Units. In connection with the remarketing, the interest rate on the junior subordinated notes was reset to 2.579%, payable on a semi-annual basis and Dominion Energy ceased to have the ability to redeem the notes at its option or defer interest payments. In March 2016 and May 2016, Dominion Energy 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 Energy ceased to have the ability to redeem the notes at its option or defer interest payments. At December 31, 2018, the securities are included in junior subordinated notes in Dominion Energy’s Consolidated Balance Sheets. Dominion Energy did not receive any proceeds from the remarketings. Remarketing proceeds belonged to the investors holding the related 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 Energy for issuance of 12.5 million shares of its common stock in July 2017 and 8.5 million shares of its common stock in both April 2016 and July 2016. See Issuance of Common Stock below for a description of common stock issued by Dominion Energy under the stock purchase contracts.

In August 2016, Dominion Energy issued $1.4 billion of 2016 Series A 6.75% Equity Units, initially in the form of Corporate Units. The Corporate Units are listed on the NYSE under the symbol DCUD. The net proceeds from the 2016 Equity Units were used to finance the Dominion Energy Questar Combination. See Note 3 for more information.

Each 2016 Series A Corporate Unit consists of a stock purchase contract, a 1/40 interest in a 2016 Series A-1 RSN issued by Dominion Energy and a 1/40 interest in a 2016 Series A-2 RSN issued by Dominion Energy. The stock purchase contracts obli-

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Combined Notes to Consolidated Financial Statements, Continued

gate the holders to purchase shares of Dominion Energy common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price to be paid under the stock purchase contracts is $50 per Corporate Unit and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion Energy common stock near the settlement date. The RSNs are pledged as collateral to secure the purchase of common stock under the related stock purchase contracts.

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

Dominion Energy has recorded the present value of the stock purchase contract payments as a liability offset by a charge to

equity. Interest payments on the RSNs are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS, Dominion Energy applies the treasury stock method to the equity units.

Pursuant to the terms of the 2016 Equity Units, Dominion Energy expects to remarket both the 2016 Series A-1 and 2016 Series A-2 RSNs during the second or third quarter of 2019. Following a successful remarketing, the interest rate on the RSNs will be reset, interest will be payable on a semi-annual basis and Dominion Energy will cease to have the ability to redeem the RSNs at its option or defer interest payments. Proceeds of each remarketing will belong to the investors in the related equity units and will be held and applied on their behalf at the settlement date of the related stock purchase contracts to pay the purchase price to Dominion Energy for issuance of its common stock.

Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion Energy will issue between 15.1 million and 18.9 million shares in August 2019. A total of 23.1 million shares of Dominion Energy’s common stock has been reserved for issuance in connection with the stock purchase contracts.

Selected information about Dominion Energy’s equity units is presented below:

Issuance Date	Units Issued		Total Net Proceeds		Total Long-term Debt		RSN Annual Interest Rate			Stock Purchase Contract Annual Rate			Stock Purchase Contract Liability(1)		Stock Purchase Settlement Date
(millions, except interest rates)
8/15/2016(2)		28	$	1,374.8		$1,400.0		2.000	%(3)		4.750	%		$190.6		8/15/2019

(1) Payments of $64 million and $101 million were made in 2018 and 2017, respectively, including payments for the remarketed 2014 Series A notes. The stock purchase contract liability was $47 million and $111 million at December 31, 2018 and 2017, respectively.

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

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

160

NOTE 18. PREFERRED STOCK

Dominion Energy is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 2018 or 2017.

Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference; however, none were issued and outstanding at December 31, 2018 or 2017.

NOTE 19. EQUITY

Issuance of Common Stock

DOMINION ENERGY

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

During 2018, Dominion Energy received cash proceeds, net of fees and commissions, of $2.5 billion from the issuance of approximately 36 million shares of common stock through various programs including the forward sale agreements described below resulting in approximately 681 million shares of common stock outstanding at December 31, 2018. These proceeds include cash of $315 million received from the issuance of 4.5 million of such shares through Dominion Energy Direct^® and employee savings plans.

In July 2017, Dominion Energy issued 12.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2014 Equity Units and received proceeds of $1.0 billion.

In both April 2016 and July 2016, Dominion Energy issued 8.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2013 Equity Units and received $1.1 billion of total proceeds. Additionally, Dominion Energy completed a market issuance of equity in April 2016 of 10.2 million shares and received proceeds of $756 million through a registered underwritten public offering. A portion of the net proceeds was used to finance the Dominion Energy Questar Combination. See Note 3 for more information.

In June 2017, Dominion Energy 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 June 2017, Dominion Energy entered into three separate sales agency agreements to effect sales under the program and pursuant to which it may offer from time to time up to $500 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the NYSE at market prices or in such other transactions as are agreed upon by Dominion Energy and the sales agents in conformance with applicable securities laws. In January 2018, Dominion Energy provided sales instructions to one of the sales agents and issued 6.6 million shares through at-the-market issuances and received cash proceeds of $495 million, net of fees and commissions paid of $5 million. Following these issuances, Dominion Energy had no remaining ability to issue stock under

the 2017 sales agency agreements and completed the program. In February 2018, Dominion Energy entered into six separate sales agency agreements to effect sales under a new at-the-market program pursuant to which it may offer from time to time up to $1.0 billion aggregate amount of its common stock. These agreements replaced the sales agency agreements entered into by Dominion Energy in June 2017. Sales of common stock can be made by means of private negotiated transactions, as transactions on the NYSE at market prices or in such other transactions as are agreed upon by Dominion Energy and the sales agents in conformance with applicable securities laws. In the fourth quarter of 2018, Dominion Energy provided sales instructions to two of the sales agents and issued 2.7 million shares through at-the-market issuances and received cash proceeds of $197 million, net of fees and commissions paid of $2 million. Following these issuances, Dominion Energy has $801 million of remaining ability to issue stock under the sales agency agreements.

Dominion Energy entered in March 2018, and closed in April 2018, separate forward sale agreements with Goldman Sachs & Co. LLC and Credit Suisse Capital LLC, as forward purchasers, and an underwriting agreement with Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, as representatives of the several underwriters named therein, relating to an aggregate of 20 million shares of Dominion Energy common stock. The underwriting agreement granted the underwriters a 30-day option to purchase up to an additional three million shares of Dominion Energy common stock, which the underwriters exercised with respect to approximately 2.1 million shares in April 2018. Dominion Energy entered into separate forward sale agreements with the forward purchasers with respect to the additional shares. In December 2018, Dominion Energy received proceeds of $1.4 billion (after deducting underwriting discounts, but before deducting expenses, and subject to forward price adjustments under the forward sale agreements) upon the physical settlement of 22.1 million shares.

See Note 3 to the Consolidated Financial Statements for information on the issuance of Dominion Energy common stock in January 2019 in connection with the SCANA Combination. Also in January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy through the issuance of common stock as noted below.

VIRGINIA POWER

In 2018, 2017 and 2016, Virginia Power did not issue any shares of its common stock to Dominion Energy.

Shares Reserved for Issuance

Dominion Energy has approximately 76 million shares reserved and available for issuance for Dominion Energy Direct^®, employee stock awards, employee savings plans, director stock compensation plans and issuances in connection with stock purchase contracts and the at-the-market program. See Note 17 for more information.

Repurchase of Common Stock

Dominion Energy did not repurchase any shares in 2018 or 2017 and does not plan to repurchase shares during 2019, except for shares tendered by employees to satisfy tax withholding obliga-

161

Combined Notes to Consolidated Financial Statements, Continued

tions on vested restricted stock, which do not count against its stock repurchase authorization.

Purchase of Dominion Energy Midstream Units

In September 2015, Dominion Energy initiated a program to purchase from the market up to $50 million of common units representing limited partner interests in Dominion Energy Midstream, which expired in September 2016. Dominion Energy purchased approximately 658,000 common units for $17 million for the year ended December 31, 2016.

In January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy through the issuance of 22.5 million shares of common stock valued at $1.6 billion. The merger was accounted for by Dominion Energy following the guidance for a change in a parent company’s ownership interest in a consolidated subsidiary. Because Dominion Energy controls Dominion Energy Midstream both before and after the merger, the changes in Dominion Energy’s ownership interest in Dominion Energy Midstream were accounted for as an equity transaction and no gain or loss will be recognized. The tax effect of the merger will be presented in common stock.

Issuance of Dominion Energy Midstream Units

In 2017, Dominion Energy Midstream received $18 million of proceeds from the issuance of common units through its at-the-market program.

In 2016, Dominion Energy Midstream received $482 million of proceeds from the issuance of common units and $490 million of proceeds from the issuance of convertible preferred units. The net proceeds were primarily used to finance a portion of the acquisition of Dominion Energy Questar Pipeline from Dominion Energy. See Note 3 for more information.

The holders of the convertible preferred units were entitled to receive cumulative quarterly distributions payable in cash or additional convertible preferred units, subject to certain conditions. The units were convertible into Dominion Energy Midstream common units on a one-for-one basis, subject to certain adjustments, (i) in whole or in part at the option of the unitholders any time after December 1, 2018 or, (ii) in whole or in part at Dominion Energy Midstream’s option, subject to certain conditions, any time after December 1, 2019. Immediately prior to the closing of Dominion Energy’s acquisition of the outstanding interest in Dominion Energy Midstream noted above, each convertible preferred unit was converted into common units representing limited partner interests in Dominion Energy Midstream in accordance with the terms of Dominion Energy Midstream’s partnership agreement.

In May 2018, all of the subordinated units of Dominion Energy Midstream held by Dominion Energy were converted into common units on a 1:1 ratio following the payment of Dominion Energy Midstream’s distribution for the first quarter of 2018. In June 2018, Dominion Energy, as general partner, exercised an incentive distribution right reset as defined in Dominion Energy Midstream’s partnership agreement and received 26.7 million common units representing limited partner interests in Dominion Energy Midstream. As a result of the increase in its ownership interest in Dominion Energy Midstream, Dominion Energy recorded a decrease in noncontrolling interest, and a correspond-

ing increase in shareholders’ equity, of $375 million reflecting the change in the carrying value of the interest in the net assets of Dominion Energy Midstream held by others.

Accumulated Other Comprehensive Income (Loss)

Presented in the table below is a summary of AOCI by component:

At December 31,	2018			2017
(millions)
Dominion Energy
Net deferred losses on derivatives-hedging activities, net of $79 and $188 tax	$	(234	)	$	(301	)
Net unrealized gains on nuclear decommissioning trust funds, net of $— and $(419) tax		2			747
Net unrecognized pension and other postretirement benefit costs, net of $519 and $692 tax		(1,465	)		(1,101	)
Other comprehensive loss from equity method investees, net of $— and $2 tax		(2	)		(3	)
Total AOCI, including noncontrolling interest	$	(1,699	)	$	(658	)
Less other comprehensive income attributable to noncontrolling interest		1			1
Total AOCI, excluding noncontrolling interest	$	(1,700	)	$	(659	)
Virginia Power
Net deferred losses on derivatives-hedging activities, net of $4 and $8 tax	$	(13	)	$	(12	)
Net unrealized gains on nuclear decommissioning trust funds, net of $— and $(47) tax		1			74
Total AOCI	$	(12	)	$	62
Dominion Energy Gas
Net deferred losses on derivatives-hedging activities, net of $8 and $15 tax	$	(25	)	$	(23	)
Net unrecognized pension costs, net of $56 and $59 tax		(144	)		(75	)
Total AOCI	$	(169	)	$	(98	)

162

DOMINION ENERGY

The following table presents Dominion Energy’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 loss from equity method investees			Total
(millions)
Year Ended December 31, 2018
Beginning balance		$(302	)		$ 747			$(1,101	)		$(3	)		$(659	)
Other comprehensive income before reclassifications: gains (losses)		30			(18	)		(215	)		1			(202	)
Amounts reclassified from AOCI: (gains) losses(1)		102			5			78			—			185
Net current period other comprehensive income (loss)		132			(13)			(137	)		1			(17	)
Cumulative-effect of changes in accounting principle		(64	)		(732)			(227	)		—			(1,023	)
Less other comprehensive income (loss) attributable to noncontrolling interest		1			—			—			—			1
Ending balance		$(235	)		$2			$(1,465	)		$(2	)		$(1,700	)
Year Ended December 31, 2017
Beginning balance		$(280	)		$ 569			$(1,082	)		$(6	)		$  (799	)
Other comprehensive income before reclassifications: gains (losses)		8			215			(69	)		3			157
Amounts reclassified from AOCI: (gains) losses(1)		(29	)		(37	)		50			—			(16	)
Net current period other comprehensive income (loss)		(21	)		178			(19	)		3			141
Less other comprehensive income (loss) attributable to noncontrolling interest		1			—			—			—			1
Ending balance		$(302	)		$ 747			$(1,101	)		$(3	)		$  (659	)

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

The following table presents Dominion Energy’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)
Year Ended December 31, 2018
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$90			Operating revenue
		(14	)		Electric fuel and other energy-related purchases
Interest rate contracts		48			Interest and related charges
Foreign currency contracts		13			Other Income
Total		137
Tax		(35	)		Income tax expense
Total, net of tax		$102
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities		$7			Other income
Total		7
Tax		(2	)		Income tax expense
Total, net of tax		$5
Unrecognized pension and other postretirement benefit costs:
Amortization of prior-service costs (credits)		$(21	)		Other income
Amortization of actuarial losses		120			Other income
Total		99
Tax		(21	)		Income tax expense
Total, net of tax		$78
Year Ended December 31, 2017
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$(81	)		Operating revenue
		2			Purchased gas
Interest rate contracts		52			Interest and related charges
Foreign currency contracts		(20	)		Other Income
Total		(47	)
Tax		18			Income tax expense
Total, net of tax		$(29	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities		$(81	)		Other income
Impairment		23			Other income
Total		(58	)
Tax		21			Income tax expense
Total, net of tax		$(37	)
Unrecognized pension and other postretirement benefit costs:
Prior-service costs (credits)		$(21	)		Other income
Actuarial losses		103			Other income
Total		82
Tax		(32	)		Income tax expense
Total, net of tax		$50

163

Combined Notes to Consolidated Financial Statements, Continued

VIRGINIA POWER

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

	Deferred gains and losses on derivatives- hedging activities			Unrealized gains and losses on investment securities			Total
(millions)
Year Ended December 31, 2018
Beginning balance	$	(12)		$	74			$ 62
Other comprehensive income before reclassifications: gains (losses)		1			—			1
Amounts reclassified from AOCI: (gains) losses(1)		1			—			1
Net current period other comprehensive income (loss)		2			—			2
Cumulative-effect of changes in accounting principle		(3	)		(73	)		(76	)
Ending balance	$	(13	)	$	1			$(12	)
Year Ended December 31, 2017
Beginning balance	$	(8	)	$	54			$ 46
Other comprehensive income before reclassifications: gains (losses)		(5	)		24			19
Amounts reclassified from AOCI: gains (losses)(1)		1			(4	)		(3	)
Net current period other comprehensive income (loss)		(4	)		20			16
Ending balance	$	(12	)	$	74			$ 62

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

The following table presents Virginia Power’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)
Year Ended December 31, 2018
(Gains) losses on cash flow hedges:
Interest rate contracts		$ 1			Interest and related charges
Total		1
Tax		—			Income tax expense
Total, net of tax		$ 1
Year Ended December 31, 2017
(Gains) losses on cash flow hedges:
Interest rate contracts		$ 1			Interest and related charges
Total		1
Tax		—			Income tax expense
Total, net of tax		$ 1
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities		$(9	)		Other income
Impairment		2			Other income
Total		(7	)
Tax		3			Income tax expense
Total, net of tax		$(4	)

DOMINION ENERGY GAS

The following table presents Dominion Energy 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)
Year Ended December 31, 2018
Beginning balance		$(23	)		$  (75	)	$	(98	)
Other comprehensive income before reclassifications: gains (losses)		(17	)		(52	)		(69	)
Amounts reclassified from AOCI: (gains) losses(1)		20			4			24
Net current period other comprehensive income (loss)		3			(48	)		(45	)
Cumulative-effect of changes in accounting principle		(5	)		(21	)		(26	)
Ending balance		$(25	)		$(144	)	$	(169	)
Year Ended December 31, 2017
Beginning balance		$(24	)		$  (99	)	$	(123	)
Other comprehensive income before reclassifications: gains (losses)		5			20			25
Amounts reclassified from AOCI: gains (losses)(1)		(4	)		4			—
Net current period other comprehensive income (loss)		1			24			25
Ending balance		$(23	)		$  (75	)	$	(98	)

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

164

The following table presents Dominion Energy 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)
Year Ended December 31, 2018
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$   8		Operating revenue
Interest rate contracts		6		Interest and related charges
Foreign currency contracts		13		Other income
Total		27
Tax		(7	)	Income tax expense
Total, net of tax		$ 20
Unrecognized pension costs:
Actuarial losses		$   6		Other income
Total		6
Tax		(2	)	Income tax expense
Total, net of tax		$   4
Year Ended December 31, 2017
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$   8		Operating revenue
Interest rate contracts		5		Interest and related charges
Foreign currency contracts		(20	)	Other income
Total		(7	)
Tax		3		Income tax expense
Total, net of tax		$  (4	)
Unrecognized pension costs:
Actuarial losses		$   6		Other income
Total		6
Tax		(2	)	Income tax expense
Total, net of tax		$   4

Stock-Based Awards

The 2005 and 2014 Incentive Compensation Plans permit stock-based awards that include restricted stock, performance grants, goal-based stock, stock options, and stock appreciation rights. The Non-Employee Directors Compensation Plan permits grants of restricted stock and stock options. Under provisions of these plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the CGN Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. No options are outstanding under either plan. At December 31, 2018, approximately 22 million shares were available for future grants under these plans.

Goal-based stock awards are granted in lieu of cash-based performance grants to certain officers who have not achieved a certain targeted level of share ownership. As of December 31, 2018, unrecognized compensation cost related to nonvested goal-based stock awards was immaterial.

Dominion Energy measures and recognizes compensation expense relating to share-based payment transactions over the

vesting period based on the fair value of the equity or liability instruments issued. Dominion Energy’s results for the years ended December 31, 2018, 2017 and 2016 include $48 million, $45 million, and $33 million, respectively, of compensation costs and $12 million, $16 million, and $11 million, respectively of income tax benefits related to Dominion Energy’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income. Excess Tax Benefits are classified as a financing cash flow.

RESTRICTED STOCK

Restricted stock grants are made to officers under Dominion Energy’s LTIP and may also be granted to certain key non-officer employees. The fair value of Dominion Energy’s restricted stock awards is equal to the closing price of Dominion Energy’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2018, 2017 and 2016:

	Shares			Weighted —average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2015		855			$66.16
Granted		372			71.67
Vested		(301	)		56.83
Cancelled and forfeited		(40	)		71.75
Nonvested at December 31, 2016		886			$71.40
Granted		454			74.24
Vested		(287	)		68.90
Cancelled and forfeited		(10	)		72.37
Nonvested at December 31, 2017		1,043			$73.32
Granted		534			72.92
Vested		(316	)		73.59
Cancelled and forfeited		(53	)		74.25
Nonvested at December 31, 2018		1,208			$73.03

As of December 31, 2018, unrecognized compensation cost related to nonvested restricted stock awards totaled $49 million and is expected to be recognized over a weighted-average period of 2.1 years. The fair value of restricted stock awards that vested was $23 million, $21 million, and $21 million in 2018, 2017 and 2016, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion Energy stock and the applicable federal, state and local tax withholding rates.

CASH-BASED PERFORMANCE GRANTS

Cash-based performance grants are made to Dominion Energy’s officers under Dominion Energy’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.

In February 2016, a cash-based performance grant was made to officers. Payout of the performance grant occurred in January 2018 based on the achievement of two performance metrics during 2016 and 2017: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The total of the payout under the grant was $12 million.

165

Combined Notes to Consolidated Financial Statements, Continued

In February 2017, two cash-based performance grants were made to officers as Dominion Energy transitioned from a two-year performance period to a three-year performance period. Payout of the two-year grant occurred in January 2019 based on the achievement of two performance metrics during 2017 and 2018: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC with an additional partial payout based on Dominion Energy’s price-earnings ratio relative to that of the members of Dominion Energy’s compensation peer group. The total of the payout under the two-year grant was $13 million and a liability of $13 million had been accrued for this award. Payout of the three-year cash-based performance grant is expected to occur by March 15, 2020 based on the achievement of two performance metrics during 2017, 2018 and 2019: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There are additional opportunities to earn a portion of the awards based on Dominion Energy’s absolute TSR or relative price-earnings ratio performance. At December 31, 2018, the targeted amount of the three-year grant was $14 million and a liability of $10 million had been accrued for the award.

In February 2018, a cash-based performance grant was made to officers. Payout of the three-year cash-based performance grant is expected to occur by March 15, 2021 based on the achievement of two performance metrics during 2018, 2019 and 2020: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There are additional opportunities to earn a portion of the awards based on Dominion Energy’s absolute TSR or relative price-earnings ratio performance. At December 31, 2018, the targeted amount of the three-year grant was $16 million and a liability of $5 million had been accrued for this award.

NOTE 20. DIVIDEND RESTRICTIONS

The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2018, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

The North Carolina Commission, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by Virginia Power and PSNC to (i) the amount of retained earnings at closing of the SCANA Combination plus (ii) any future earnings recorded by Virginia Power and PSNC after such date. In addition, notice to the North Carolina Commission is required if payment of dividends causes the equity component of Virginia Power and PSNC’s capital structure to fall below 45%.

The Ohio Commission may prohibit any public service company, including East Ohio, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2018, the Ohio Commission had not restricted the payment of dividends by East Ohio.

Pursuant to the SCANA Merger Approval Order, the amount of any SCE&G dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry. There is no specific restriction on the payment of dividends by SCE&G.

The Utah Commission may prohibit any public service company, including Questar Gas, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2018, the Utah Commission had not restricted the payment of dividends by Questar Gas.

Certain agreements associated with the Companies’ credit facility contains restrictions on the ratio of debt to total capitalization. These limitations did not restrict the Companies’ ability to pay dividends or receive dividends from their subsidiaries at December 31, 2018.

In connection with the SCANA Combination, under the terms of the merger agreement, Dominion Energy could not declare, set aside or pay any dividends on, or make any other distributions (whether in cash, stock or property) in respect of, any of its capital stock, other than regular quarterly cash dividends from January 2018 through January 2019.

As part of the merger agreement with Dominion Energy Midstream from November 2018 through January 2019, Dominion Energy could not declare, set aside or pay any dividends on, or make any other distributions (whether in cash, stock or property) in respect of, any of its capital stock, other than regular quarterly cash dividends.

See Note 17 for a description of potential restrictions on dividend payments by Dominion Energy in connection with the deferral of interest payments on certain junior subordinated notes and equity units, initially in the form of corporate units.

NOTE 21. EMPLOYEE BENEFIT PLANS

Dominion Energy and Dominion Energy Gas—Defined Benefit Plans

Dominion Energy provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Dominion Energy Gas participates in a number of the Dominion Energy-sponsored retirement plans. Under the terms of its benefit plans, Dominion Energy reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Dominion Energy maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the employee’s compensation. Dominion Energy’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension programs also provide benefits to certain retired executives under company-sponsored nonqualified employee benefit plans. The nonqualified plans are funded through contributions to grantor trusts. Dominion Energy also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service.

Pension benefits for Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Pension Plan, a defined benefit pension plan sponsored by Dominion Energy that provides benefits to multiple Dominion Energy subsidiaries. Pension benefits for Dominion Energy Gas employees represented by collective bargaining units are covered by separate pension plans for East Ohio and, for DETI, a plan that provides benefits to employees of both DETI and Hope. Employee compensation is the basis for allocating

166

pension costs and obligations between DETI and Hope and determining East Ohio’s share of total pension costs.

Retiree healthcare and life insurance benefits for Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Retiree Health and Welfare Plan, a plan sponsored by Dominion Energy that provides certain retiree healthcare and life insurance benefits to multiple Dominion Energy subsidiaries. Retiree healthcare and life insurance benefits for Dominion Energy Gas employees represented by collective bargaining units are covered by separate other postretirement benefit plans for East Ohio and, for DETI, a plan that provides benefits to both DETI and Hope. Employee headcount is the basis for allocating other postretirement benefit costs and obligations between DETI and Hope and determining East Ohio’s share of total other postretirement benefit costs.

Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates, mortality rates and the rate of compensation increases.

Dominion Energy uses December 31 as the measurement date for all of its employee benefit plans, including those in which Dominion Energy Gas participates. Dominion Energy uses the market-related value of pension plan assets to determine the expected return on plan assets, a component of net periodic pension cost, for all pension plans, including those in which Dominion Energy Gas participates. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized.

Dominion Energy’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $(605) million and $1.6 billion in 2018 and 2017, respectively, versus expected returns of $806 million and $767 million, respectively. Dominion Energy Gas’ pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual returns (losses) of $(129) million and $335 million in 2018 and 2017, respectively, versus expected returns of $178 million and $165 million, respectively. 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 such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

During 2016, Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units) engaged their actuary to conduct an experience study of their employees demographics over a five-year period as compared to significant assumptions that were being used to determine pension and other

postretirement benefit obligations and periodic costs. These assumptions primarily included mortality, retirement rates, termination rates, and salary increase rates. The changes in assumptions implemented as a result of the experience study resulted in increases of $290 million and $38 million in the pension and other postretirement benefits obligations, respectively, at December 31, 2016 for Dominion Energy and $24 million and $9 million in the pension and other postretirement benefits obligations, respectively, at December 31, 2016 for Dominion Energy Gas. In addition, these changes increased net periodic benefit costs $42 million for Dominion Energy during 2017. The increase in net periodic benefit costs for Dominion Energy Gas during 2017 was immaterial.

PLAN AMENDMENTS AND REMEASUREMENTS

In the fourth quarter of 2017, Dominion Energy remeasured its pension and other postretirement benefit plans as a result of voluntary and involuntary separation programs at Dominion Energy Questar. The settlement and related remeasurement resulted in a reduction in the pension benefit obligation of approximately $75 million and an increase in the accumulated postretirement benefit obligation of approximately $2 million. The discount rates used for the 2017 pension cost and related settlement were 4.46% as of December 31, 2016, 4.51% as of January 31, 2017 and 4.05% as of June 30 and September 30, 2017. All other assumptions used were consistent with the measurement as of December 31, 2016.

In the first quarter of 2017, Dominion Energy and Dominion Energy Gas remeasured an other postretirement benefit plan as a result of an amendment that changed post-65 retiree medical coverage for certain current and future Local 69 retirees effective July 1, 2017. The remeasurement resulted in a decrease in Dominion Energy and Dominion Energy Gas’ accumulated postretirement benefit obligation of $73 million and $61 million, respectively. As a result of regulatory accounting, the remeasurement had an immaterial impact on net income for both Dominion Energy and Dominion Energy Gas. The discount rate used for the remeasurement was 4.30%. All other assumptions used were consistent with the measurement as of December 31, 2016.

Also during the first quarter of 2017, Dominion Energy recorded a $7 million ($4 million after-tax) charge, including $6 million ($4 million after-tax) at Dominion Energy Gas, as a result of additional payments associated with the new collective bargaining agreement, which is reflected in other operations and maintenance expense in their Consolidated Statements of Income.

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

167

Combined Notes to Consolidated Financial Statements, Continued

FUNDED STATUS

The following table summarizes the changes in pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units):

	Pension Benefits						Other Postretirement Benefits
Year Ended December 31,	2018			2017			2018			2017
(millions, except percentages)
Dominion Energy
Changes in benefit obligation:
Benefit obligation at beginning of year	$	9,052		$	8,132		$	1,529		$	1,478
Service cost		157			138			27			26
Interest cost		337			345			56			60
Benefits paid		(358	)		(323	)		(87	)		(83	)
Actuarial (gains) losses during the year		(688	)		830			(158	)		119
Plan amendments(1)		—			5			(4	)		(73	)
Settlements and curtailments(2)		—			(75	)		—			2
Benefit obligation at end of year	$	8,500		$	9,052		$	1,363		$	1,529
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	8,062		$	7,016		$	1,729		$	1,512
Actual return (loss) on plan assets		(513	)		1,327			(92	)		236
Employer contributions		6			118			12			13
Benefits paid		(358	)		(323	)		(68	)		(32	)
Settlements(2)		—			(76	)		—			—
Fair value of plan assets at end of year	$	7,197		$	8,062		$	1,581		$	1,729
Funded status at end of year	$	(1,303	)	$	(990	)	$	218		$	200
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	$	1,003		$	1,117		$	276		$	261
Other current liabilities		(34	)		(8	)		(2	)		—
Noncurrent pension and other postretirement benefit liabilities		(2,272	)		(2,099	)		(56	)		(61	)
Net amount recognized	$	(1,303	)	$	(990	)	$	218		$	200
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate		4.42%–4.43%			3.80%–3.81%			4.37%–4.38%			3.76%
Weighted average rate of increase for compensation		4.32%			4.09%			4.30%-4.55%			3.95%-4.11%
Dominion Energy Gas
Changes in benefit obligation:
Benefit obligation at beginning of year	$	773		$	683		$	290		$	320
Service cost		18			15			4			4
Interest cost		29			30			11			12
Benefits paid		(34	)		(33	)		(18	)		(19	)
Actuarial (gains) losses during the year		(56	)		78			(27	)		34
Plan amendments(1)		—			—			(4	)		(61	)
Benefit obligation at end of year	$	730		$	773		$	256		$	290
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	1,803		$	1,542		$	333		$	299
Actual return (loss) on plan assets		(113	)		294			(16	)		41
Employer contributions		—			—			12			12
Benefits paid		(34	)		(33	)		(18	)		(19	)
Fair value of plan assets at end of year	$	1,656		$	1,803		$	311		$	333
Funded status at end of year	$	926		$	1,030		$	55		$	43
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	$	926		$	1,030		$	63		$	57
Noncurrent pension and other postretirement benefit liabilities(3)		—			—			(8	)		(14	)
Net amount recognized	$	926		$	1,030		$	55		$	43
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate		4.42	%		3.81	%		4.37	%		3.76	%
Weighted average rate of increase for compensation		4.55	%		4.11	%		n/a			n/a

(1) 2017 amounts relate primarily to a plan amendment that changed post-65 retiree medical coverage for certain current and future Local 69 retirees effective July 1, 2017.

(2) 2017 amount relates primarily to settlement and curtailment as a result of the voluntary and involuntary separation programs at Dominion Energy Questar.

(3) Reflected in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.

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The ABO for all of Dominion Energy’s defined benefit pension plans was $7.8 billion and $8.2 billion at December 31, 2018 and 2017, respectively. The ABO for the defined benefit pension plans covering Dominion Energy Gas employees represented by collective bargaining units was $689 million and $724 million at December 31, 2018 and 2017, respectively.

Under its funding policies, Dominion Energy evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion Energy determines the amount of contributions for the current year, if any, at that time. During 2018, Dominion Energy and Dominion Energy Gas made no contributions to the qualified defined benefit pension plans. Dominion Energy expects to make $21 million of the minimum required contributions in 2019, and no contributions are currently expected in 2019 for Dominion Energy Gas.

Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion Energy’s subsidiaries, including Dominion Energy Gas, fund other postretirement benefit costs through VEBAs. Dominion Energy’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion Energy’s contributions to VEBAs, all of which pertained to Dominion Energy Gas employees, totaled $12 million for both 2018 and 2017, and Dominion Energy expects to contribute approximately $12 million to the Dominion Energy VEBAs in 2019, all of which pertains to Dominion Energy Gas employees.

Dominion Energy and Dominion Energy Gas do not expect any pension or other postretirement plan assets to be returned during 2019.

The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units):

	Pension Benefits				Other Postretirement Benefits
As of December 31,	2018		2017		2018		2017
(millions)
Dominion Energy
Benefit obligation	$	7,705	$	8,209		$164		$191
Fair value of plan assets		5,398		6,103		136		156
Dominion Energy Gas
Benefit obligation	$	—	$	—		$134		$157
Fair value of plan assets		—		—		126		143

The following table provides information on the ABO and fair value of plan assets for Dominion Energy’s pension plans with an ABO in excess of plan assets:

As of December 31,	2018		2017
(millions)
Accumulated benefit obligation	$	7,056	$	7,392
Fair value of plan assets		5,398		6,103

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans:

	Estimated Future Benefit Payments
	Pension Benefits		Other Postretirement Benefits
(millions)
Dominion Energy
2019		$407		$98
2020		405		99
2021		426		99
2022		442		99
2023		465		98
2024-2028	2,548		461
Dominion Energy Gas
2019		$37		$19
2020		39		19
2021		40		19
2022		42		19
2023		43		19
2024-2028		223		90

PLAN ASSETS

Dominion Energy’s overall objective for investing its pension and other postretirement plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. As a participating employer in various pension plans sponsored by Dominion Energy, Dominion Energy Gas is subject to Dominion Energy’s investment policies for such plans. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for Dominion Energy’s pension funds are 28% U.S. equity, 18% non-U.S. equity, 35% fixed income, 3% real estate and 16% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the U.S. Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the U.S. including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity real estate investment trusts and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.

Dominion Energy also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies.

Strategic investment policies are established for Dominion Energy’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from

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Combined Notes to Consolidated Financial Statements, Continued

the plans’ strategic allocation are a function of Dominion Energy’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to fur-

ther reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.

For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6.

The fair values of Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) pension plan assets by asset category are as follows:

At December 31,	2018								2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Dominion Energy
Cash and cash equivalents	$	17	$	1		$—	$	18	$	18	$	—		$—	$	18
Common and preferred stocks:
U.S.		1,645		—		—		1,645		1,902		—		—		1,902
International		1,061		—		—		1,061		1,151		—		—		1,151
Insurance contracts		—		318		—		318		—		352		—		352
Corporate debt instruments		23		729		—		752		41		729		—		770
Government securities		25		605		—		630		9		676		—		685
Total recorded at fair value	$	2,771	$	1,653		$—	$	4,424	$	3,121	$	1,757		$—	$	4,878
Assets recorded at NAV(1):
Common/collective trust funds								1,849								2,272
Alternative investments:
Real estate funds								108								111
Private equity funds								633								606
Debt funds								155								161
Hedge funds								17								19
Total recorded at NAV							$	2,762							$	3,169
Total investments(2)							$	7,186							$	8,047
Dominion Energy Gas
Cash and cash equivalents	$	4	$	—		$—	$	4	$	4	$	—		$—	$	4
Common and preferred stocks:
U.S.		378		—		—		378		425		—		—		425
International		244		—		—		244		257		—		—		257
Insurance contracts		—		73		—		73		—		79		—		79
Corporate debt instruments		5		168		—		173		9		163		—		172
Government securities		6		139		—		145		2		151		—		153
Total recorded at fair value	$	637	$	380		$—	$	1,017	$	697	$	393		$—	$	1,090
Assets recorded at NAV(1):
Common/collective trust funds								425								509
Alternative investments:
Real estate funds								25								25
Private equity funds								146								135
Debt funds								36								36
Hedge funds								4								4
Total recorded at NAV							$	636							$	709
Total investments(3)							$	1,653							$	1,799

(1) These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

(2) Excludes net assets related to pending sales of securities of $12 million, net accrued income of $21 million, and includes net assets related to pending purchases of securities of $22 million at December 31, 2018. Excludes net assets related to pending sales of securities of $11 million, net accrued income of $19 million, and includes net assets related to pending purchases of securities of $15 million at December 31, 2017.

(3) Excludes net assets related to pending sales of securities of $3 million, net accrued income of $5 million, and includes net assets related to pending purchases of securities of $5 million at December 31, 2018. Excludes net assets related to pending sales of securities of $3 million, net accrued income of $4 million, and includes net assets related to pending purchases of securities of $3 million at December 31, 2017.

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The fair values of Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) other postretirement plan assets by asset category are as follows:

At December 31,	2018								2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Dominion Energy
Cash and cash equivalents		$1		$1		$—	$	2		$1		$2		$—		$3
Common and preferred stocks:
U.S.		554		—		—		554		636		—		—		636
International		170		—		—		170		196		—		—		196
Insurance contracts		—		19		—		19		—		21		—		21
Corporate debt instruments		1		44		—		45		2		44		—		46
Government securities		2		37		—		39		1		41		—		42
Total recorded at fair value		$728		$101		$—	$	829		$836		$108		$—		$944
Assets recorded at NAV(1):
Common/collective trust funds								650								689
Alternative investments:
Real estate funds								10								9
Private equity funds								80								73
Debt funds								10								11
Hedge funds								1								1
Total recorded at NAV							$	751								$783
Total investments(2)							$	1,580								$1,727
Dominion Energy Gas
Common and preferred stocks:
U.S.		$113		$—		$—	$	113		$130		$—		$—		$130
International		30		—		—		30		33		—		—		33
Total recorded at fair value		$143		$—		$—	$	143		$163		$—		$—		$163
Assets recorded at NAV(1):
Common/collective trust funds								148								154
Alternative investments:
Real estate funds								2								1
Private equity funds								18								15
Debt funds								—								—
Total recorded at NAV							$	168								$170
Total investments							$	311								$333

(1) These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

(2) Excludes net assets related to pending sales of securities of $1 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $2 million at December 31, 2018. Excludes net assets related to pending sales of securities of $1 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $1 million at December 31, 2017.

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Combined Notes to Consolidated Financial Statements, Continued

The Plan’s investments are determined based on the fair values of the investments and the underlying investments, which have been determined as follows:

• Cash and Cash Equivalents—Investments are held primarily in short-term notes and treasury bills, which are valued at cost plus accrued interest.

• Common and Preferred Stocks—Investments are valued at the closing price reported on the active market on which the individual securities are traded.

• Insurance Contracts—Investments in Group Annuity Contracts with John Hancock were entered into after 1992 and are stated at fair value based on the fair value of the underlying securities as provided by the managers and include investments in U.S. government securities, corporate debt instruments, state and municipal debt securities.

• Corporate Debt Instruments—Investments are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar instruments, the instrument is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks or a broker quote, if available.

• Government Securities—Investments are valued using pricing models maximizing the use of observable inputs for similar securities.

• Common/Collective Trust Funds—Common/collective trust funds invest in debt and equity securities and other instruments with characteristics similar to those of the funds’ benchmarks. The primary objectives of the funds are to seek investment returns that approximate the overall performance of their benchmark indexes. These benchmarks are major equity indices, fixed income indices, and money market indices that focus on growth, income, and liquidity strategies, as applicable. Investments in common/collective trust funds are stated at the NAV as determined by the issuer of the common/collective trust funds and are based on the fair value of the underlying investments held by the fund less its liabilities. The NAV is used as a practical expedient to estimate fair value. The common/collective trust funds do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held. The majority of the common/collective trust funds have limited withdrawal or redemption rights during the term of the investment.

• Alternative Investments—Investments in real estate funds, private equity funds, debt funds and hedge funds are stated at fair value based on the NAV of the Plan’s proportionate share of the partnership, joint venture or other alternative investment’s fair value as determined by reference to audited financial statements or NAV statements provided by the investment manager. The NAV is used as a practical expedient to estimate fair value.

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NET PERIODIC BENEFIT (CREDIT) COST

The service cost component and non-service cost components of net periodic benefit (credit) cost are reflected in other operations and maintenance expense and other income, respectively, in the Consolidated Statements of Income. The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans are as follows:

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2018			2017			2016			2018			2017			2016
(millions, except percentages)
Dominion Energy
Service cost	$	157		$	138		$	118		$	27		$	26		$	31
Interest cost		337			345			317			56			60			65
Expected return on plan assets		(663	)		(639	)		(573	)		(143	)		(128	)		(118	)
Amortization of prior service (credit) cost		1			1			1			(52	)		(51	)		(35	)
Amortization of net actuarial loss		193			162			111			11			13			8
Settlements and curtailments		—			—			1			—			—			—
Net periodic benefit (credit) cost	$	25		$	7		$	(25	)	$	(101	)	$	(80	)	$	(49	)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	490		$	142		$	931		$	78		$	12		$	178
Prior service (credit) cost		—			5			—			(4	)		(73	)		(216	)
Settlements and curtailments		—			1			(1	)		—			2			—
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss		(193	)		(162	)		(111	)		(11	)		(13	)		(8	)
Amortization of prior service credit (cost)		(1	)		(1	)		(1	)		52			51			35
Total recognized in other comprehensive income and regulatory assets and liabilities	$	296		$	(15	)	$	818		$	115		$	(21	)	$	(11	)
Significant assumptions used to determine periodic cost:
Discount rate		3.80%-3.8	1%		3.31%-4.5	0%		2.87%-4.9	9%		3.76%			3.92%-4.4	7%		3.56%-4.9	4%
Expected long-term rate of return on plan assets		8.75	%		8.75	%		8.75	%		8.50	%		8.50	%		8.50	%
Weighted average rate of increase for compensation		4.09	%		4.09	%		4.22	%		3.95%-4.1	1%		3.29	%		4.22	%
Healthcare cost trend rate(1)											7.00	%		7.00	%		7.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(1)											5.00	%		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate(1)(2)											2022			2021			2020
Dominion Energy Gas
Service cost	$	18		$	15		$	13		$	4		$	4		$	5
Interest cost		29			30			30			11			12			14
Expected return on plan assets		(150	)		(141	)		(134	)		(28	)		(24	)		(23	)
Amortization of prior service (credit) cost		—			—			—			(4	)		(3	)		1
Amortization of net actuarial loss		19			16			13			3			2			1
Net periodic benefit (credit) cost	$	(84	)	$	(80	)	$	(78	)	$	(14	)	$	(9	)	$	(2	)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	207		$	(75	)	$	91		$	16		$	18		$	28
Prior service cost		—			—			—			(4	)		(61	)		—
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss		(19	)		(16	)		(13	)		(3	)		(2	)		(1	)
Amortization of prior service credit (cost)		—			—			—			4			3			(1	)
Total recognized in other comprehensive income and regulatory assets and liabilities	$	188		$	(91	)	$	78		$	13		$	(42	)	$	26
Significant assumptions used to determine periodic cost:
Discount rate		3.81	%		4.50	%		4.99	%		3.81	%		4.47	%		4.93	%
Expected long-term rate of return on plan assets		8.75	%		8.75	%		8.75	%		8.50	%		8.50	%		8.50	%
Weighted average rate of increase for compensation		4.11	%		4.11	%		3.93	%		4.55	%		4.11	%		3.93	%
Healthcare cost trend rate(1)											7.00	%		7.00	%		7.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(1)											5.00	%		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate(1)											2022			2021			2020

(1) Assumptions used to determine net periodic cost for the following year.

(2) The Society of Actuaries model used to determine healthcare cost trend rates was updated in 2014. The new model converges to the ultimate trend rate much more quickly than previous models.

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Combined Notes to Consolidated Financial Statements, Continued

The components of AOCI and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans that have not been recognized as components of net periodic benefit (credit) cost are as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2018		2017		2018			2017
(millions)
Dominion Energy
Net actuarial loss	$	3,477	$	3,181	$	350		$	283
Prior service (credit) cost		7		8		(393	)		(440	)
Total(1)	$	3,484	$	3,189	$	(43	)	$	(157	)
Dominion Energy Gas
Net actuarial loss	$	555	$	367	$	89		$	76
Prior service (credit) cost		—		—		(52	)		(52	)
Total(2)	$	555	$	367	$	37		$	24

(1) As of December 31, 2018, of the $3.5 billion and $(43) million related to pension benefits and other postretirement benefits, $2.0 billion and $(41) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2017, of the $3.2 billion and $(157) million related to pension benefits and other postretirement benefits, $1.9 billion and $(87) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.

(2) As of December 31, 2018, of the $555 million related to pension benefits, $200 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $37 million related to other postretirement benefits is included entirely in regulatory assets and liabilities. As of December 31, 2017, of the $367 million related to pension benefits, $134 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $24 million related to other postretirement benefits is included entirely in regulatory assets and liabilities.

The following table provides the components of AOCI and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans as of December 31, 2018 that are expected to be amortized as components of net periodic benefit (credit) cost in 2019:

	Pension Benefits		Other Postretirement Benefits
(millions)
Dominion Energy
Net actuarial loss		$155	$	18
Prior service (credit) cost		1		(52)
Dominion Energy Gas
Net actuarial loss		$  19	$	4
Prior service (credit) cost		—		(4	)

The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality are critical assumptions in determining net periodic benefit (credit) cost. Dominion Energy develops non-investment related assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions used for Dominion Energy’s pension and other postretirement plans, including those in which Dominion Energy Gas participates, including discount rates, expected long-term rates of return, healthcare cost trend rates and mortality rates.

Dominion Energy determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans, including those in which Dominion Energy Gas participates, by using a combination of:

• Expected inflation and risk-free interest rate assumptions;

• Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;

• Expected future risk premiums, asset classes’ volatilities and correlations;

• Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and

• Investment allocation of plan assets.

Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans, including those in which Dominion Energy Gas participates.

Mortality rates are developed from actual and projected plan experience for postretirement benefit plans. Dominion Energy’s actuary conducts an experience study periodically as part of the process to select its best estimate of mortality. Dominion Energy considers both standard mortality tables and improvement factors as well as the plans’ actual experience when selecting a best estimate. During 2016, Dominion Energy conducted a new experience study as scheduled and, as a result, updated its mortality assumptions for all its plans, including those in which Dominion Energy Gas participates.

Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion Energy’s retiree healthcare plans, including those in which Dominion Energy Gas participates. A one percentage point change in assumed healthcare cost trend rates would have had the following effects for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) other postretirement benefit plans:

	Other Postretirement Benefits
	One percentage point increase		One percentage point decrease
(millions)
Dominion Energy
Effect on net periodic cost for 2019		$  20		$  (16)
Effect on other postretirement benefit obligation at December 31, 2018		130		(110)
Dominion Energy Gas
Effect on net periodic cost for 2019		$    4		$    (3)
Effect on other postretirement benefit obligation at December 31, 2018		25		(22)

Dominion Energy Gas (Employees Not Represented by Collective Bargaining Units) and Virginia Power—Participation in Defined Benefit Plans

Virginia Power employees and Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Pension Plan described above. As participating employers, Virginia Power and Dominion Energy Gas are subject to Dominion Energy’s funding policy, which is to contribute annually an amount that is in accordance with ERISA. During 2018, Virginia Power and Dominion Energy Gas made no con-

174

tributions to the Dominion Energy Pension Plan, and no contributions to this plan are currently expected in 2019. Virginia Power’s net periodic pension cost related to this plan was $126 million, $110 million and $79 million in 2018, 2017 and 2016, respectively. Dominion Energy Gas’ net periodic pension credit related to this plan was $(38) million, $(37) million and $(45) million in 2018, 2017 and 2016, respectively. Net periodic pension (credit) cost is reflected in other operations and maintenance expense in their respective Consolidated Statements of Income. The funded status of various Dominion Energy subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating Dominion Energy subsidiaries. See Note 24 for Virginia Power and Dominion Energy Gas amounts due to/from Dominion Energy related to this plan.

Retiree healthcare and life insurance benefits, for Virginia Power employees and for Dominion Energy Gas employees not represented by collective bargaining units, are covered by the Dominion Energy Retiree Health and Welfare Plan described above. Virginia Power’s net periodic benefit (credit) cost related to this plan was $(51) million, $(42) million and $(29) million in 2018, 2017 and 2016, respectively. Dominion Energy Gas’ net periodic benefit (credit) cost related to this plan was $(7) million, $(5) million and $(4) million for 2018, 2017 and 2016, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expenses in their respective Consolidated Statements of Income. Employee headcount is the basis for determining the share of total other postretirement benefit costs for participating Dominion Energy subsidiaries. See Note 24 for Virginia Power and Dominion Energy Gas amounts due to/from Dominion Energy related to this plan.

Dominion Energy holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power and Dominion Energy Gas’ employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power and Dominion Energy Gas will provide to Dominion Energy for their shares of employee benefit plan contributions.

Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, Virginia Power and Dominion Energy Gas fund other postretirement benefit costs through VEBAs. During 2018 and 2017, Virginia Power made no contributions to the VEBA and does not expect to contribute to the VEBA in 2019. Dominion Energy Gas made no contributions to the VEBAs for employees not represented by collective bargaining units during 2018 and 2017 and does not expect to contribute in 2019.

Defined Contribution Plans

Dominion Energy also sponsors defined contribution employee savings plans that cover substantially all employees. During 2018, 2017 and 2016, Dominion Energy recognized $51 million, $45 million and $44 million, respectively, as employer matching contributions to these plans. Dominion Energy Gas participates in these employee savings plans, both specific to Dominion

Energy Gas and that cover multiple Dominion Energy subsidiaries. During 2018, 2017 and 2016, Dominion Energy Gas recognized $8 million, $7 million and $7 million, respectively, as employer matching contributions to these plans. Virginia Power also participates in these employee savings plans. During 2018, 2017 and 2016, Virginia Power recognized $20 million, $19 million and $19 million, respectively, as employer matching contributions to these plans.

Organizational Design Initiative

In the first quarter of 2016, the Companies announced an organizational design initiative that reduced 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. For the year ended December 31, 2016, Dominion Energy 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 Energy 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.

NOTE 22. 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 that the Companies cannot estimate, 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 that 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 Companies’ financial position, liquidity or results of operations.

175

Combined Notes to Consolidated Financial Statements, Continued

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

The MATS rule requires coal- and oil-fired electric utility steam generating units to meet strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. Virginia Power ceased operating the coal units at Yorktown power station in April 2017 to comply with the rule.

In June 2017, the DOE issued an order to PJM to direct Virginia Power to operate Yorktown power station’s Units 1 and 2 as needed to avoid reliability issues on the Virginia Peninsula. The order was effective for 90 days and can be reissued upon PJM’s request, if necessary, until required electricity transmission upgrades are completed. Beginning in August 2017, PJM filed requests for 90-day renewals of the DOE order which the DOE has granted. The current renewal is effective until March 2019. The Sierra Club has challenged the DOE order and certain renewal requests, all of which have been denied by the DOE.

In December 2018, the EPA issued a proposed rule to reverse its previous finding that it is appropriate and necessary to regulate toxic emissions from power plants. However, the emissions standards and other requirements of the MATS rule would remain in place as the EPA is not proposing to remove coal and oil fired power plants from the list of sources that are regulated under MATS. Although litigation of the MATS rule and the outcome of the EPA’s rulemaking are still pending, the regulation remains in effect and Virginia Power is complying with the applicable requirements of the rule and does not expect any adverse impacts to its operations at this time.

Ozone Standards

In October 2015, the EPA issued a final rule tightening the ozone standard from 75-ppb to 70-ppb. To comply with this standard, in April 2016 Virginia Power submitted the NO_X Reasonable Available Control Technology analysis for Unit 5 at Possum Point power station. In December 2016, the VDEQ determined that NO_X reductions are required on Unit 5. In October 2017, Virginia Power proposed to install NO_X controls by mid-2019 with an expected cost in the range of $25 million to $35 million. In April 2018, Virginia Power submitted an application with the VDEQ containing an alternative plan for compliance in lieu of installing NO_X controls on Unit 5 at Possum Point. The alter-

native plan includes operating restrictions during the ozone season through 2021 while allowing for continued operation to meet PJM capacity commitments and calls for the permanent retirement of the unit by 2021. In January 2019, the VDEQ issued a state operating permit that requires either the installation and operation of selective non-catalytic NO_X reduction technology by June 2019 or for Virginia Power to enter into an agreement with the VDEQ by June 2019 committing to retiring the unit by June 2021 with ozone season operating restrictions in the interim. In addition, Virginia Power placed two natural gas-fired units at the facility into cold reserve in December 2018. Virginia Power is currently evaluating its options. Dominion Energy and Virginia Power are unable to estimate the expenditures associated with this matter, however, they could be material to Dominion Energy and Virginia Power’s results of operations, financial condition and/or cash flows.

The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018. States have until August 2021 to develop plans to address the new standard. Until the states have developed implementation plans for the standard, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact on the Companies’ results of operations and cash flows.

NO_x and VOC Emissions

In April 2016, the Pennsylvania Department of Environmental Protection issued final regulations, with an effective date of January 2017, to reduce NO_X and VOC emissions from combustion sources. To comply with the regulations, Dominion Energy Gas installed emission control systems on existing engines at several compressor stations in Pennsylvania, which was completed in December 2018. The compliance costs associated with engineering and installation of controls and compliance demonstration with the regulation was approximately $35 million.

Oil and Gas NSPS

In August 2012, the EPA issued an 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 June 2016, the EPA issued a new NSPS regulation, 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. All projects which commenced construction after September 2015 are required to comply with this regulation. In October 2018, the EPA published a proposed rule reconsidering and amending portions of the 2016 rule, including but not limited to, the fugitive emissions requirements at well sites and compressor stations. Until the proposed rule is final, Dominion Energy and Dominion Energy Gas are implementing the 2016 regulation. Dominion Energy and Dominion Energy Gas are still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.

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GHG REGULATION

Carbon Regulations

In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and to set a significant emissions rate at 75,000 tons per year of CO₂ equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, the Companies cannot predict the impact to their financial statements.

In addition, the EPA continues to evaluate its policy regarding 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. It is unclear how the final policy will affect Virginia Power’s Altavista, Hopewell and Southampton power stations which were converted from coal to biomass under the prior biomass deferral policy; however, the expenditures to comply with any new requirements could be material to Dominion Energy and Virginia Power’s financial statements.

Methane Emissions

In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR Program, the Natural Gas STAR Methane Challenge Program. The 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, East Ohio, Hope, DETI and Questar Gas joined the EPA as founding partners in the new Methane Challenge program and submitted implementation plans in September 2016. Wexpro, DECG and Dominion Energy Questar Pipeline joined the Methane Challenge in 2018. DECG joined the EPA’s voluntary Natural Gas STAR Program in July 2016 and submitted an implementation plan in September 2016 with Questar Gas and Dominion Energy Questar Pipeline joining in 2018. Dominion Energy and Dominion Energy Gas do not expect the costs related to these programs to have a material impact on their results of operations, financial condition and/or cash flows.

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 Energy and Virginia Power have 13 and 11 facilities, respectively, that may be subject to the final regulations. Nine units at Virginia Power’s facilities that are subject to regulations under Section 316(b) of the CWA have been or will be placed into cold reserve. While in cold reserve, applicable requirements under Section 316(b) of the CWA continue to apply to these units. Dominion Energy anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion Energy 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 Energy 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. In April 2017, the EPA granted two separate petitions for reconsideration of the Effluent Limitations Guidelines final rule and stayed future compliance dates in the rule. Also in April 2017, the U.S. Court of Appeals for the Fifth Circuit granted the U.S.’s request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. In September 2017, the EPA signed a rule to postpone the earliest compliance dates for certain waste streams regulations in the Effluent Limitations Guidelines final rule from November 2018 to November 2020; however, the latest date for compliance for these regulations remains December 2023. The EPA is proposing to complete new rulemaking for these waste streams. While the impacts of this rule could be material to Dominion Energy and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for Dominion Energy and Virginia Power.

WASTE MANAGEMENT AND REMEDIATION

The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners

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Combined Notes to Consolidated Financial Statements, Continued

and operators of contaminated sites, can be jointly, severally and strictly liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.

From time to time, Dominion Energy, Virginia Power, or Dominion Energy 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. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion Energy, Virginia Power, or Dominion Energy Gas may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. The Companies do not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.

Dominion Energy has determined that it is associated with 22 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of which pertain to Dominion Energy 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 Energy is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. In addition, a Virginia Power site has been accepted into a state-based voluntary remediation program. In June 2018, Virginia Power submitted a proposed remedial action plan to remove material from this site at an estimated cost of $18 million. Pending VDEQ approval, Virginia Power expects to begin remedial work at this site in mid-2019. As a result, in June 2018, Virginia recorded a charge of $16 million ($12 million after-tax) in other operations and maintenance expense in the Consolidated Statements of Income. The four sites Dominion Energy acquired in the SCANA Combination associated with SCE&G are in various states of investigation, remediation and monitoring under work plans approved by, or under review by, the SCDHEC or the EPA. Dominion Energy anticipates that activities at these sites will continue through 2020 at an estimated cost of $10 million. In September 2018, SCE&G submitted an updated remediation work plan at one site to SCDHEC, which if approved, would increase costs by approximately $8 million. SCE&G expects to recover costs arising from the remediation work at all four sites through rate recovery mechanisms. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.

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

Other Legal Matters

The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and

personal injury. Due to the uncertainty surrounding these matters, the Companies are unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows.

APPALACHIAN GATEWAY

Pipeline Contractor Litigation

Following the completion of the Appalachian Gateway project in 2012, DETI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2015, the contractor filed a complaint against DETI in U.S. District Court for the Western District of Pennsylvania. In March 2016, the Pennsylvania court granted DETI’s motion to transfer the case to the U.S. District Court for the Eastern District of Virginia. In July 2016, DETI filed a motion to dismiss. In March 2017, the court dismissed three of eight counts in the complaint. In May 2017, the contractor withdrew one of the counts in the complaint. In November 2017, DETI and the contractor entered into a partial settlement agreement for a release of certain claims. In August 2018, DETI paid $14 million in accordance with the terms of a settlement agreement reached between the parties, resolving this matter.

Gas Producers Litigation

In connection with the Appalachian Gateway project, Dominion Energy Field Services, Inc. entered into contracts for firm purchase rights with a group of small gas producers. In June 2016, the gas producers filed a complaint in the Circuit Court of Marshall County, West Virginia against Dominion Energy, DETI and Dominion Energy Field Services, Inc., among other defendants, claiming that the contracts are unenforceable and seeking compensatory and punitive damages. During the third quarter of 2016, Dominion Energy, DETI and Dominion Energy Field Services, Inc. were served with the complaint. Also in the third quarter of 2016, Dominion Energy and DETI, with the consent of the other defendants, removed the case to the U.S. District Court for the Northern District of West Virginia. In October 2016, the defendants filed a motion to dismiss and the plaintiffs filed a motion to remand. In February 2017, the U.S. District Court entered an order remanding the matter to the Circuit Court of Marshall County, West Virginia. In March 2017, Dominion Energy was voluntarily dismissed from the case; however, DETI and Dominion Energy Field Services, Inc. remain parties to the matter. In April 2017, the case was transferred to the Business Court Division of West Virginia. In January 2018, the court granted the motion to dismiss filed by the defendants on two counts. Claims are pending in the Business Court Division of West Virginia. Dominion Energy and Dominion Energy Gas cannot currently estimate financial statement impacts, but there could be a material impact to their financial condition and/or cash flows.

ASH POND AND LANDFILL CLOSURE COSTS

In March 2015, the Sierra Club filed a lawsuit alleging CWA violations at Chesapeake power station. In March 2017, the U.S. District Court for the Eastern District of Virginia ruled that impacted groundwater associated with the on-site coal ash storage units was migrating to adjacent surface water, which constituted

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an unpermitted point source discharge in violation of the CWA. The court, however, rejected Sierra Club’s claims that Virginia Power had violated specific conditions of its water discharge permit. Finding no harm to the environment, the court further declined to impose civil penalties or require excavation of the ash from the site as Sierra Club had sought. In July 2017, the court issued a final order requiring Virginia Power to perform additional specific sediment, water and aquatic life monitoring at and around the Chesapeake power station for a period of at least two years. The court further directed Virginia Power to apply for a solid waste permit from VDEQ that includes corrective measures to address on-site groundwater impacts. In July 2017, Virginia Power appealed the court’s July 2017 final order to the U.S. Court of Appeals for the Fourth Circuit. In August 2017, the Sierra Club filed a cross appeal. In September 2018, the U.S. Court of Appeals for the Fourth Circuit ruled that impacted groundwater associated with coal ash storage at the Chesapeake power station did not constitute point source pollution in violation of the CWA or the station’s water discharge permit. The Sierra Club subsequently filed a petition for rehearing with the U.S. Court of Appeals for the Fourth Circuit, which was denied.

In April 2015, the EPA enacted a final rule regulating CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store, CCRs. Dominion Energy currently operates inactive ash ponds, existing ash ponds and CCR landfills subject to the final rule at 11 different facilities, eight of which are at Virginia Power. This rule created a legal obligation for Dominion Energy and 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 2015, Virginia Power recorded a $386 million ARO related to future ash pond and landfill closure costs. In 2016, Virginia Power recorded an increase to this ARO of $238 million, which resulted in a $197 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $17 million increase in property, plant and equipment and a $24 million increase in regulatory assets.

In December 2016, legislation was enacted that creates a framework for EPA- approved state CCR permit programs. In August 2017, the EPA issued interim guidance outlining the framework for state CCR program approval. The EPA has enforcement authority until state programs are approved. The EPA and states with approved programs both will have authority to enforce CCR requirements under their respective rules and programs. In September 2017, the EPA agreed to reconsider portions of the CCR rule in response to two petitions for reconsideration. In March 2018, the EPA proposed certain changes to the CCR rule related to issues remanded as part of the pending litigation and other issues the EPA is reconsidering. Several of the proposed changes would allow states with approved CCR permit programs additional flexibilities in implementing their programs. In July 2018, the EPA promulgated the first phase of changes to the CCR rule. Until all phases of the CCR rule are promulgated, Dominion Energy and Virginia Power cannot forecast potential incremental impacts or costs related to existing coal ash sites in connection with future implementation of the 2016 CCR legislation and reconsideration of the CCR rule. In August 2018, the U.S. Court of Appeals for the D.C. Circuit

issued its decision in the pending challenges of the CCR rule, vacating and remanding to the EPA three provisions of the rule. Dominion Energy and Virginia Power do not expect the scope of the U.S. Court of Appeals for the D.C. Circuit’s decision to impact their closure plans, but cannot forecast incremental impacts associated with any future changes to the CCR rule in connection with the court’s remand.

In April 2017, the Governor of Virginia signed legislation into law that places a moratorium on the VDEQ issuing solid waste permits for closure of ash ponds at Virginia Power’s Bremo, Chesapeake, Chesterfield and Possum Point power stations until May 2018. The law also required Virginia Power to conduct an assessment of closure alternatives for the ash ponds at these four stations, to include an evaluation of excavation for recycling or off-site disposal, surface and groundwater conditions and safety. Virginia Power completed the assessments and provided the report on December 1, 2017. In April 2018, the Governor of Virginia signed legislation into law extending the existing permit moratorium until July 2019. The legislation also requires Virginia Power to solicit and compile by November 2018, information from third parties on the suitability, cost and market demand for beneficiation or recycling of coal ash from these units. The coal ash recycling business plan was submitted to the legislature in November 2018. The extended moratorium does not apply to a permit required for an impoundment where CCRs have already been removed and placed in another impoundment on-site, are being removed from an impoundment, or are being processed in connection with a recycling or beneficial use project. In connection with this legislation, in the second quarter of 2018 Virginia Power recorded an increase to its ARO and a related environmental liability related to future ash pond and landfill closure costs of $131 million, which resulted in an $81 million ($60 million after-tax) charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $46 million increase in property, plant and equipment associated with asset retirement costs and a $4 million increase in regulatory assets. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the obligation.

COVE POINT

In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project at the Cove Point facility, which enables the facility to liquefy domestically-produced natural gas and export it as LNG. In March 2018, Cove Point received authorization from FERC to commence service of the Liquefaction Project, which commenced commercial operations in April 2018.

Two parties have separately filed petitions for review of the FERC order in the U.S. Court of Appeals for the D.C. Circuit, which petitions were consolidated. 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. In September 2017, FERC issued its order on remand from the U.S. Court of Appeals for the D.C. Circuit, and reaffirmed its ruling in its prior orders that Cove Point did not violate the prohibition against undue discrimination by agreeing to a capacity reduction and early contract termination with the

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Combined Notes to Consolidated Financial Statements, Continued

existing import shipper. In October 2017, the party filed a request for rehearing of the FERC order on remand. In August 2018, FERC issued its rehearing order affirming and clarifying its previous orders. No appeals were filed and FERC’s orders are final and no longer subject to further review.

FERC

FERC staff in the Office of Enforcement, Division of Investigations, conducted a non-public investigation of Virginia Power’s offers of combustion turbines generators into the PJM day-ahead markets from April 2010 through September 2014. FERC staff notified Virginia Power of its preliminary findings relating to Virginia Power’s alleged violation of FERC’s rules in connection with these activities. Virginia Power provided its response to FERC staff’s preliminary findings letter explaining why Virginia Power’s conduct was lawful and refuting any allegation of wrongdoing. This matter is pending. Virginia Power has recorded a liability of $14 million in its Consolidated Balance Sheet at December 31, 2018.

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 U.S. nuclear operators, Dominion Energy 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 Energy requiring implementation of safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation have been implemented. The information requests issued by the NRC request each reactor to reevaluate the seismic and external flooding hazards at their site using present-day methods and information, conduct walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. The walkdowns of each unit have been completed, audited by the NRC and found to be adequate. Reevaluation of the emergency communications systems and staffing levels was completed as part of the effort to comply with the orders. Reevalua-

tion of the seismic hazards was completed or in review with the NRC in 2018. Reevaluation of the external flooding hazards is expected to continue through 2019. Dominion Energy 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 Energy and Virginia Power do not expect material financial impacts related to compliance with Tier 2 and Tier 3 recommendations.

Nuclear Operations

NUCLEAR DECOMMISSIONING—MINIMUM FINANCIAL ASSURANCE

The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 2018 calculation for the NRC minimum financial assurance amount, aggregated for Dominion Energy and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.7 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 2018 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2018 U.S. Bureau of Labor Statistics indices. Dominion Energy believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. Dominion Energy and Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. See Note 9 for additional information on nuclear decommissioning trust investments.

NUCLEAR INSURANCE

The Price-Anderson Amendments Act of 1988 provides the public with liability protection on a per site, per nuclear incident basis, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. During the second quarter of 2018, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program decreased from

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$13.4 billion to $13.1 billion. During the fourth quarter of 2018, this amount increased from $13.1 billion to $14.1 billion. Dominion Energy and Virginia Power have purchased $450 million of coverage from commercial insurance pools for Millstone, Surry and North Anna with the remainder provided through the mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., Dominion Energy and Virginia Power could be assessed up to $138 million for each of their licensed reactors not to exceed $21 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. The NRC granted an exemption in March 2015 to remove Kewaunee from the Secondary Financial Protection program. This same exemption permitted Dominion Energy to reduce Kewaunee’s required level of liability coverage to $100 million. This reduction was implemented in January 2018, following the removal and storage of the spent nuclear fuel from the spent fuel pool. The current levels of nuclear property insurance coverage for Dominion Energy and Virginia Power’s nuclear units are as follows:

	Coverage
(billions)
Dominion Energy
Millstone	$	1.70
Kewaunee		0.05
Virginia Power(1)
Surry	$	1.70
North Anna		1.70

(1) Surry and North Anna share a blanket property limit of $200 million.

Dominion Energy and Virginia Power’s nuclear property insurance coverage for Millstone, Surry and North Anna exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site. In March 2015, the NRC granted an exemption which allowed Kewaunee to reduce its property insurance limit to $50 million. This reduction was implemented in January 2018, following the removal and storage of the spent nuclear fuel from the spent fuel pool. This includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion Energy and Virginia Power’s maximum retrospective premium assessment for the current policy period is $83 million and $51 million, respectively. Based on the severity of the incident, the Board of Directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion Energy and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

Millstone and Virginia Power also purchase accidental outage insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program,

Dominion Energy and Virginia Power are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion Energy and Virginia Power’s maximum retrospective premium assessment for the current policy period is $21 million and $10 million, respectively.

ODEC, a part owner of North Anna, and Massachusetts Municipal and Green Mountain, part owners of Millstone’s Unit 3, are responsible to Dominion Energy and Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.

SPENT NUCLEAR FUEL

Dominion Energy and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by Dominion Energy and Virginia Power’s contracts with the DOE. Dominion Energy and Virginia Power have previously received damages award payments and settlement payments related to these contracts.

By mutual agreement of the parties, the settlement agreements are extendable to provide for resolution of damages incurred after 2013. The settlement agreements for the Surry, North Anna and Millstone nuclear power stations have been extended to provide for periodic payments for damages incurred through December 31, 2019. In June 2018, a lawsuit for Kewaunee was filed in the U.S. Court of Federal Claims for recovery of spent nuclear fuel storage costs incurred for the period January 1, 2014 through December 31, 2017. This matter is pending.

In 2018, Virginia Power and Dominion Energy received payments of $16 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2016 through December 31, 2016, and $13 million for resolution of claims incurred at Millstone for the period of July 1, 2016 through June 30, 2017.

In 2017, Virginia Power and Dominion Energy received payments of $22 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2015 through December 31, 2015, and $14 million for resolution of claims incurred at Millstone for the period of July 1, 2015 through June 30, 2016.

In 2016, Virginia Power and Dominion Energy received payments of $30 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2014 through December 31, 2014, and $22 million for resolution of claims incurred at Millstone for the period of July 1, 2014 through June 30, 2015.

Dominion Energy and Virginia Power continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion Energy’s receivables for spent nuclear fuel-related costs totaled $49 million and $46 million at December 31, 2018 and 2017, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $30 million at both December 31, 2018 and 2017.

Dominion Energy and Virginia Power will continue to manage their spent fuel until it is accepted by the DOE.

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Combined Notes to Consolidated Financial Statements, Continued

Long-Term Purchase Agreements

At December 31, 2018, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that a third party has used to secure financing for the facility that will provide the contracted goods or services:

	2019			2020			2021			2022			2023			Thereafter			Total
(millions)
Purchased electric capacity(1)		$	60		$	52		$	46		$	—		$	—		$	—		$	158

(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with independent power producers, which end in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad based economic indices. At December 31, 2018, the present value of Virginia Power’s total commitment for capacity payments is $142 million. Capacity payments totaled $50 million, $114 million and $248 million, and energy payments totaled $42 million, $72 million and $126 million for the years ended 2018, 2017 and 2016, respectively.

Lease Commitments

The Companies lease real estate, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating leases that have initial or remaining lease terms in excess of one year as of December 31, 2018 are as follows:

	2019			2020			2021			2022			2023			Thereafter			Total
(millions)
Dominion Energy		$	64		$	61		$	55		$	47		$	38		$	384		$	649
Virginia Power			34			32			28			22			16			106			238
Dominion Energy Gas			12			11			9			7			4			3			46

Rental expense for Dominion Energy totaled $109 million, $113 million, and $104 million for 2018, 2017 and 2016, respectively. Rental expense for Virginia Power totaled $63 million, $57 million, and $52 million for 2018, 2017 and 2016, respectively. Rental expense for Dominion Energy Gas totaled $22 million, $34 million, and $37 million for 2018, 2017 and 2016, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.

In July 2016, Dominion Energy 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, totaling $365 million, to fund the estimated project costs. The project is expected to be completed by mid-2019. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $281 million as of December 31, 2018. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 89.9% of the then funded amount. For specific full recourse events, Dominion Energy 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 Energy 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 on behalf of the lessor 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 Energy 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.

Guarantees, Surety Bonds and Letters of Credit

In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility, also entered in October 2017, with a stated maturity date of October 2021. Dominion Energy’s maximum potential loss exposure under the terms of the guarantee is limited to 48% of the outstanding borrowings under the revolving credit facility, an equal percentage to Dominion Energy’s ownership in Atlantic Coast Pipeline. As of December 31, 2018, Atlantic Coast Pipeline has borrowed $1.4 billion against the revolving credit facility and borrowed an additional $113 million in January and February 2019. Dominion Energy’s Consolidated Balance Sheet includes a liability of $21 million and $28 million associated with this guarantee agreement at December 31, 2018 and 2017, respectively.

In addition, at December 31, 2018, Dominion Energy had issued an additional $48 million of guarantees, primarily to support other equity method investees. No amounts related to the other guarantees have been recorded.

Dominion Energy also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion Energy would be obligated to satisfy such obligation. To the extent that a liability subject to a guarantee has been incurred by one of Dominion Energy’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion Energy 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 Energy 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 December 31, 2018, Dominion Energy had issued the following subsidiary guarantees:

	Maximum Exposure
(millions)
Commodity transactions(1)		$	2,186
Nuclear obligations(2)			179
Cove Point(3)			1,900
Solar(4)			659
Other(5)			420
Total(6)		$	5,344

182

(1) Guarantees related to commodity commitments of certain subsidiaries. These guarantees were provided to counterparties in order to facilitate physical and financial transaction related commodities and services.

(2) Guarantees related to certain DGI subsidiaries’ regarding all aspects of running a nuclear facility.

(3) Guarantees related to Cove Point, in support of terminal services, transportation and construction. Cove Point has two guarantees that have no maximum limit and, therefore, are not included in this amount.

(4) Includes guarantees to facilitate the development of solar projects. Also includes guarantees entered into by DGI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.

(5) Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations, construction projects and insurance programs. Due to the uncertainty of worker’s compensation claims, the parental guarantee has no stated limit. Also included are guarantees related to certain DGI subsidiaries’ obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of December 31, 2018, Dominion Energy’s maximum remaining cumulative exposure under these equity funding agreements is $4 million through 2019 and its maximum annual future contribution is approximately $4 million.

(6) Excludes Dominion Energy’s guarantee for the construction of the new corporate office property discussed further within Lease Commitments above.

Additionally, at December 31, 2018, Dominion Energy had purchased $171 million of surety bonds, including $72 million at Virginia Power and $26 million at Dominion Energy Gas, and authorized the issuance of letters of credit by financial institutions of $88 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.

Indemnifications

As part of commercial contract negotiations in the normal course of business, the Companies may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Companies are unable to develop an estimate of the maximum potential amount of any other future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2018, the Companies believe any other future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.

NOTE 23. CREDIT RISK

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

The Companies maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Management believes, based on credit policies and the December 31, 2018 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

General

DOMINION ENERGY

As a diversified energy company, Dominion Energy transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic, Midwest and Rocky Mountain and Southeast regions of the U.S. Dominion Energy does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.

Dominion Energy’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion Energy transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of any collateral. At December 31, 2018, Dominion Energy’s credit exposure totaled $145 million. Of this amount, investment grade counterparties, including those internally rated, represented 69%, and no single counterparty, whether investment grade or non-investment grade, exceeded $47 million of exposure.

VIRGINIA POWER

Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2018, Virginia Power’s credit exposure totaled $10 million, of which no amounts were investment grade counterparties, and no single counterparty exceeded $9 million of exposure.

183

Combined Notes to Consolidated Financial Statements, Continued

DOMINION ENERGY GAS

Dominion Energy Gas transacts mainly with major companies in the energy industry and with residential and commercial energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. Dominion Energy Gas does not believe that this geographic concentration contributes to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy Gas is not exposed to a significant concentration of credit risk for receivables arising from gas utility operations. Dominion Energy Gas’ gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2018, Dominion Energy Gas’ credit exposure totaled $8 million. Of this amount, investment grade counterparties, including those internally rated, represented 93%, and no single counterparty, whether investment grade or non-investment grade, exceeded $5 million of exposure.

In 2018, DETI provided service to 307 customers with approximately 96% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 38% of the total storage and transportation revenue and the thirty largest provided approximately 71% of the total storage and transportation revenue.

East Ohio distributes natural gas to residential, commercial and industrial customers in Ohio using rates established by the Ohio Commission. Approximately 99% of East Ohio revenues are derived from its regulated gas distribution services. East Ohio’s bad debt risk is mitigated by the regulatory framework established by the Ohio Commission. See Note 13 for further information about Ohio’s PIPP and UEX Riders that mitigate East Ohio’s overall credit risk.

Credit-Related Contingent Provisions

The majority of Dominion Energy’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion Energy 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 December 31, 2018 and 2017, Dominion Energy would have been required to post an additional $1 million and $62 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 Energy had posted no collateral at December 31, 2018 and 2017, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. 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 December 31, 2018 and 2017 was $1 million and $65 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power and Dominion Energy Gas were not material

as of December 31, 2018 and 2017. See Note 7 for further information about derivative instruments.

NOTE 24. RELATED-PARTY TRANSACTIONS

Virginia Power and Dominion Energy Gas engage in related party transactions primarily with other Dominion Energy subsidiaries (affiliates). Virginia Power and Dominion Energy 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 Energy Gas are included in Dominion Energy’s consolidated federal income tax return and, where applicable, combined income tax returns for Dominion Energy are filed in various states. See Note 2 for further information. Dominion Energy’s transactions with equity method investments are described in Note 9. 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 forward commodity purchases, to manage commodity price risks associated with purchases of natural gas. See Notes 7 and 19 for more information. As of December 31, 2018, Virginia Power’s derivative assets and liabilities with affiliates were $26 million and $10 million, respectively. As of December 31, 2017, Virginia Power’s derivative assets and liabilities with affiliates were $11 million and $5 million, respectively.

Virginia Power participates in certain Dominion Energy benefit plans as described in Note 21. At December 31, 2018 and 2017, Virginia Power’s amounts due to Dominion Energy associated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets were $632 million and $505 million, respectively. At December 31, 2018 and 2017, Virginia Power’s amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $254 million and $199 million, respectively.

DES 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.

The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES to Virginia Power on the basis of direct and allocated methods in accordance with Virginia Power’s services agreements with DES. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES serv-

184

ice. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.

Presented below are significant transactions with DES and other affiliates:

Year Ended December 31,	2018			2017			2016
(millions)
Commodity purchases from affiliates		$	930		$	674		$	571
Services provided by affiliates(1)			450			453			454
Services provided to affiliates			24			25			22

(1) Includes capitalized expenditures of $145 million, $144 million and $144 million for the year ended December 31, 2018, 2017 and 2016, respectively.

Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. There were $224 million and $33 million in short-term demand note borrowings from Dominion Energy as of December 31, 2018 and 2017, respectively. The weighted-average interest rate of these borrowings was 2.94% and 1.65% at December 31, 2018 and 2017, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion Energy money pool for its nonregulated subsidiaries as of December 31, 2018 and 2017. Interest charges related to Virginia Power’s borrowings from Dominion Energy were immaterial for the years ended December 31, 2018, 2017 and 2016.

There were no issuances of Virginia Power’s common stock to Dominion Energy in 2018, 2017 or 2016.

DOMINION ENERGY GAS

Transactions with Related Parties

Dominion Energy Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Energy Gas provides transportation and storage services to affiliates. Dominion Energy Gas also enters into certain other contracts with affiliates, and related parties, including construction services, which are presented separately from contracts involving commodities or services. As of December 31, 2018 and 2017, all of Dominion Energy Gas’ commodity derivatives were with affiliates. See Notes 7 and 19 for more information. See Note 9 for information regarding transactions with an affiliate.

Dominion Energy Gas participates in certain Dominion Energy benefit plans as described in Note 21. At December 31, 2018 and 2017, Dominion Energy Gas’ amounts due from Dominion Energy associated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $772 million and $734 million, respectively. Dominion Energy Gas’ amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $14 million and $7 million at December 31, 2018 and 2017, respectively.

DES and other affiliates provide accounting, legal, finance and certain administrative and technical services to Dominion Energy Gas. Dominion Energy Gas provides certain services to related parties, including technical services.

The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES to Dominion Energy Gas on the basis of direct and allocated methods in accordance with Dominion Energy Gas’ services agreements with DES. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable. The costs of these services follow:

Year Ended December 31,	2018			2017			2016
(millions)
Sales of natural gas and transportation and storage services to affiliates		$	58		$	70		$	69
Purchases of natural gas from affiliates			6			5			9
Services provided by related parties(1)			131			143			141
Services provided to related parties(2)			216			156			128

(1) Includes capitalized expenditures of $37 million, $45 million and $49 million for the year ended December 31, 2018, 2017 and 2016, respectively.

(2) Amounts primarily attributable to Atlantic Coast Pipeline, a related party VIE.

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

At December 31,	2018			2017
(millions)
Other receivables(1)		$	13		$	12
Customer receivables from related parties			1			1
Imbalances receivable from affiliates			1			1
Imbalances payable to affiliates(2)			13			—
Affiliated notes receivable(3)			16			20

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

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

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

Dominion Energy Gas’ borrowings under the IRCA with Dominion Energy totaled $218 million and $18 million as of December 31, 2018 and 2017, respectively. The weighted-average interest rate of these borrowings was 2.78% and 1.60% at December 31, 2018 and 2017, respectively. Interest charges related to Dominion Energy Gas’ total borrowings from Dominion Energy were immaterial for 2018, 2017 and 2016.

185

Combined Notes to Consolidated Financial Statements, Continued

NOTE 25. OPERATING SEGMENTS

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

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

(1) Includes remaining producer services activities.

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

DOMINION ENERGY

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

In 2018, Dominion Energy reported after-tax net expenses of $608 million in the Corporate and Other segment, with $88 million of the net expenses attributable to specific items related to its operating segments.

The net expenses for specific items in 2018 primarily related to the impact of the following items:

• A $219 million ($164 million after-tax) charge related to the impairment of certain gathering and processing assets attributable to Gas Infrastructure;

• A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers, attributable to:

• Power Generation ($109 million after-tax); and

• Power Delivery ($51 million after-tax);

• A $170 million ($134 million after-tax) net loss related to our investments in nuclear decommissioning trust funds attributable to Power Generation;

• A $124 million ($88 million after-tax) charge for disallowance of FERC-regulated plant attributable to Gas Infrastructure;

• An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Power Generation; and

• A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration attributable to Power Delivery; partially offset by

• An $828 million ($619 million after-tax) benefit associated with the sale of certain merchant generation facilities and equity method investments attributable to:

• Power Generation ($229 million after-tax); and

• Gas Infrastructure ($390 million after-tax).

In 2017, Dominion Energy reported after-tax net benefits of $389 million in the Corporate and Other segment, with $861 million of the net benefits attributable to specific items related to its operating segments.

The net benefits for specific items in 2017 primarily related to the impact of the following items:

• A $979 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, primarily attributable to:

• Gas Infrastructure ($324 million);

• Power Generation ($655 million); partially offset by

• $158 million ($96 million after-tax) of charges associated with equity method investments in wind-powered generation facilities, attributable to Power Generation.

In 2016, Dominion Energy reported after-tax net expenses of $484 million in the Corporate and Other segment, with $180 million of these net expenses attributable to specific items related to its operating segments.

The net expenses for specific items in 2016 primarily related to the impact of the following items:

• A $197 million ($122 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Power Generation; and

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

• Power Delivery ($5 million after-tax);

• Gas Infrastructure ($12 million after-tax); and

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

186

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

Year Ended December 31,	Power Delivery		Power Generation			Gas Infrastructure			Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2018
Total revenue from external customers	$	2,206	$	7,104		$	4,221		$	(208	)	$	43		$	13,366
Intersegment revenue		23		11			27			674			(735	)		—
Total operating revenue		2,229		7,115			4,248			466			(692	)		13,366
Depreciation, depletion and amortization		625		746			615			14			—			2,000
Impairment of assets and related charges		—		1			8			394			—			403
Gains on sales of assets		—		6			(186	)		(200	)		—			(380	)
Equity in earnings of equity method investees		—		18			178			1			—			197
Interest income		—		90			64			126			(196	)		84
Interest and related charges		265		374			268			782			(196	)		1,493
Income tax expense (benefit)		160		294			330			(204	)		—			580
Net income (loss) attributable to Dominion Energy		587		1,254			1,214			(608	)		—			2,447
Investment in equity method investees		—		82			1,159			37			—			1,278
Capital expenditures		1,564		1,321			1,415			105			—			4,405
Total assets (billions)		17.8		28.2			31.5			11.2			(10.8	)		77.9
2017
Total revenue from external customers	$	2,206	$	6,676		$	2,832		$	16		$	856		$	12,586
Intersegment revenue		22		10			834			610			(1,476	)		—
Total operating revenue		2,228		6,686			3,666			626			(620	)		12,586
Depreciation, depletion and amortization		593		747			522			43			—			1,905
Impairment of assets and related charges		—		—			—			15			—			15
Gains on sales of assets		—		—			(147	)		—			—			(147	)
Equity in earnings of equity method investees		—		(181	)		159			4			—			(18	)
Interest income		4		92			45			96			(155	)		82
Interest and related charges		265		342			109			644			(155	)		1,205
Income tax expense (benefit)		334		373			487			(1,224	)		—			(30	)
Net income (loss) attributable to Dominion Energy		531		1,181			898			389			—			2,999
Investment in equity method investees		—		81			1,422			41			—			1,544
Capital expenditures		1,433		2,275			2,149			52			—			5,909
Total assets (billions)		16.7		29.0			28.0			12.0			(9.1	)		76.6
2016
Total revenue from external customers	$	2,210	$	6,747		$	2,069		$	(7	)	$	718		$	11,737
Intersegment revenue		23		10			697			609			(1,339	)		—
Total operating revenue		2,233		6,757			2,766			602			(621	)		11,737
Depreciation, depletion and amortization		537		662			330			30			—			1,559
Impairment of assets and related charges		—		—			—			4			—			4
Gains on sales of assets		—		4			(44	)		—			—			(40	)
Equity in earnings of equity method investees		—		(16	)		105			22			—			111
Interest income		—		74			34			36			(78	)		66
Interest and related charges		244		290			38			516			(78	)		1,010
Income tax expense (benefit)		308		279			431			(363	)		—			655
Net income (loss) attributable to Dominion Energy		484		1,397			726			(484	)		—			2,123
Capital expenditures		1,320		2,440			2,322			43			—			6,125

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

VIRGINIA POWER

The majority of Virginia Power’s revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia Power’s Power Delivery and Power Generation segments.

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 2018, Virginia Power reported an after-tax net expense of $312 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net expenses for specific items in 2018 primarily related to the impact of the following items:

• A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers, attributable to:

• Power Generation ($109 million after-tax); and

• Power Delivery ($51 million after-tax).

• An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Power Generation.

• A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration attributable to Power Delivery.

187

Combined Notes to Consolidated Financial Statements, Continued

In 2017, Virginia Power reported an after-tax net benefit of $74 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net benefit for specific items in 2017 primarily related to the impact of the following item:

• A $93 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, attributable to Power Generation.

In 2016, Virginia Power reported after-tax net expenses of $173 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net expenses for specific items in 2016 primarily related to the impact of the following item:

• A $197 million ($121 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Power Generation.

188

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

Year Ended December 31,	Power Delivery		Power Generation		Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2018
Operating revenue	$	2,204	$	5,630	$	(215	)	$	—		$	7,619
Depreciation and amortization		624		533		(25	)		—			1,132
Interest income		—		9		5			(4	)		10
Interest and related charges		265		250		—			(4	)		511
Income tax expense (benefit)		158		220		(78	)		—			300
Net income (loss)		586		1,008		(312	)		—			1,282
Capital expenditures		1,539		1,003		—			—			2,542
Total assets (billions)		17.6		19.4		—			(0.1	)		36.9
2017
Operating revenue	$	2,212	$	5,344	$	—		$	—		$	7,556
Depreciation and amortization		594		547		—			—			1,141
Interest income		4		15		3			(3	)		19
Interest and related charges		265		232		—			(3	)		494
Income tax expense (benefit)		334		534		(94	)		—			774
Net income		527		939		74			—			1,540
Capital expenditures		1,439		1,290		—			—			2,729
Total assets (billions)		16.6		18.6		—			(0.1	)		35.1
2016
Operating revenue	$	2,217	$	5,390	$	(19	)	$	—		$	7,588
Depreciation and amortization		537		488		—			—			1,025
Interest income		—		—		—			—			—
Interest and related charges		244		219		—			(2	)		461
Income tax expense (benefit)		307		524		(104	)		—			727
Net income (loss)		482		909		(173	)		—			1,218
Capital expenditures		1,313		1,336		—			—			2,649

DOMINION ENERGY GAS

The Corporate and Other Segment of Dominion Energy Gas primarily includes specific items attributable to Dominion Energy 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 Energy Gas as a result of Dominion Energy’s basis in the net assets contributed.

In 2018, Dominion Energy Gas reported after-tax net expenses of $251 million in its Corporate and Other segment, with $244 million of these net expenses attributable to its operating segment.

The net expenses for specific items in 2018 primarily related to the impact of the following items:

• A $219 million ($165 million after-tax) charge related to the impairment of gathering and processing assets; and

• A $124 million ($88 million after-tax) charge for disallowance of FERC-regulated plant.

In 2017, Dominion Energy Gas reported after-tax net benefit of $179 million in its Corporate and Other segment, with $174 million of these net expenses attributable to its operating segment.

The net benefit for specific items in 2017 primarily related to the impact of the following item:

• A $185 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.

In 2016, Dominion Energy Gas reported after-tax net expenses of $3 million in its Corporate and Other segment, with $7 million of these net expenses attributable to its operating segment.

The net expense for specific items in 2016 primarily related to the impact of the following item:

• An $8 million ($5 million after-tax) charge related to an organizational design initiative.

189

Combined Notes to Consolidated Financial Statements, Continued

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

Year Ended December 31,	Gas Infrastructure			Corporate and Other			Consolidated Total
(millions)
2018
Operating revenue	$	1,940		$	—		$	1,940
Depreciation and amortization		244			—			244
Impairment of assets and related charges		5			341			346
Gains on sales of assets		(119	)		—			(119	)
Equity in earnings of equity method investees		24			—			24
Interest income		2			—			2
Interest and related charges		104			1			105
Income tax expense (benefit)		188			(102	)		86
Net income (loss)		552			(251	)		301
Investment in equity method investees		91			—			91
Capital expenditures		772			—			772
Total assets (billions)		11.8			0.6			12.4
2017
Operating revenue	$	1,814		$	—		$	1,814
Depreciation and amortization		227			—			227
Impairment of assets and related charges		15			1			16
Gains on sales of assets		(70	)		—			(70	)
Equity in earnings of equity method investees		21			—			21
Interest income		2			—			2
Interest and related charges		97			—			97
Income tax expense (benefit)		256			(205	)		51
Net income		436			179			615
Investment in equity method investees		95			—			95
Capital expenditures		778			—			778
Total assets (billions)		11.3			0.6			11.9
2016
Operating revenue	$	1,638		$	—		$	1,638
Depreciation and amortization		214			(10	)		204
Gains on sales of assets		(45	)		—			(45	)
Equity in earnings of equity method investees		21			—			21
Interest income		1			—			1
Interest and related charges		92			2			94
Income tax expense (benefit)		237			(22	)		215
Net income (loss)		395			(3	)		392
Capital expenditures		854			—			854

190

NOTE 26. QUARTERLY FINANCIAL DATA (UNAUDITED)

A summary of the Companies’ quarterly results of operations for the years ended December 31, 2018 and 2017 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

DOMINION ENERGY

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(millions)
2018
Operating revenue	$	3,466	$	3,088	$	3,451	$	3,361
Income from operations		875		742		1,150		834
Net income including noncontrolling interests		526		478		883		662
Net income attributable to Dominion Energy		503		449		854		641
Basic EPS:
Net income attributable to Dominion Energy		0.77		0.69		1.31		0.97
Diluted EPS:
Net income attributable to Dominion Energy		0.77		0.69		1.30		0.97
Dividends declared per common share		0.835		0.835		0.835		0.835
2017
Operating revenue	$	3,384	$	2,813	$	3,179	$	3,210
Income from operations		1,079		753		1,152		953
Net income including noncontrolling interests		674		417		696		1,333
Net income attributable to Dominion Energy		632		390		665		1,312
Basic EPS:
Net income attributable to Dominion Energy		1.01		0.62		1.03		2.04
Diluted EPS:
Net income attributable to Dominion Energy		1.01		0.62		1.03		2.04
Dividends declared per common share		0.755		0.755		0.770		0.770

Dominion Energy’s 2018 results include the impact of the following significant items:

• Fourth quarter results include $536 million of after-tax gains from the sale of certain merchant generation facilities and equity method investments partially offset by a $164 million after-tax impairment charge for certain gathering and processing assets.

• Second quarter results include an $89 million after-tax charge for disallowance of FERC-regulated plant.

• First quarter results include a $160 million after-tax charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers.

Dominion Energy’s 2017 results include the impact of the following significant item:

• Fourth quarter results include $851 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, partially offset by $96 million of after-tax charges associated with our equity method investments in wind-powered generation facilities.

VIRGINIA POWER

Virginia Power’s quarterly results of operations were as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(millions)
2018
Operating revenue	$	1,748	$	1,829	$	2,232	$	1,810
Income from operations		364		533		756		418
Net income		184		339		520		239
2017
Operating revenue	$	1,831	$	1,747	$	2,154	$	1,824
Income from operations		653		613		847		619
Net income		356		318		459		407

Virginia Power’s 2018 results include the impact of the following significant item:

• First quarter results include a $160 million after-tax charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers.

Virginia Power’s 2017 results include the impact of the following significant item:

• Fourth quarter results include a $93 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.

DOMINION ENERGY GAS

Dominion Energy Gas’ quarterly results of operations were as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(millions)
2018
Operating revenue		$526		$459		$423		$532
Income (loss) from operations		201		7		182		(55	)
Net income (loss)	166		15		136		(16)
2017
Operating revenue		$490		$422		$401		$501
Income from operations		156		116		185		181
Net income		108		77		117		313

Dominion Energy Gas’s 2018 results include the impact of the following significant items:

• Fourth quarter results include a $165 million after-tax impairment charge for certain gathering and processing assets.

• Second quarter results include an $89 million after-tax charge for disallowance of FERC-regulated plant.

Dominion Energy Gas’s 2017 results include the impact of the following significant item:

• Fourth quarter results include a $197 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.

191

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

DOMINION ENERGY

Senior management, including Dominion Energy’s CEO and CFO, evaluated the effectiveness of Dominion Energy’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion Energy’s CEO and CFO have concluded that Dominion Energy’s disclosure controls and procedures are effective. There were no changes in Dominion Energy’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion Energy’s internal control over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Dominion Energy understands and accepts responsibility for Dominion Energy’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion Energy continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as Dominion Energy does throughout all aspects of its business.

Dominion Energy maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Audit Committee of the Board of Directors of Dominion Energy, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal control, and financial reporting matters of Dominion Energy and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically meet alone with the Audit Committee and have free access to the Audit Committee at any time.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion Energy’s 2018 Annual Report to contain a management’s report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for the report, Dominion Energy tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2018, Dominion Energy makes the following assertions:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion Energy.

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Management evaluated Dominion Energy’s internal control over financial reporting as of December 31, 2018. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion Energy maintained effective internal control over financial reporting as of December 31, 2018.

Dominion Energy’s independent registered public accounting firm is engaged to express an opinion on Dominion Energy’s internal control over financial reporting, as stated in their report which is included herein.

February 28, 2019

192

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of Dominion Energy, Inc.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Dominion Energy, Inc. and subsidiaries (“Dominion Energy”) at December 31, 2018, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, Dominion Energy maintained, in all material respects, effective internal control over financial reporting at December 31, 2018, based on criteria established in Internal Control—Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements at and for the year ended December 31, 2018, of Dominion Energy and our report dated February 28, 2019, expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

Dominion Energy’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Dominion Energy’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Dominion Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately

and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2019

193

VIRGINIA POWER

Senior management, including Virginia Power’s CEO and CFO, evaluated the effectiveness of Virginia Power’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Virginia Power’s CEO and CFO have concluded that Virginia Power’s disclosure controls and procedures are effective. There were no changes in Virginia Power’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Virginia Power’s internal control over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Virginia Power understands and accepts responsibility for Virginia Power’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Virginia Power continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.

Virginia Power maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Board of Directors also serves as Virginia Power’s Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Virginia Power’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Virginia Power’s 2018 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Virginia Power tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2018, Virginia Power makes the following assertions:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power.

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Management evaluated Virginia Power’s internal control over financial reporting as of December 31, 2018. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of

the Treadway Commission. Based on this assessment, management believes that Virginia Power maintained effective internal control over financial reporting as of December 31, 2018.

This annual report does not include an attestation report of Virginia Power’s registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Virginia Power’s independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.

February 28, 2019

DOMINION ENERGY GAS

Senior management, including Dominion Energy Gas’ CEO and CFO, evaluated the effectiveness of Dominion Energy Gas’ disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion Energy Gas’ CEO and CFO have concluded that Dominion Energy Gas’ disclosure controls and procedures are effective. There were no changes in Dominion Energy Gas’ internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion Energy Gas’ internal control over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Dominion Energy Gas understands and accepts responsibility for Dominion Energy Gas’ financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion Energy Gas continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.

Dominion Energy Gas maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Board of Directors also serves as Dominion Energy Gas’ Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Dominion Energy Gas’ auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Dominion Energy Gas’ 2018 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Dominion Energy Gas tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2018, Dominion Energy Gas makes the following assertions:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion Energy Gas.

194

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Management evaluated Dominion Energy Gas’ internal control over financial reporting as of December 31, 2018. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion Energy Gas maintained effective internal control over financial reporting as of December 31, 2018.

This annual report does not include an attestation report of Dominion Energy Gas’ registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Dominion Energy Gas’ independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.

February 28, 2019

Item 9B. Other Information

None.

195

Part III

Item 10. Directors, Executive Officers and Corporate Governance

DOMINION ENERGY

The following information for Dominion Energy is incorporated by reference from the Dominion Energy 2019 Proxy Statement, which will be filed on or around March 22, 2019:

• Information regarding the directors required by this item is found under the heading Election of Directors.

• Information regarding compliance with Section 16 of the Securities Exchange Act of 1934, as amended, required by this item is found under the heading Section 16(a) Beneficial Ownership Reporting Compliance.

• Information regarding the Dominion Energy Audit Committee Financial expert(s) required by this item is found under the heading The Committees of the Board—Audit Committee.

• Information regarding the Dominion Energy Audit Committee required by this item is found under the headings The Committees of the Board—Audit Committee and Audit Committee Report.

• Information regarding Dominion Energy’s Code of Ethics and Business Conduct required by this item is found under the heading Other Information—Code of Ethics and Business Conduct.

The information concerning the executive officers of Dominion Energy required by this item is included in Part I of this Form 10-K under the caption Executive Officers of Dominion Energy. Each executive officer of Dominion Energy is elected annually.

Item 11. Executive Compensation

DOMINION ENERGY

The following information about Dominion Energy is contained in the 2019 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the headings Compensation Discussion and Analysis and Executive Compensation Tables; the information regarding Compensation Committee interlocks contained under the heading Compensation Committee Interlocks and Insider Participation; the information regarding the Compensation Committee review and discussions of Compensation Discussion and Analysis contained under the heading Compensation, Governance and Nominating Committee Report; and the information regarding director compensation contained under the heading Compensation of Non-Employee Directors.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

DOMINION ENERGY

The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the heading Securities Ownership in the 2019 Proxy Statement is incorporated by reference.

The information regarding equity securities of Dominion Energy that are authorized for issuance under its equity compensation plans contained under the heading Executive Compensation Tables-Equity Compensation Plans in the 2019 Proxy Statement is incorporated by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

DOMINION ENERGY

The information regarding related party transactions required by this item found under the heading Other Information—Certain Relationships and Related Party Transactions, and information regarding director independence found under the heading Corporate Governance—Director Independence, in the 2019 Proxy Statement is incorporated by reference.

196

Item 14. Principal Accountant Fees and Services

DOMINION ENERGY

The information concerning principal accountant fees and services contained under the heading Auditor Fees and Pre-Approval Policy in the 2019 Proxy Statement is incorporated by reference.

VIRGINIA POWER AND DOMINION ENERGY GAS

The following table presents fees paid to Deloitte & Touche LLP for services related to Virginia Power and Dominion Energy Gas for the fiscal years ended December 31, 2018 and 2017.

Type of Fees	2018		2017
(millions)
Virginia Power
Audit fees	$	1.68	$	1.93
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
Total Fees	$	1.68	$	1.93
Dominion Energy Gas
Audit fees	$	0.97	$	1.09
Audit-related fees		0.26		0.24
Tax fees		—		—
All other fees		—		—
Total Fees	$	1.23	$	1.33

Audit fees represent fees of Deloitte & Touche LLP for the audit of Virginia Power and Dominion Energy Gas’ annual consolidated financial statements, the review of financial statements included in Virginia Power and Dominion Energy Gas’ quarterly Form 10-Q reports, and the services that an independent auditor would customarily provide in connection with subsidiary audits, statutory requirements, regulatory filings, and similar engagements for the fiscal year, such as comfort letters, attest services, consents, and assistance with review of documents filed with the SEC.

Audit-related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Virginia Power and Dominion Energy Gas’ consolidated financial statements or internal control over financial reporting. This category may include fees related to the performance of audits and attest services not required by statute or regulations, due diligence related to mergers, acquisitions, and investments, and accounting consultations about the application of GAAP to proposed transactions.

Virginia Power and Dominion Energy Gas’ Boards of Directors have adopted the Dominion Energy Audit Committee pre-approval policy for their independent auditor’s services and fees and have delegated the execution of this policy to the Dominion Energy Audit Committee. In accordance with this delegation, each year the Dominion Energy Audit Committee pre-approves a schedule that details the services to be provided for the following year and an estimated charge for such services. At its February 2019 meeting, the Dominion Energy Audit Committee approved schedules of services and fees for 2019 inclusive of Virginia Power and Dominion Energy Gas. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the Dominion Energy Audit Committee or a delegated member of the Dominion Energy Audit Committee.

197

Part IV

Item 15. Exhibits and Financial Statement Schedules

(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.

1. Financial Statements

See Index on page 69.

2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.

3. Exhibits (incorporated by reference unless otherwise noted)

Exhibit Number	Description	Dominion Energy		Virginia Power		Dominion Energy Gas
2.1	Agreement and Plan of Merger by and among Dominion Energy, Inc., Sedona Corp. and SCANA Corporation, dated as of January  2, 2018 (Exhibit 2.1, Form 8-K filed January 5, 2018, File No. 1-8489).		X
3.1.a	Dominion Energy, Inc. Articles of Incorporation as amended and restated, effective May 10, 2017 (Exhibit 3.1, Form 8-K filed May 10, 2017, 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 Energy Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066).						X
3.1.d	Articles of Amendment to the Articles of Organization of Dominion Energy Gas Holdings, LLC (Exhibit 3.1, Form 8-K filed May 16, 2017, File No. 1-37591).						X
3.2.a	Dominion Energy, Inc. Amended and Restated Bylaws, effective May  10, 2017 (Exhibit 3.2, Form 8-K filed May 10, 2017, 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 Energy Gas Holdings, LLC dated as of May  12, 2017 (Exhibit 3.2, Form 8-K filed May 16, 2017, File No. 001-37591).						X
4	Dominion Energy, Inc., Virginia Electric and Power Company and Dominion Energy 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 any of their total consolidated assets.		X		X		X
4.1.a	See Exhibit 3.1.a above.		X
4.1.b	See Exhibit 3.1.b above.				X
4.2	Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indenture (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No.  1-2255); Ninety-Second Supplemental Indenture, dated as of July  1, 2012 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2012 filed August 1, 2012, File No. 1-2255).		X		X
4.3	Form of Senior Indenture, dated June  1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No.  333-47119); Form of Thirteenth Supplemental Indenture, dated as of January  1, 2006 (Exhibit 4.3, Form 8-K filed January 12, 2006, File No.  1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May  16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September  1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No.  1-2255); Form of Seventeenth Supplemental Indenture, dated November  1, 2007 (Exhibit 4.3, Form 8-K filed November 30, 2007, File No.  1-2255); Form of Eighteenth Supplemental Indenture, dated April  1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No.  1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November  1, 2008 (Exhibit 4.2, Form 8-K filed		X		X

198

Exhibit Number	Description	Dominion Energy		Virginia Power		Dominion Energy Gas
	November 5, 2008, File No.  1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June  24, 2009, File No. 1-2255); Form of Twenty- First Supplemental Indenture, dated August  1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No.  1-2255); Twenty-Second Supplemental Indenture, dated as of January  1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No.  1-2255); Twenty-Third Supplemental Indenture, dated as of January  1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No.  1-2255); Twenty-Fourth Supplemental Indenture, dated as of January  1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No.  1-2255); Twenty-Fifth Supplemental Indenture, dated as of March  1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No.  1-2255); Twenty-Sixth Supplemental Indenture, dated as of August  1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No.  1-2255); Twenty-Seventh Supplemental Indenture, dated February  1, 2014 (Exhibit 4.3, Form 8-K filed February 7, 2014, File No.  1-2255); Twenty-Eighth Supplemental Indenture, dated February  1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, File No.  1-2255); Twenty-Ninth Supplemental Indenture, dated May 1, 2015 (Exhibit 4.3, Form 8-K filed May  13, 2015, File No. 1-02255); Thirtieth Supplemental Indenture, dated May 1, 2015 (Exhibit 4.4, Form 8-K filed May 13, 2015, File No.  1-02255); Thirty-First Supplemental Indenture, dated January  1, 2016 (Exhibit 4.3, Form 8-K filed January 14, 2016, File No.  000-55337); Thirty-Second Supplemental Indenture, dated November  1, 2016 (Exhibit 4.3, Form 8-K filed November 16, 2016, File No.  000-55337); Thirty-Third Supplemental Indenture, dated November  1, 2016 (Exhibit 4.4, Form 8-K filed November 16, 2016, File No.  000-55337); Thirty-Fourth Supplemental Indenture, dated March  1, 2017 (Exhibit 4.3, Form 8-K filed March 16, 2017; Fil e No. 000-55337).
4.4	Senior Indenture, dated as of September  1, 2017, between Virginia Electric and Power Company and U.S. Bank National Association, as Trustee (Exhibit 4.1, Form 8-K filed September  13, 2017, File No. 000-55337); First Supplemental Indenture, dated as of September  1, 2017 (Exhibit 4.2, Form 8-K filed September  13, 2017, File No. 000-55337); Second Supplemental Indenture, dated as of March 1, 2018 (Exhibit 4.2, Form 8-K filed March 22, 2018, File No.  000-55337); Third Supplemental Indenture, dated as of November  1, 2018 (Exhibit 4.2, Form 8-K filed November 28, 2018, File No. 000-55337).		X		X
4.5	Indenture, Junior Subordinated Debentures, dated December  1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a Form of Second Supplemental Indenture, dated January  1, 2001 (Exhibit 4.6, Form 8-K filed January 12, 2001, File No. 1-8489).		X
4.6	Indenture, dated April  1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October  15, 2026); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December  12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027).		X
4.7	Form of Senior Indenture, dated June  1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of Sixteenth Supplemental Indenture, dated December  1, 2002 (Exhibit 4.3, Form 8-K filed December 13, 2002, File No.  1-8489); Form of Twenty-First Supplemental Indenture, dated March  1, 2003 (Exhibits 4.3, Form 8-K filed March 4, 2003, File No.  1-8489); Form of Twenty-Second Supplemental Indenture, dated July  1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No.  1-8489); Form of Twenty-Ninth Supplemental Indenture, dated June  1, 2005 (Exhibit 4.3, Form 8-K filed June 17, 2005, File No.  1-8489); Form of Thirty-Fifth Supplemental Indenture, dated June  1, 2008 (Exhibit 4.2, Form 8-K filed June 16, 2008, File No.  1-8489); Form of Thirty-Sixth Supplemental Indentures, dated June  1, 2008 (Exhibit 4.3, Form 8-K filed June 16, 2008, File No.  1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K		X

199

Exhibit Number	Description	Dominion Energy		Virginia Power	Dominion Energy Gas
	filed August 12, 2009, File No.  1-8489); Forty-First Supplemental Indenture, dated March 1, 2011 (Exhibit 4.3, Form 8-K, filed March  7, 2011, File No. 1-8489); Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 5, 2011, File No.  1-8489); Forty-Fifth Supplemental Indenture, dated September  1, 2012 (Exhibit 4.3, Form 8-K, filed September 13, 2012, File No.  1-8489); Forty-Sixth Supplemental Indenture, dated September  1, 2012 (Exhibit 4.4, Form 8-K, filed September 13, 2012, File No.  1-8489); Forty-Seventh Supplemental Indenture, dated September  1, 2012 (Exhibit 4.5, Form 8-K, filed September 13, 2012, File No.  1-8489); Forty-Eighth Supplemental Indenture, dated March  1, 2014 (Exhibit 4.3, Form 8-K, filed March 24, 2014, File No.  1-8489); Forty-Ninth Supplemental Indenture, dated November  1, 2014 (Exhibit 4.3, Form 8-K, filed November 25, 2014, File No.  1-8489); Fiftieth Supplemental Indenture, dated November  1, 2014 (Exhibit 4.4, Form 8-K, filed November 25, 2014, File No.  1-8489); Fifty-First Supplemental Indenture, dated November  1, 2014 (Exhibit 4.5, Form 8-K, filed November 25, 2014, File No. 1-8489).
4.8	Indenture, dated as of June  1, 2015, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form 8-K filed June 15, 2015, File No. 1-8489); First Supplemental Indenture, dated as of June 1, 2015 (Exhibit 4.2, Form 8-K filed June 15, 2015, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2015 (Exhibit 4.2, Form 8-K filed September 24, 2015, File No.  1-8489); Third Supplemental Indenture, dated as of February  1, 2016 (Exhibit 4.7, Form 10-K for the fiscal year ended December 31, 2015 filed February 26, 2016, File No.  1-8489); Fourth Supplemental Indenture, dated as of August  1, 2016 (Exhibit 4.2, Form 8-K filed August 9, 2016, File No.  1-8489); Fifth Supplemental Indenture, dated as of August  1, 2016 (Exhibit 4.3, Form 8-K filed August 9, 2016, File No.  1-8489); Sixth Supplemental Indenture, dated as of August  1, 2016 (Exhibit 4.4, Form 8-K filed August 9, 2016, File No.  1-8489); Seventh Supplemental Indenture, dated as of September  1, 2016 (Exhibit 4.1, Form 10-Q filed November 9, 2016, File No.  1-8489); Eighth Supplemental Indenture, dated as of December  1, 2016 (Exhibit 4.7, Form 10-K for the fiscal year ended December 31, 2016 filed February 28, 2017, File No.  1-8489); Ninth Supplemental Indenture, dated as of January  1, 2017 (Exhibit 4.2, Form 8-K filed January 12, 2017, File No.  1-8489); Tenth Supplemental Indenture, dated as of January  1, 2017 (Exhibit 4.3, Form 8-K filed January 12, 2017, File No.  1-8489); Eleventh Supplemental Indenture, dated as of March  1, 2017 (Exhibit 4.3, Form 10-Q filed May 4, 2017, File No.  1-8489); Twelfth Supplemental Indenture, dated as of June  1, 2017 (Exhibit 4.2, Form 10-Q filed August 3, 2017, File No.  1-8489); Thirteenth Supplemental Indenture, dated December  1, 2017 (Exhibit 4.8, Form 10-K for the fiscal year ended December 31, 2017 filed February 27, 2018, File No.  1-8489); Fourteenth Supplemental Indenture, dated May 1, 2018 (Exhibit 4.2, Form 10-Q filed August  2, 2018, File No. 1-8489); Fifteenth Supplemental Indenture, dated June 1, 2018 (Exhibit 4.2, Form 8-K, filed June 5, 2018, File No. 1-8489).		X
4.9	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); Third Supplemental and Amending Indenture, dated as of June  1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, 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 July 1, 2016 (Exhibit 4.3, Form 8-K filed July  19, 2016, File No. 1-8489); Eleventh Supplemental Indenture, dated August 1, 2016 (Exhibit 4.3, Form 8-K filed August 15, 2016, File No.  1-8489); Twelfth Supplemental Indenture, dated August 1, 2016 (Exhibit 4.4, Form 8-K filed August  15, 2016, File No. 1-8489); Thirteenth Supplemental Indenture, dated May 18, 2017 (Exhibit 4.4, Form 8-K filed May 18, 2017, File No. 1-8489).		X

200

Exhibit Number	Description	Dominion Energy		Virginia Power		Dominion Energy Gas
4.10	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No.  1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489).		X
4.11	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No.  1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489).		X
4.12	2016 Series A Purchase Contract and Pledge Agreement, dated August  15, 2016, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.7, Form 8-K filed August 15, 2016, File No. 1-8489).		X
4.13	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); 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 (Exhibit 4.1.a, Form 10-Q filed August 3, 2016, File No.  1-37591); Ninth Supplemental Indenture, dated as of June  1, 2016 (Exhibit 4.1.b, Form 10-Q filed August 3, 2016, File No.  1-37591); Tenth Supplemental Indenture, dated as of June  1, 2016 (Exhibit 4.1.c, Form 10-Q filed August 3, 2016, File No.  1-37591); Eleventh Supplemental Indenture, dated June 1, 2018 (Exhibit 4.2, Form 8-K filed June  19, 2018, File No. 1-37591).		X				X
10.1	$6,000,000,000 Third Amended and Restated Revolving Credit Agreement, dated as of March  20, 2018, among Dominion Energy, Inc., Virginia Electric and Power Company, Dominion Energy Gas Holdings, LLC, Questar Gas Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Mizuho Bank, Ltd., Bank of America, N.A., The Bank of Nova Scotia and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein (Exhibit 10.1, Form 8-K filed March 26, 2018, File No. 001-08489).		X		X		X
10.2	$950 million 364-Day Term Loan Credit Agreement, dated February  9, 2018, by and among Dominion Energy, Inc., The Bank of Nova Scotia, as Administrative Agent, The Bank of Nova Scotia, as Lead Arranger and Bookrunner, and other lenders named therein (Exhibit 10.1, Form 8-K filed February 15, 2018, File No. 001-08489).		X
10.3	Confirmation of Forward Sale Transaction, dated March  27, 2018, between the Company and Credit Suisse Capital, LLC, with Credit Suisse Securities (USA) LLC acting as agent for Credit Suisse Capital LLC (Exhibit 10.1, Form 8-K filed April 2, 2018, File No. 001-08489).		X
10.4	Confirmation of Forward Sale Transaction, dated March  27, 2018, between the Company and Credit Suisse Capital, LLC, with Credit Suisse Securities (USA) LLC acting as agent for Goldman Sachs & Co. LLC (Exhibit 10.2, Form 8-K filed April 2, 2018, File No. 001-08489).		X
10.5	$500,000,000 364-Day Term Loan Credit Agreement, dated June  14, 2018, by and among Dominion Energy, Inc., Toronto Dominion (Texas) LLC, as Administrative Agent, TD Securities (USA) LLC, as Lead Arranger and Bookrunner, and other lenders named therein (Exhibit 10.1, Form 8-K filed June 15, 2018, File No. 001-08489).		X

201

Exhibit Number	Description	Dominion Energy		Virginia Power		Dominion Energy Gas
10.6	DRS Services Agreement, dated January  1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (Exhibit 10.1, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489).		X
10.7	DRS Services Agreement, dated January  1, 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company (Exhibit 10.2, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255).				X
10.8	DRS Services Agreement, dated September  12, 2013, between Dominion Gas Holdings, LLC and Dominion Resources Services, Inc. (Exhibit 10.3, Form S-4 filed April 4, 2014, File No. 333-195066).						X
10.9	DRS Services Agreement, dated January  1, 2003, between Dominion Transmission, Inc. and Dominion Resources Services, Inc. (Exhibit 10.4, Form S-4 filed April 4, 2014, File No. 333-195066).						X
10.10	DRS Services Agreement, dated January  1, 2003, between The East Ohio Company and Dominion Resources Services, Inc. (Exhibit 10.5, Form S-4 filed April 4, 2014, File No. 333-195066).						X
10.11	DRS Services Agreement, dated January  1, 2003, between Dominion Iroquois, Inc. and Dominion Resources Services, Inc. (Exhibit 10.6, Form S-4 filed April 4, 2014, File No. 333-195066).						X
10.12	Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489).		X		X
10.13	Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003 filed May 9, 2003, File No. 1-8489 and File No. 1-2255).		X		X
10.14	Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No.  1-8489), as amended September  26, 2014 (Exhibit 10.1, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).		X		X		X
10.15*	Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 1-2255), as amended March  31, 2006 (Exhibit 10.1, Form 8-K filed April 4, 2006, File No. 1-8489).		X		X		X
10.16*	Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company dated January 24, 2013 (effective for certain officers elected subsequent to February 1, 2013) (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2013 filed February 28, 2014, File No. 1-8489 and File No. 1-2255).		X		X		X
10.17*	Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No.  1-8489), as amended September  26, 2014 (Exhibit 10.2, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).		X		X		X
10.18*	Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 31, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X		X
10.19*	Dominion Resources, Inc. New Executive Supplemental Retirement Plan, as amended and restated effective July  1, 2013 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2013 filed August 6, 2013 File No.  1-8489), as amended September  26, 2014 (Exhibit 10.3, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014)		X		X		X

202

Exhibit Number	Description	Dominion Energy		Virginia Power		Dominion Energy Gas
10.20*	Dominion Resources, Inc. New Retirement Benefit Restoration Plan, as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No.  1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February  26, 2009, File No. 1-2255), as amended September 26, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).		X		X		X
10.21*	Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No.  1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489).		X
10.22*	Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February  27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No.  1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489).		X
10.23*	Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January  1, 2005, as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489).		X
10.24*	Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated May  7, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended June 30, 2014 filed July 30, 2014, File No.  1-8489 and File No. 1-2250).		X		X		X
10.25*	Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell, II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No.  1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489).		X		X		X
10.26*	Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F.  McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489).		X		X		X
10.27*	Supplemental Retirement Agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255).		X		X		X
10.28*	Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No.  1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October  30, 2008, File No. 1-2255)		X		X		X
10.29*	Supplemental Retirement Agreement with Mark F. McGettrick effective May  19, 2010 (Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489).		X		X		X
10.30*	Form of Restricted Stock Award Agreement under the 2013 Long-Term Incentive Program approved January 24, 2013 (Exhibit 10.2, Form 8-K filed January 25, 2013, File No. 1-8489).		X		X		X
10.31*	Form of Restricted Stock Award Agreement under the 2014 Long-Term Incentive Program approved January 16, 2014 (Exhibit 10.41, Form 10-K for the fiscal year ended December 31, 2013 filed February 28, 2014, File No. 1-8489).		X		X		X
10.32*	Dominion Resources, Inc. 2014 Incentive Compensation Plan, effective May 7, 2014 (Exhibit 10.1, Form 8-K filed May 7, 2014, File No. 1-8489).		X		X		X
10.33	Registration Rights Agreement, dated as of October  22, 2013, by and among Dominion Gas Holdings, LLC and RBC Capital Markets, LLC, RBS Securities Inc. and Scotia Capital (USA) Inc., as the initial purchasers of the Notes (Exhibit 10.1, Form S-4 filed April  4, 2014, File No. 333-195066).						X
10.34	Inter-Company Credit Agreement, dated October  17, 2013, between Dominion Resources, Inc. and Dominion Gas Holdings, LLC (Exhibit 10.2, Form S-4 filed April 4, 2014, File No. 333-195066).		X				X

203

Exhibit Number	Description	Dominion Energy		Virginia Power		Dominion Energy Gas
10.35*	2016 Performance Grant Plan under the 2016 Long-Term Incentive Program approved January 21, 2016 (Exhibit 10.47, Form 10-K for the fiscal year ended December 31, 2015 filed February 26, 2016, File No. 1-8489).		X		X		X
10.36*	Form of Restricted Stock Award Agreement under the 2016 Long-Term Incentive Program approved January 21, 2016 (Exhibit 10.48, Form 10-K for the fiscal year ended December 31, 2015 filed February 26, 2016, File No. 1-8489).		X		X		X
10.37*	2017 Performance Grant Plan (Transition Grant) under the 2017 Long-Term Incentive Program approved January  24, 2017 (Exhibit 10.45, Form 10-K for the fiscal year ended December 31, 2016 filed February 28, 2017, File No. 1-8489).		X		X		X
10.38*	Form of Restricted Stock Award Agreement under the 2017 Long-Term Incentive Program approved January 24, 2017 (Exhibit 10.46, Form 10-K for the fiscal year ended December 31, 2016 filed February 28, 2017, File No. 1-8489).		X		X		X
10.39*	2017 Performance Grant Plan under the 2014 Incentive Compensation Plan approved January 24, 2017 (Exhibit 10.3, Form 10-Q for the quarter ended March 31, 2017 filed May 4, 2017, File No. 1-8489).		X		X		X
10.40*	2018 Performance Grant Plan under the 2018 Long-Term Incentive Program approved January 25, 2018 (Exhibit 10.43, Form 10-K for the fiscal year ended December 31, 2017, filed February 27, 2018, File No. 1-8489).		X		X		X
10.41*	Form of Restricted Stock Award Agreement under the 2018 Long-Term Incentive Program approved January 25, 2018 (Exhibit 10.44, Form 10-K for the fiscal year ended December 31, 2017, filed February 27, 2018, File No. 1-8489).		X		X		X
10.42*	2019 Performance Grant Plan under the 2019 Long-Term Incentive Program approved January 24, 2019 (filed herewith).		X		X		X
10.43*	2019 Goal-Based Stock Award Agreement under the 2019 Long-Term Incentive Program approved January 24, 2019 (filed herewith).		X		X		X
10.44*	Form of Restricted Stock Award Agreement under the 2019 Long-Term Incentive Program approved January 24, 2019 (filed herewith).		X		X		X
21	Subsidiaries of Dominion Energy, Inc. (filed herewith).		X
23.1	Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm for Dominion Energy, Inc., Virginia Electric and Power Company and Dominion Energy Gas Holdings, LLC (filed herewith).		X		X		X
23.2	Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm for SCANA Corporation (filed herewith).		X
31.a	Certification by Chief Executive Officer of Dominion Energy, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X
31.b	Certification by Chief Financial Officer of Dominion Energy, 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 Energy 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 Energy 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 Energy, 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 Energy Gas Holdings, LLC as required by Section  906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).						X

204

Exhibit Number	Description	Dominion Energy		Virginia Power		Dominion Energy Gas
99	Audited Consolidated Financial Statements and Schedule of SCANA Corporation at December  31, 2018 and 2017 and for the three years ended December 31, 2018, together with the related notes to the financial statements (incorporated by reference from Item 8. Financial Statements and Supplementary Data for SCANA Corporation, SCANA Corporation Annual Report on Form 10-K for the fiscal year ended December 31, 2018, filed February 28, 2019, File No. 1-8809). SCANA Corporation’s Annual Report is included in a combined filing with the Annual Report of South Carolina Electric & Gas Company; information related to such affiliated entity is not considered to be a component of the Audited Financial Statements of SCANA Corporation.		X
101	The following financial statements from Dominion Energy, Inc., Virginia Electric and Power Company and Dominion Energy Gas Holdings, LLC Annual Report on Form 10-K for the year ended December 31, 2018, filed on February 28, 2019, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.		X		X		X

* Indicates management contract or compensatory plan or arrangement.

Item 16. Form 10-K Summary

None.

205

Signatures

Dominion Energy

Pursuant to the requirements of Section 13 or 15(d) 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 ENERGY, INC.
By:	/s/ Thomas F. Farrell, II
	(Thomas F. Farrell, II, Chairman, President and Chief Executive Officer)

Date: February 28, 2019

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2019.

Signature	Title
/s/ Thomas F. Farrell, II Thomas F. Farrell, II	Chairman of the Board of Directors, President and Chief Executive Officer
/s/ James A. Bennett James A. Bennett	Director
/s/ Helen E. Dragas Helen E. Dragas	Director
/s/ James O. Ellis, Jr. James O. Ellis, Jr.	Director
/s/ D. Maybank Hagood D. Maybank Hagood	Director
/s/ John W. Harris John W. Harris	Director
/s/ Ronald W. Jibson Ronald W. Jibson	Director
/s/ Mark J. Kington Mark J. Kington	Director
/s/ Joseph M. Rigby Joseph M. Rigby	Director
/s/ Pamela J. Royal Pamela J. Royal	Director
/s/ Robert H. Spilman, Jr. Robert H. Spilman, Jr.	Director
/s/ Susan N. Story Susan N. Story	Director
/s/ Michael E. Szymanczyk Michael E. Szymanczyk	Director
/s/ James R. Chapman James R. Chapman	Executive Vice President, Chief Financial Officer and Treasurer
/s/ Michele L. Cardiff Michele L. Cardiff	Vice President, Controller and Chief Accounting Officer

206

Virginia Power

Pursuant to the requirements of Section 13 or 15(d) 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.

VIRGINIA ELECTRIC AND POWER COMPANY
By:	/s/ Thomas F. Farrell, II
	(Thomas F. Farrell, II, Chairman of the Board of Directors and Chief Executive Officer)

Date: February 28, 2019

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2019.

Signature	Title
/s/ Thomas F. Farrell, II Thomas F. Farrell, II	Chairman of the Board of Directors and Chief Executive Officer
/s/ Robert M. Blue Robert M. Blue	Director
/s/ Carlos M. Brown Carlos M. Brown	Director
/s/ James R. Chapman James R. Chapman	Executive Vice President, Chief Financial Officer and Treasurer
/s/ Michele L. Cardiff Michele L. Cardiff	Vice President, Controller and Chief Accounting Officer

207

Dominion Energy Gas

Pursuant to the requirements of Section 13 or 15(d) 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 ENERGY GAS HOLDINGS, LLC
By:	/s/ Thomas F. Farrell, II
	(Thomas F. Farrell, II, Chairman of the Board of Directors and Chief Executive Officer)

Date: February 28, 2019

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2019.

Signature	Title
/s/ Thomas F. Farrell, II Thomas F. Farrell, II	Chairman of the Board of Directors and Chief Executive Officer
/s/ Carlos M. Brown Carlos M. Brown	Director
/s/ James R. Chapman James R. Chapman	Director, Executive Vice President, Chief Financial Officer and Treasurer
/s/ Michele L. Cardiff Michele L. Cardiff	Vice President, Controller and Chief Accounting Officer

208

EX-10.42

EXHIBIT 10.42

DOMINION ENERGY, INC.

2019 PERFORMANCE GRANT PLAN

1.    Purpose. The purpose of the 2019 Performance Grant Plan (the “Plan”) is to set forth the terms of 2019 Performance Grants (“Performance Grants”) awarded by Dominion Energy, Inc., a Virginia corporation (the “Company”). This Plan contains the performance goals for the awards, the performance criteria, the target and maximum amounts payable, and other applicable terms and conditions. Capitalized terms not otherwise defined herein shall have the meanings given them in the Company’s 2014 Incentive Compensation Plan, as amended.

2.    Definitions.

a.    Beneficiary. Means the individual, individuals, entity, entities or the estate of a Participant entitled to receive the amounts payable under a Performance Grant, if any, upon the Participant’s death.

b.    Cause. For purposes of this Plan, the term “Cause” will have the meaning assigned to that term under a Participant’s Employment Continuity Agreement with the Company, as such Agreement may be amended from time to time.

c.    Committee. Means the Compensation, Governance and Nominating Committee of the board of directors of the Company (or any successor board committee designated by the board of directors of the Company to administer this Plan).

d.    Company Pension Plan. Means the applicable pension plan of the Company or its subsidiaries, if any, in which the Participant is eligible to participate as of the Date of Grant, which may include either the Dominion Energy Pension Plan or the SCANA Corporation Retirement Plan or any successor thereto, but excluding the cash balance portion of any such plan.

e.    Date of Grant. February 1, 2019.

f.    Disability or Disabled. Means a “disability” as defined under Treasury Regulation Section 1.409A-3(i)(4). The Committee will determine whether or not a Disability exists and its determination will be conclusive and binding on the Participant.

g.    Participant. An officer of the Company or a Dominion Company who receives a Performance Grant on the Date of Grant.

h.    Performance Period. The 36-month period beginning on January 1, 2019 and ending on December 31, 2021.

i.    Retire or Retirement. For purposes of this Plan, the term Retire or Retirement means a voluntary termination of employment on a date when the Participant is eligible for early or normal retirement benefits under the terms of the Company Pension Plan, or would be eligible if any crediting of deemed additional years of age or service applicable to the Participant under a supplemental retirement plan of the Company was applied under the Company Pension Plan, as in effect at the time of the determination, or,

1

for a Participant who is not eligible to participate in a Company Pension Plan, a voluntary termination of employment on or after age 55, unless (in each case) the Company’s Chief Executive Officer in his sole discretion (or, if the Participant is the Company’s Chief Executive Officer, the Committee in its sole discretion) determines that the Participant’s retirement is detrimental to the Company.

j.    Target Amount. The dollar amount designated in the written notice to the Participant communicating the Performance Grant.

3.    Performance Grants. A Participant will receive a written notice of the amount designated as the Participant’s Target Amount for the Performance Grant payable under the terms of this Plan. The actual payout may be from 0% to 200% of the Target Amount, depending on the achievement of the performance goals.

4.    Performance Achievement and Time of Payment. Upon the completion of the Performance Period, the Committee will determine the final performance goal achievement of each of the performance criteria described in Section 6. The Company will then calculate the final amount of each Participant’s Performance Grant based on such performance goal achievement. Except as provided in Sections 7(b) or 8, the Committee will determine the time of payout of the Performance Grants, provided that in no event will payment be made later than March 15, 2022. Performance Grants shall be paid in cash.

5.    Forfeiture. Except as provided in Sections 7 and 8, a Participant’s right to payout of a Performance Grant will be forfeited if the Participant’s employment with the Company or a Dominion Company terminates for any reason before the end of the Performance Period.

6.    Performance Goals. Payout of Performance Grants will be based on the performance goal achievement of the performance criteria described in this Section 6 and further defined in Exhibit A.

a.    TSR Performance. Total Shareholder Return (TSR) Performance will determine fifty percent (50%) of the Target Amount (“TSR Percentage”). Relative TSR Performance and Absolute TSR Performance are each defined in Exhibit A. The percentage of the TSR Percentage that will be paid out, if any, is based on the following table:

Relative TSR Performance Percentile Ranking	Percentage Payout of TSR Percentage
85th or above		200	%
50th		100	%
25th		50	%
Below 25th		0	%

To the extent that the Company’s Relative TSR Performance ranks in a percentile between the 25^th and 85^th percentile in the table above, then the TSR Percentage payout will be interpolated between the corresponding TSR Percentage payout set forth above. No payment of the TSR Percentage will be made if the Relative TSR Performance is below the 25^th percentile, except that a payment of 25% of the TSR Percentage will be made if the Company’s Relative TSR Performance is below the 25^th percentile but its Absolute

2

TSR Performance is at least 9%. In addition to the foregoing payments, and regardless of the Company’s Relative TSR Performance, either (but not both) of the following may be earned: (i) an additional payment of 25% of the TSR Percentage will be made if the Company’s Absolute TSR Performance is at least 10% but less than 15%, and/or if the Company’s Price-Earnings Ratio (as defined in Exhibit A) is at or above the 50^th percentile and below the top third of the group of companies (inclusive of the Company) used to measure Relative TSR Performance in accordance with Exhibit A hereto, or (ii) an additional payment of 50% of the TSR Percentage will be made if the Company’s Absolute TSR Performance is at least 15%, and/or if the Company’s Price-Earnings Ratio is at or above the top third of the group of companies (inclusive of the Company) used to measure Relative TSR Performance in accordance with Exhibit A hereto (in either case, the “Performance Adder”). The Committee may reduce or eliminate payment of the Performance Adder in its sole discretion.

The aggregate payments under this Section 6(a) may not exceed 250% of the TSR Percentage. In addition, the overall percentage payment under the entire Performance Grant may not exceed 200% of the Target Amount.

b.    ROIC Performance. Return on Invested Capital Performance (“ROIC Performance”) will determine fifty percent (50%) of the Target Amount (“ROIC Percentage”). ROIC Performance is defined in Exhibit A. The percentage of the ROIC Percentage that will be paid out, if any, is based on the following table:

ROIC Performance	Percentage Payout of ROIC Percentage
7.41% and above		200	%
7.13%		100	%
6.81%		50	%
Below 6.81%		0	%

• To the extent that the Company’s ROIC Performance is greater than 6.81% and less than 7.13%, the ROIC Percentage payout will be interpolated between the applicable Percentage Payout of ROIC Percentage range set forth above.

• To the extent that the Company’s ROIC Performance is greater than 7.13% and less than 7.41%, the ROIC Percentage payout will be interpolated between the applicable Percentage Payout of ROIC Percentage range set forth above.

7.     Retirement, Involuntary Termination without Cause, Death or Disability.

a.    Retirement or Involuntary Termination without Cause. Except as provided in Section 8, if a Participant Retires during the Performance Period or if a Participant’s employment is involuntarily terminated by the Company or a Dominion Company without Cause during the Performance Period, and in either case the Participant would have been eligible for a payment if the Participant had remained employed until the end of the Performance Period, the Participant will receive a pro-rated payout of the Participant’s Performance Grant equal to the payment the Participant would have received had the Participant remained employed until the end of the Performance Period multiplied by a fraction, the numerator of which is the number of whole months from February 1, 2019 to the first day of the month coinciding with or immediately following the date of the Participant’s retirement or termination of employment, and the denominator of which is

3

thirty-five (35). Payment will be made after the end of the Performance Period at the time provided in Section 4 based on the performance goal achievement approved by the Committee. If the Participant Retires, however, no payment will be made if the Company’s Chief Executive Officer in his sole discretion (or, if the Participant is the Company’s Chief Executive Officer, the Committee in its sole discretion) determines that the Participant’s Retirement is detrimental to the Company.

b.    Death or Disability. If, while employed by the Company or a Dominion Company, a Participant dies or becomes Disabled during the Performance Period, the Participant or, in the event of the Participant’s death, the Participant’s Beneficiary will receive a lump sum cash payment equal to the product of (i) and (ii) where:

(i) is the amount that would be paid based on the predicted performance used for determining the compensation cost recognized by the Company for the Participant’s Performance Grant for the latest financial statement filed with the Company’s Annual Report on Form 10-K or Quarterly Report on Form 10-Q immediately prior to the event; and

(ii) is a fraction, the numerator of which is the number of whole months from February 1, 2019 to the first day of the calendar month coinciding with or immediately following the date of the Participant’s death or Disability, and the denominator of which is thirty-five (35).

Payment under this Section 7(b) will be made as soon as administratively feasible (and in any event within sixty (60) days) after the date of the Participant’s death or Disability, and the Participant shall not have the right to any further payment under this Agreement. In the event of the Participant’s death, payment will be made to the Participant’s designated Beneficiary.

8.    Qualifying Change of Control. Upon a Qualifying Change of Control prior to the end of the Performance Period, provided the Participant has remained continuously employed with the Company or a Dominion Company from the Date of Grant to the date of the Qualifying Change of Control, the Participant will receive a lump sum cash payment equal to the greater of (i) the Target Amount or (ii) the total payout that would be made at the end of the Performance Period if the predicted performance used for determining the compensation cost recognized by the Company for the Participant’s Performance Grant for the latest financial statement filed with the Company’s Annual Report on Form 10-K or Quarterly Report on Form 10-Q immediately prior to the Qualifying Change of Control was the actual performance for the Performance Period (in either case, the “COC Payout Amount”). Payment will be made on or as soon as administratively feasible following the Qualifying Change of Control date and in no event later than sixty (60) days following the Qualifying Change of Control date. If a Qualifying Change of Control occurs prior to the end of the Performance Period and after a Participant has Retired or been involuntarily terminated without Cause pursuant to Section 7(a) above, then the Participant will receive a pro-rated payout of the Participant’s Performance Grant, equal to the COC Payout Amount multiplied by the fraction set forth in Section 7(a) above, with payment occurring in a cash lump sum on or as soon as administratively feasible (but in any event within sixty (60) days) after the Qualifying Change of Control date. Following any payment under this Section 8, the Participant shall not have the right to any further payment under this Agreement.

4

9.    Termination for Cause. Notwithstanding any provision of this Plan to the contrary, if the Participant’s employment with the Company or a Dominion Company is terminated for Cause (as defined by the Employment Continuity Agreement between the Participant and the Company), the Participant will forfeit all rights to his or her Performance Grant.

10.    Clawback of Award Payment.

a.    Restatement of Financial Statements. If the Company’s financial statements are required to be restated at any time within a two (2) year period following the end of the Performance Period as a result of fraud or intentional misconduct, the Committee may, in its discretion, based on the facts and circumstances surrounding the restatement, direct the Company to recover all or a portion of the Performance Grant payout from the Participant if the Participant’s conduct directly caused or partially caused the need for the restatement.

b.    Fraudulent or Intentional Misconduct. If the Company determines that the Participant has engaged in fraudulent or intentional misconduct related to or materially affecting the Company’s business operations or the Participant’s duties at the Company, the Committee may, in its discretion, based on the facts and circumstances surrounding the misconduct, direct the Company to withhold payment, or if payment has been made, to recover all or a portion of the Performance Grant payout from the Participant.

c.    Recovery of Payout. The Company reserves the right to recover a Performance Grant payout pursuant to this Section 10 by (i) seeking repayment from the Participant; (ii) reducing the amount that would otherwise be payable to the Participant under another Company benefit plan or compensation program to the extent permitted by applicable law; (iii) withholding future annual and long-term incentive awards or salary increases; or (iv) taking any combination of these actions.

d.    No Limitation on Remedies. The Company’s right to recover a Performance Grant payout pursuant to this Section 10 shall be in addition to, and not in lieu of, actions the Company may take to remedy or discipline a Participant’s misconduct including, but not limited to, termination of employment or initiation of a legal action for breach of fiduciary duty.

e.    Subject to Future Rulemaking. The Performance Grant payout is subject to any claw back policies the Company may adopt in order to conform to the requirements of Section 954 of the Dodd-Frank Wall Street Reform Act and Consumer Protection Act and resulting rules issued by the Securities and Exchange Commission or national securities exchanges thereunder and that the Company determines should apply to this Performance Grant Plan.

11.    Miscellaneous.

a.    Nontransferability. Except as provided in Section 7(b), a Performance Grant is not transferable and is subject to a substantial risk of forfeiture until the end of the Performance Period.

5

b.    No Right to Continued Employment. A Performance Grant does not confer upon a Participant any right with respect to continuance of employment by the Company, nor will it interfere in any way with the right of the Company to terminate a Participant’s employment at any time.

c.    Tax Withholding. The Company will withhold Applicable Withholding Taxes from the payout of Performance Grants.

d.    Performance Goal Adjustments. The Committee may at any time, in its sole discretion, remove or revise any performance goals or other performance objectives for this 2019 Performance Grant Plan. The Committee retains the authority to exercise negative discretion to reduce payments under this Plan as it deems appropriate.

e.    Governing Law. This Plan shall be governed by the laws of the Commonwealth of Virginia, without regard to its choice of law provisions.

f.    Binding Effect. This Plan will be binding upon and inure to the benefit of the legatees, distributes, and personal representatives of Participants and any successors of the Company.

g.    Section 409A. This Plan and the Performance Grants hereunder are intended to comply with Section 409A of the Internal Revenue Code of 1986, as amended (“Code Section 409A”), and shall be interpreted to the maximum extent possible in accordance with such intent. To the extent necessary to comply with Code Section 409A, no payment will be made earlier than six months after a Participant’s termination of employment other than for death if the Performance Grant is subject to Code Section 409A and the Participant is a “specified employee” (within the meaning of Code Section 409A(a)(2)(B)(i)).

h.    Administration. The Plan shall be administered by the Committee, which shall have all of the applicable powers and authority set forth in Section 19 of the Company’s 2014 Incentive Compensation Plan with respect to this Plan and the Performance Grants awarded hereunder, the terms of which are incorporated by reference herein.

i.    Termination and Amendment. The Committee may amend the Plan and Performance Grants awarded hereunder, provided that, except as otherwise provided herein, no termination or amendment of the Plan or any Performance Grants under the Plan shall materially adversely affect a Participant’s rights with respect to any outstanding Performance Grant without that Participant’s consent. Notwithstanding the foregoing, the Committee may amend the Plan and Performance Grants awarded hereunder without having to obtain the consent of any affected Participant as it deems necessary or appropriate to ensure compliance with applicable laws or to cause Performance Grants to avoid adverse tax consequences under the Code and regulations thereunder.

j.    Notice. All notices and other communications required or permitted to be given under this Plan shall be in writing and shall be deemed to have been duly given if delivered personally or mailed first class, postage prepaid, as follows: (a) if to the Company—at the principal business address of the Company to the attention of the

6

Corporate Secretary of the Company; and (b) if to any Participant—at the last address of the Participant known to the sender at the time the notice or other communication is sent.

k.    Interpretation. Unless otherwise specifically provided under the terms of any such plan or program, settlements of awards received by participants under the Plan shall not be deemed a part of a participant’s regular, recurring compensation for purposes of calculating payments or benefits from any benefit plan or severance program of the Company or a Dominion Company or any severance pay law of any country. Nothing contained in the Plan will be deemed in any way to limit or restrict the Company or any Dominion Company from making any award or payment to any person under any other plan, arrangement or understanding, whether now existing or hereafter in effect.

l.    Beneficiary Matters. A Participant may designate a Beneficiary to receive benefits due under a Performance Grant, if any, upon the Participant’s death. Designation of a Beneficiary shall be made by execution of a form approved or accepted by the Committee. In the absence of a valid Beneficiary designation, a Participant’s surviving spouse, if any, and if none, the Participant’s estate, shall be the Beneficiary. A Participant may change a prior Beneficiary designation by a subsequent execution of a new Beneficiary designation form. The change in Beneficiary will be effective upon receipt by the Committee. Any payment made to a Beneficiary under this Plan in good faith shall fully discharge the Company and the Dominion Companies from all further obligations with respect to that payment. If the Committee has any doubt as to the proper Beneficiary to receive a payment under this Plan, the Committee shall have the right to withhold such payment until the matter is fully adjudicated. In making any payment to or for the benefit of any minor or an incompetent Participant or Beneficiary, the administrator, in its sole and absolute discretion, may make a distribution to a legal or natural guardian or other relative of a minor or court-appointed representative of such incompetent. Alternatively, it may make a payment to any adult with whom the minor or incompetent temporarily or permanently resides. The receipt by a guardian, representative, relative or other person shall be a complete discharge of the Company and the Dominion Companies’ obligations under the Plan. The Company shall have no responsibility to see to the proper application of any payment so made. The Plan shall be binding on all successors and assigns of a Participant, including, without limitation, the estate of such participant and the executor, administrator or trustee of such estate, or any receiver or trustee in bankruptcy or representative of the Participant’s creditors.

m.    Unfunded Plan. Unless otherwise determined by the Committee, the Plan shall be unfunded and shall not create (or be construed to create) a trust or a separate fund or funds. The Plan shall not establish any fiduciary relationship between the Company and any Participant or other person. To the extent any person holds any rights by virtue of a Performance Grant granted under the Plan, such rights (unless otherwise determined by the Committee) shall be no greater than the rights of an unsecured general creditor of the Company.

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EXHIBIT A

DOMINION ENERGY, INC.

2019 PERFORMANCE GRANT PLAN

PERFORMANCE CRITERIA

Total Shareholder Return

Relative TSR Performance will be measured based on where the Company’s total shareholder return during the Performance Period ranks in relation to the total shareholder returns of the companies that are members of the Company’s compensation peer group as of the Date of Grant as set forth below (the “Comparison Companies”):

Ameren Corporation	Exelon Corporation
American Electric Power Company	FirstEnergy Corporation
CenterPoint Energy	NextEra Energy
Consolidated Edison Company	PG&E Corporation
DTE Energy Company	PPL Corporation
Duke Energy Corporation	Public Service Enterprise Group
Edison International	Southern Company
Entergy Corporation	Xcel Energy
Eversource Energy

The Comparison Companies shall be adjusted during the Performance Period as follows:

(i) In the event of a merger, acquisition or business combination transaction of a Comparison Company with or by another Comparison Company, effective upon the public announcement of the transaction, the surviving entity shall remain a Comparison Company and the non-surviving entity shall cease to be a Comparison Company (provided that, if the proposed transaction is subsequently terminated before the Relative TSR Performance is calculated, then the non-surviving company shall be retroactively reinstated as a Comparison Company);

(ii) If it is publicly announced that a Comparison Company will be acquired by another company that is not a Comparison Company, or in the event a “going private transaction” is publicly announced where the Comparison Company will not be the surviving entity or will otherwise no longer be publicly traded, the company shall cease to be a Comparison Company as of the date such announcement is made (provided that, if the proposed transaction is subsequently terminated before the Relative TSR Performance is calculated, then the company shall be retroactively reinstated as a Comparison Company);

(iii) In the event of a spinoff, divestiture, or sale of a substantial portion of assets of a Comparison Company, the Comparison Company shall no longer be a Comparison Company if the company’s reported revenue (in its GAAP accounts) for the four most recently reported quarters ending on or before the last day of the Performance Period falls below 40% of Dominion Energy’s reported revenue for the last year of the Performance Period; and

i

(iv) In the event of a bankruptcy of a Comparison Company, such company shall remain a Comparison Company and its stock price will continue to be tracked for purposes of Relative TSR Performance. If the company liquidates, it will remain a Comparison Company and its stock price will be reduced to zero for the remaining Performance Period.

Total shareholder return consists of the difference between the value of a share of common stock at the beginning and end of the Performance Period, plus the value of gross dividends paid as if reinvested in stock and other appropriate adjustments for such events as stock splits. For purposes of TSR Performance, the total shareholder return of the Company and the Comparison Companies will be calculated using Bloomberg¹. As soon as practicable after the completion of the Performance Period, the total shareholder returns of the Comparison Companies will be calculated and ranked from highest to lowest by the Committee. The Company’s total shareholder return will then be ranked in terms of which percentile it would have placed in among the Comparison Companies.

Absolute TSR Performance will be the Company’s total shareholder return on an average annual basis for the Performance Period.

Price-Earnings Ratio

Price-Earnings Ratio performance will be measured based on where the Company’s Price-Earnings Ratio ranks in relation to the Price-Earnings Ratios of the Comparison Companies. For purposes of Price-Earnings Ratio performance, the relative Price-Earnings Ratio performance of the Company and the Comparison Companies will be determined using such method as the Committee shall determine. As soon as practicable after the completion of the Performance Period, the Price-Earnings Ratios of the Comparison Companies will be determined and ranked from highest to lowest by the Committee, using three methods:

• First, using closing stock prices on the final day of the Performance Period divided by the operating earnings per share (“Operating EPS”) for the Company and the Comparison Companies over the most recently completed four-quarter period. If required based on the availability of data, the four quarters ended September 30² of the final year of the Performance Period can be utilized for estimating relative Price-Earnings Ratio performance.

• Second, using closing stock prices on the final day of the Performance Period divided by the estimated Operating EPS for the Company and the Comparison Companies for the final year of the Performance Period³.

• Third, using closing stock prices on the final day of the Performance Period divided by the estimated Operating EPS for the Company and the Comparison Companies for the following calendar year⁴.

¹  Specifically, using the function “CUST-TRR-RETURN-PER” or successor functions as defined by Bloomberg.

²  The source of quarterly operating earnings per share shall the companies’ quarterly earnings release statements.

³  The forward-looking P/E multiple shall be sourced from Bloomberg. Specifically, the closing stock price using the function “PX_LAST”, and the EPS using the function “EEPS_CURR_YR”, or successor functions as defined by Bloomberg.

⁴  The forward-looking P/E multiple shall be sourced from Bloomberg. Specifically, the closing stock price using the function “PX_LAST”, and the EPS using the function “EEPS_NXT_YR” or successor functions as defined by Bloomberg.

ii

For each method, the Company’s Price-Earnings Ratio will then be ranked in terms of which percentile it placed in among the Comparison Companies for the Committee’s determination. The Committee will, in its sole discretion, select which of the three methods to use to calculate final payouts under the Performance Grants.

Return on Invested Capital

Return on Invested Capital (ROIC)

The following terms are used to calculate ROIC for purposes of the 2019 Performance Grant:

ROIC means Total Return divided by Average Invested Capital. Performance will be calculated for the three successive fiscal years within the Performance Period, added together and then divided by three to arrive at an annual average ROIC for the Performance Period.

Total Return means Operating Earnings plus After-tax Interest & Related Charges, determined for each of the three successive fiscal years within the Performance Period.

Operating Earnings means operating earnings as disclosed on the Company’s earnings report furnished on Form 8-K for the applicable fiscal year.

Average Invested Capital means the Average Balances for Long & Short-term Debt plus Preferred Equity plus Common Shareholders’ Equity. The Average Balances for a year are calculated by performing the calculation at the end of each quarter during the fiscal year (including in the fiscal year’s opening balance sheet) and then averaging those amounts over five quarters. Long and short-term debt shall be as reported in the Company’s consolidated balance sheet prepared under GAAP, net of cash and cash equivalents.

Average Invested Capital will be calculated by excluding (i) accumulated other comprehensive income/(loss) from Common Shareholders’ Equity (as shown on the Company’s financial statements); (ii) impacts from changes in accounting principles that were not prescribed as of the Date of Grant; and (iii) the effects of incremental impacts from non-operating gains or losses during the Performance Period, as disclosed on the Company’s earnings report furnished on Form 8-K, that were not included in the projection on which the original ROIC calculation was based at the time of the grant.

iii

EX-10.43

EXHIBIT 10.43

DOMINION ENERGY, INC.

2019 GOAL-BASED STOCK AWARD AGREEMENT

THIS AGREEMENT, dated February 5, 2019, between Dominion Energy, Inc., a Virginia corporation (the “Company”) and [Insert Name] (“Participant”), is made pursuant and subject to the provisions of the Dominion Energy, Inc. 2014 Incentive Compensation Plan and any amendments thereto (the “Plan”). All terms used in this Agreement that are defined in the Plan have the same meaning given to such terms in the Plan.

1.    Goal-Based Stock Award. Pursuant to the Plan, [Insert Number] shares of Goal-Based Stock (“Target Amount”) were awarded to the Participant on February 5, 2019 (“Date of Grant”), subject to the terms and conditions of the Plan, and subject further to the terms and conditions set forth in this Agreement and Exhibit A attached hereto. Goal-Based Stock is Company Stock that will be issued if the Performance Goals set forth in Section 4 for the Performance Period are fulfilled. The actual number of shares of Goal-Based Stock that may be issued may be from 0% to 200% of the Target Amount, depending on the achievement of the Performance Goals. The Performance Period for purposes of this Agreement is the period beginning on January 1, 2019 and ending on December 31, 2021.

2.    Performance Achievement and Time of Goal-Based Stock Issuance. Upon the completion of the Performance Period, the Committee will determine the final achievement of the Performance Goals described in Section 4. The Company will then calculate the final number of Goal-Based Stock shares to be issued based on such Performance Goal achievement. Except as provided in Section 5(b) or 6, the appropriate number of Goal-Based Stock shares will be issued to the Participant at a time determined by the Committee, but not later than March 15, 2022.

3.    Forfeiture. Except as provided in Paragraphs 5 or 6, the Participant will forfeit any and all rights in the Goal-Based Stock if the Participant’s employment with the Company or a Dominion Company terminates for any reason before the end of the Performance Period.

4.    Performance Goals. Issuance of Goal-Based Stock shares will be based on the Performance Goal achievement of the Performance Criteria described in this Section 4 and further defined in Exhibit A.

a.    TSR Performance. Total Shareholder Return (TSR) Performance will determine fifty percent (50%) of the Target Amount (“TSR Percentage”). Relative TSR Performance and Absolute TSR Performance are each defined in Exhibit A. The percentage of the TSR Percentage of Goal-Based Stock shares that will be issued, if any, is based on the following table:

Relative TSR Performance Percentile Ranking	Percentage Payout of TSR Percentage
85th or above		200	%
50th		100	%
25th		50	%
Below 25th		0	%

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To the extent that the Company’s Relative TSR Performance ranks in a percentile between the 25^th and 85^th percentile in the table above, then the TSR Percentage payout will be interpolated between the corresponding TSR Percentage payout set forth above. No payment of the TSR Percentage of Goal-Based Stock shares will be made if the Relative TSR Performance is below the 25^th percentile, except that a payment of 25% of the TSR Percentage will be made if the Company’s Relative TSR Performance is below the 25^th percentile but its Absolute TSR Performance is at least 9%. In addition to the foregoing payments, and regardless of the Company’s Relative TSR Performance, either (but not both) of the following may be earned: (i) an additional payment of 25% of the TSR Percentage will be made if the Company’s Absolute TSR Performance is at least 10% but less than 15%, and/or if the Company’s Price-Earnings Ratio (as defined in Exhibit A) is at or above the 50^th percentile and below the top third of the group of companies (inclusive of the Company) used to measure Relative TSR Performance in accordance with Exhibit A hereto, or (ii) an additional payment of 50% of the TSR Percentage will be made if the Company’s Absolute TSR Performance is at least 15%, and/or if the Company’s Price-Earnings Ratio is at or above the top third of the group of companies (inclusive of the Company) used to measure Relative TSR Performance in accordance with Exhibit A hereto (in either case, the “Performance Adder”). The Committee may reduce or eliminate payment of the Performance Adder in its sole discretion.

The aggregate payments under this Section 4(a) may not exceed 250% of the TSR Percentage. In addition, the overall percentage payment under the entire Award may not exceed 200% of the Target Amount.

b.    ROIC Performance. Return on Invested Capital Performance (“ROIC Performance”) will determine fifty percent (50%) of the Target Amount (“ROIC Percentage”). ROIC Performance is defined in Exhibit A. The percentage of the ROIC Percentage that will be paid out, if any, is based on the following table:

ROIC Performance	Percentage Payout of ROIC Percentage
7.41% and above		200	%
7.13%		100	%
6.81%		50	%
Below 6.81%		0	%

• To the extent that the Company’s ROIC Performance is greater than 6.81% and less than 7.13%, the ROIC Percentage payout will be interpolated between the applicable Percentage Payout of ROIC Percentage range set forth above.

• To the extent that the Company’s ROIC Performance is greater than 7.13% and less than 7.41%, the ROIC Percentage payout will be interpolated between the applicable Percentage Payout of ROIC Percentage range set forth above.

5.    Retirement, Involuntary Termination without Cause, Death or Disability.

a.    Retirement or Involuntary Termination without Cause. Except as provided in Section 6, if the Participant Retires (as such term is defined in Section 9(b) below) during the Performance Period or if the Participant’s employment is involuntarily terminated by the Company or a Dominion Company without Cause (as defined in the Employment Continuity Agreement between the Participant and the Company) during the

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Performance Period and the Participant would have been eligible for a payment if the Participant had remained employed until the end of the Performance Period, the Participant will receive a pro-rated payout of the Participant’s Goal-Based Stock Award equal to the number of Goal-Based Stock shares the Participant would have received had the Participant remained employed until the end of the Performance Period, multiplied by a fraction, the numerator of which is the number of whole months from February 1, 2019 to the first day of the calendar month coinciding with or immediately following the date of the Participant’s Retirement or termination of employment, and the denominator of which is thirty-five (35). Shares will be issued after the end of the Performance Period at the time provided in Section 2 based on the Performance Goal achievement approved by the Committee. If the Participant Retires, however, no shares will be issued if the Company’s Chief Executive Officer in his sole discretion (or, if the Participant is the Company’s Chief Executive Officer, the Committee in its sole discretion) determines that the Participant’s Retirement is detrimental to the Company. Any potential shares of Goal-Based Stock not issued in accordance with the terms of this Paragraph 5(a) will be forfeited.

b.    Death or Disability. If, while employed by the Company or a Dominion Company, a Participant dies or becomes Disabled (as defined in Section 9(b) below) during the Performance Period, a number of Goal-Based Stock shares will be issued to the Participant or the Participant’s Beneficiary equal to the product of (i) and (ii) where:

(i)    is the number of shares that would be issued based on the predicted performance used for determining the compensation cost recognized by the Company for this Goal-Based Stock Award for the latest financial statement filed with the Company’s Annual Report on Form 10-K or Quarterly Report on Form 10-Q immediately prior to the event; and

(ii)    is a fraction, the numerator of which is the number of whole months from February 1, 2019 to the first day of the calendar month coinciding with or immediately following the date of the Participant’s death or Disability, and the denominator of which is thirty-five (35).

Any potential shares of Goal-Based Stock not issued in accordance with the terms of this Section 5(b) will be forfeited. Goal-Based Stock shares will be issued as soon as administratively feasible (and in any event within sixty (60) days) after the date of the Participant’s death or Disability.

6.    Qualifying Change of Control. Upon a Qualifying Change of Control prior to the end of the Performance Period, provided the Participant has remained continuously employed with the Company or a Dominion Company from the Date of Grant to the date of the Qualifying Change of Control, a number of the Goal-Based Stock shares will be issued to the Participant equal to the greater of (i) the Target Amount or (ii) the number of shares that would be issued at the end of the Performance Period if the predicted performance used for determining the compensation cost recognized by the Company for this Award for the latest financial statement filed with the Company’s Annual Report on Form 10-K or Quarterly Report on Form 10-Q immediately prior to the Qualifying Change of Control was the actual performance for the Performance Period (in either case, the “COC Payout Amount”). The Goal-Based Stock shares will be issued on or as soon as administratively feasible (but in any event within sixty (60) days) following the Qualifying Change of Control date. If a Qualifying Change of Control occurs prior to the end of the Performance Period and after a Participant has Retired or been involuntarily terminated without Cause pursuant to Section 5(a) above, then the Participant will receive a pro-

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rated payout of the Participant’s Goal-Based Stock Award, equal to the COC Payout Amount multiplied by the fraction set forth in Section 5(a) above, with shares being issued on or as soon as administratively feasible (but in any event within sixty (60) days) after the Qualifying Change of Control date. Any potential shares of Goal-Based Stock not issued in accordance with the terms of this Section 6 will be forfeited.

7.    Termination for Cause. Notwithstanding any provision of this Agreement to the contrary, if the Participant’s employment with the Company or a Dominion Company is terminated for Cause (as defined by the Employment Continuity Agreement between the Participant and the Company), the Participant will forfeit all rights to Goal-Based Stock shares awarded pursuant to this Agreement.

8.    Clawback of Award Payment.

a. Restatement of Financial Statements.    If the Company’s financial statements are required to be restated at any time within a two (2) year period following the end of the Performance Period as a result of fraud or intentional misconduct, the Committee may, in its discretion, based on the facts and circumstances surrounding the restatement, direct the Company to recover all or a portion of the issued (vested) shares from the Participant if the Participant’s conduct directly caused or partially caused the need for the restatement.

b. Fraudulent or Intentional Misconduct.    If the Company determines that the Participant has engaged in fraudulent or intentional misconduct related to or materially affecting the Company’s business operations or the Participant’s duties at the Company, the Committee may, in its discretion, based on the facts and circumstances surrounding the misconduct, direct the Company to withhold issuance of all or a portion of the Goal-Based Stock shares granted pursuant to this Agreement, or if shares have been issued, to recover all or a portion of the shares from the Participant.

c. Recovery of Payout.    The Company reserves the right to recover a Goal-Based Stock Award payout pursuant to this Section 8 by (i) seeking recovery of the vested shares from the Participant; (ii) reducing the amount that would otherwise be payable to the Participant under another Company benefit plan or compensation program to the extent permitted by applicable law; (iii) withholding future annual and long-term incentive awards or salary increases; or (iv) taking any combination of these actions.

d. No Limitation on Remedies.    The Company’s right to recover Goal-Based or issued shares pursuant to this Section 8 shall be in addition to, and not in lieu of, actions the Company may take to remedy or discipline a Participant’s misconduct including, but not limited to, termination of employment or initiation of a legal action for breach of fiduciary duty.

e. Subject to Future Rulemaking.    The Goal-Based Stock granted under this Agreement is subject to any clawback policies the Company may adopt in order to conform to the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and resulting rules issued

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by the Securities and Exchange Commission or national securities exchanges thereunder and that the Company determines should apply to this Agreement.

9.    Terms and Conditions.

a. Nontransferability; No Shareholder Rights. Except as provided in Section 5, this award of Goal-Based Stock is not transferable and is subject to a substantial risk of forfeiture until the end of the Performance Period. A Participant shall have not have any rights as a shareholder with respect to the shares of Goal-Based Stock that may be issued under this Agreement unless and until such shares have actually been issued to the Participant after the end of the Performance Period as provided herein.

b. Certain Definitions.

(i)    Retirement. For purposes of this Agreement, the term Retire or Retirement means a voluntary termination of employment on a date when the Participant is eligible for early or normal retirement benefits under the terms of the Company Pension Plan (as defined below), or would be eligible if any crediting of deemed additional years of age or service applicable to the Participant under a supplemental retirement plan of the Company was applied under the Company Pension Plan, as in effect at the time of the determination, or, for a Participant who is not eligible to participate in a Company Pension Plan, a voluntary termination of employment on or after age 55, unless (in each case) the Company’s Chief Executive Officer in his sole discretion (or, if the Participant is the Company’s Chief Executive Officer, the Committee in its sole discretion) determines that the Participant’s retirement is detrimental to the Company. “Company Pension Plan” means the applicable pension plan of the Company or its subsidiaries, if any, in which the Participant is eligible to participate as of the Date of Grant, which may include either the Dominion Energy Pension Plan or the SCANA Corporation Retirement Plan or any successor thereto, but excluding the cash balance portion of any such plan.

(ii)    Disabled or Disability. For purposes of this Agreement, the term “Disabled” or “Disability” means a disability as defined under Treasury Regulation Section 1.409A-3(i)(4). The Committee will determine whether or not a Disability exists and its determination will be conclusive and binding on the Participant.

c. Delivery of Shares.

(i)    Share Delivery. Within the applicable time periods after the end of the Performance Period or after the occurrence of an event described in Sections 5 or 6 as described above, the Company will deliver to the Participant (or in the event of the Participant’s death, the Participant’s Beneficiary) the appropriate number of shares of Company Stock.

(ii)    Withholding of Taxes. No Company Stock will be delivered until the Participant (or the Participant’s Beneficiary) has paid to the Company the amount that must be withheld under federal, state and local income and

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employment tax laws (the “Applicable Withholding Taxes”) or the Participant and the Company have made satisfactory arrangements for the payment of such taxes. Unless the Participant makes an alternative election, the Company will retain the number of shares of Goal-Based Stock (valued at their Fair Market Value) required to satisfy the Applicable Withholding Taxes. As an alternative to the Company retaining shares, the Participant or the Participant’s Beneficiary may elect to (i) deliver Mature Shares (valued at their Fair Market Value) or (ii) make a cash payment to satisfy Applicable Withholding Taxes.

d. Fractional Shares. Fractional shares of Company Stock will not be issued.

e. No Right to Continued Employment. This Agreement does not confer upon the Participant any right with respect to continuance of employment by the Company, nor will it interfere in any way with the right of the Company to terminate the Participant’s employment at any time.

f. Change in Capital Structure. The number and fair market value of shares of Goal-Based Stock awarded by this Agreement will be automatically adjusted as provided in Section 18(a) of the Plan if the Company has a change in capital structure.

g. Governing Law. This Agreement shall be governed by the laws of the Commonwealth of Virginia, other than its choice of law provisions.

h. Conflicts. In the event of any conflict between the provisions of the Plan and the provisions of this Agreement, the provisions of the Plan will govern.

i. Participant Bound by Plan. By accepting this Agreement, Participant hereby acknowledges receipt of a copy of the prospectus and Plan document accessible on the Company Intranet and agrees to be bound by all the terms and provisions thereof.

j. Binding Effect. This Agreement will be binding upon and inure to the benefit of the legatees, distributees, and personal representatives of the Participant and the successors of the Company.

k. Performance Goal Adjustments. Pursuant to Section 10(c) of the Plan, the Committee may at any time, in its sole discretion, remove or revise any performance goals or other performance objectives for this Goal-Based Stock Award. The Committee may exercise negative discretion to reduce payments under this Agreement as it deems appropriate.

l. Section 409A. This Agreement and the Goal-Based Stock award arrangement described herein is intended to comply with Section 409A of the Internal Revenue Code of 1986, as amended (“Code Section 409A”), and shall be interpreted to the maximum extent possible in accordance with such intent. To the extent necessary to comply with Code Section 409A, no payment will be made earlier than six months after a Participant’s termination of employment other than for death if the Award is subject to Code Section 409A and the Participant is a “specified employee” (within the meaning of Code Section 409A(a)(2)(B)(i)).

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EXHIBIT A

DOMINION ENERGY, INC.

2019 GOAL-BASED STOCK AWARD AGREEMENT

PERFORMANCE CRITERIA

Total Shareholder Return

Relative TSR Performance will be measured based on where the Company’s total shareholder return during the Performance Period ranks in relation to the total shareholder returns of the companies that are members of the Company’s compensation peer group as of the Date of Grant as set forth below (the “Comparison Companies”):

Ameren Corporation	Exelon Corporation
American Electric Power Company	FirstEnergy Corporation
CenterPoint Energy	NextEra Energy
Consolidated Edison Company	PG&E Corporation
DTE Energy Company	PPL Corporation
Duke Energy Corporation	Public Service Enterprise Group
Edison International	Southern Company
Entergy Corporation	Xcel Energy
Eversource Energy

The Comparison Companies shall be adjusted during the Performance Period as follows:

(i) In the event of a merger, acquisition or business combination transaction of a Comparison Company with or by another Comparison Company, effective upon the public announcement of the transaction, the surviving entity shall remain a Comparison Company and the non-surviving entity shall cease to be a Comparison Company (provided that, if the proposed transaction is subsequently terminated before the Relative TSR Performance is calculated, then the non-surviving company shall be retroactively reinstated as a Comparison Company);

(ii) If it is publicly announced that a Comparison Company will be acquired by another company that is not a Comparison Company, or in the event a “going private transaction” is publicly announced where the Comparison Company will not be the surviving entity or will otherwise no longer be publicly traded, the company shall cease to be a Comparison Company as of the date such announcement is made (provided that, if the proposed transaction is subsequently terminated before the Relative TSR Performance is calculated, then the company shall be retroactively reinstated as a Comparison Company);

(iii) In the event of a spinoff, divestiture, or sale of a substantial portion of assets of a Comparison Company, the Comparison Company shall no longer be a Comparison Company if the company’s reported revenue (in its GAAP accounts) for the four most recently reported quarters ending on or before the last day of the Performance Period falls below 40% of Dominion Energy’s reported revenue for last year of the Performance Period; and

(iv) In the event of a bankruptcy of a Comparison Company, such company shall remain a Comparison Company and its stock price will continue to be tracked for purposes of

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Relative TSR Performance. If the company liquidates, it will remain a Comparison Company and its stock price will be reduced to zero for the remaining Performance Period.

Total shareholder return consists of the difference between the value of a share of common stock at the beginning and end of the Performance Period, plus the value of gross dividends paid as if reinvested in stock and other appropriate adjustments for such events as stock splits. For purposes of TSR Performance, the total shareholder return of the Company and the Comparison Companies will be calculated using Bloomberg.¹ As soon as practicable after the completion of the Performance Period, the total shareholder returns of the Comparison Companies will be calculated and ranked from highest to lowest by the Committee. The Company’s total shareholder return will then be ranked in terms of which percentile it would have placed in among the Comparison Companies.

Absolute TSR Performance will be the Company’s total shareholder return on an average annual basis for the Performance Period.

Price-Earnings Ratio

Price-Earnings Ratio performance will be measured based on where the Company’s Price-Earnings Ratio ranks in relation to the Price-Earnings Ratios of the Comparison Companies. For purposes of Price-Earnings Ratio performance, the relative Price-Earnings Ratio performance of the Company and the Comparison Companies will be determined using such method as the Committee shall determine. As soon as practicable after the completion of the Performance Period, the Price-Earnings Ratios of the Comparison Companies will be determined and ranked from highest to lowest by the Committee, using three methods:

• First, using closing stock prices on the final day of the Performance Period divided by the operating earnings per share (“Operating EPS”) for the Company and the Comparison Companies over the most recently completed four-quarter period. If required based on the availability of data, the four quarters ended September 30² of the final year of the Performance Period can be utilized for estimating relative Price-Earnings Ratio performance.

• Second, using closing stock prices on the final day of the Performance Period divided by the estimated Operating EPS for the Company and the Comparison Companies for the final year of the Performance Period³.

• Third, using closing stock prices on the final day of the Performance Period divided by the estimated Operating EPS for the Company and the Comparison Companies for the following calendar year⁴.

¹  Specifically, using the function “CUST-TRR-RETURN-PER” or successor functions as defined by Bloomberg.

²  The source of quarterly operating earnings per share shall the companies’ quarterly earnings release statements.

³  The forward-looking P/E multiple shall be sourced from Bloomberg. Specifically, the closing stock price using the function “PX_LAST”, and the EPS using the function “EEPS_CURR_YR” or successor functions as defined by Bloomberg.

⁴  The forward-looking P/E multiple shall be sourced from Bloomberg. Specifically, the closing stock price using the function “PX_LAST”, and the EPS using the function “EEPS_NXT_YR” or successor functions as defined by Bloomberg.

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For each method, the Company’s Price-Earnings Ratio will then be ranked in terms of which percentile it placed in among the Comparison Companies for the Committee’s determination. The Committee will, in its sole discretion, select which of the three methods to use to calculate final payouts under the Performance Grants.

Return on Invested Capital

Return on Invested Capital (ROIC)

The following terms are used to calculate ROIC for purposes of the 2019 Goal-Based Stock Award:

ROIC means Total Return divided by Average Invested Capital. Performance will be calculated for the three successive fiscal years within the Performance Period, added together and then divided by three to arrive at an annual average ROIC for the Performance Period.

Total Return means Operating Earnings plus After-tax Interest & Related Charges, determined for each of the three successive fiscal years within the Performance Period.

Operating Earnings means operating earnings as disclosed on the Company’s earnings report furnished on Form 8-K for the applicable fiscal year.

Average Invested Capital means the Average Balances for Long & Short-term Debt plus Preferred Equity plus Common Shareholders’ Equity. The Average Balances for a year are calculated by performing the calculation at the end of each quarter during the fiscal year (including in the fiscal year’s opening balance sheet) and then averaging those amounts over five quarters. Long and short-term debt shall be as reported in the Company’s consolidated balance sheet prepared under GAAP, net of cash and cash equivalents.

Average Invested Capital will be calculated by excluding (i) accumulated other comprehensive income/(loss) from Common Shareholders’ Equity (as shown on the Company’s financial statements); (ii) impacts from changes in accounting principles that were not prescribed as of the Date of Grant; and (iii) the effects of incremental impacts from non-operating gains or losses during the Performance Period, as disclosed on the Company’s earnings report furnished on Form 8-K, that were not included in the projection on which the original ROIC calculation was based at the time of the grant.

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EX-10.44

EXHIBIT 10.44

DOMINION ENERGY, INC.

RESTRICTED STOCK AWARD AGREEMENT

PARTICIPANT	DATE OF GRANT	NUMBER OF SHARES OF RESTRICTED STOCK GRANTED
«First_Name» «Last_Name»	February 5, 2019	«##,###»
PERSONNEL NUMBER	VESTING DATE	VESTING SCHEDULE
		Vesting Date	Percentage
«#####»	February 1, 2022	February 1, 2022	100%

THIS AGREEMENT, effective as of the Date of Grant shown above, between Dominion Energy, Inc., a Virginia corporation (the “Company”) and the Participant named above is made pursuant and subject to the provisions of the Dominion Energy, Inc. 2014 Incentive Compensation Plan and any amendments thereto (the “Plan”). All terms used in this Agreement that are defined in the Plan have the same meaning given to such terms in the Plan.

1. Award of Stock. Pursuant to the Plan, the Number of Shares of Restricted Stock Granted shown above (the “Restricted Stock”) were awarded to the Participant on the Date of Grant shown above, subject to the terms and conditions of the Plan, and subject further to the terms and conditions set forth in this Agreement.

2. Vesting. Except as provided in Sections 3, 4, 5 or 6, one hundred percent (100%) of the shares of Restricted Stock awarded under this Agreement will vest on the Vesting Date shown above.

3. Forfeiture. Except as provided in Sections 4 or 5, the Participant will forfeit any and all rights in the Restricted Stock if the Participant’s employment with the Company or a Dominion Company terminates for any reason prior to the Vesting Date.

4. Death, Disability, Retirement or Involuntary Termination without Cause. Except as provided in Section 5, if the Participant terminates employment due to death, Disability, or Retirement (as such term is defined in Section 8(e)) before the Vesting Date or if the Participant’s employment is involuntarily terminated by the Company or a Dominion Company without Cause (as defined in the Employment Continuity Agreement between the Participant and the Company) before the Vesting Date, the Participant will become vested in the number of shares of Restricted Stock awarded under this Agreement multiplied by a fraction, the numerator of which is the number of whole months from February 1, 2019 to the first day of the month coinciding with or immediately following the date of the Participant’s termination of employment, and the denominator of which is the number of whole months from February 1, 2019 to the Vesting Date, rounded

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down to the nearest whole share. If the Participant Retires, however, the Participant’s Restricted Stock will not vest if the Company’s Chief Executive Officer in his sole discretion (or, if the Participant is the Company’s Chief Executive Officer, the Committee in its sole discretion) determines that the Participant’s Retirement is detrimental to the Company. The vesting will occur on the date of the Participant’s termination of employment due to death, Disability, Retirement, or termination by the Company without Cause. Any shares of Restricted Stock that do not vest in accordance with this Section 4 will be forfeited.

5. Change of Control. Upon a Change of Control prior to the Vesting Date, provided the Participant has remained continuously employed with the Company or a Dominion Company from the Date of Grant to the date of the Change of Control, the Participant’s rights in the Restricted Stock will become vested as follows:

a. A portion of the Restricted Stock will be immediately vested equal to the number of shares of Restricted Stock awarded under this Agreement multiplied by a fraction, the numerator of which is the number of whole months from February 1, 2019 to the Change of Control date, and the denominator of which is the number of whole months from February 1, 2019 to the Vesting Date, rounded down to the nearest whole share.

b. Unless previously forfeited, the remaining shares of Restricted Stock will become vested after a Change of Control at the earliest of the following events and in accordance with the terms described in subsections (i) through (iii) below:

(i) Vesting Date. All remaining shares of Restricted Stock will become vested on the Vesting Date.

(ii) Death, Disability or Retirement. If the Participant terminates employment due to death, Disability or Retirement (as defined in Section 8(e)) before the Vesting Date, the Participant will become vested in the remaining shares of Restricted Stock multiplied by a fraction, the numerator of which is the number of whole months from the first day of the month in which the Change of Control occurs to the first day of the month coinciding with or immediately following the Participant’s termination of employment, and the denominator of which is the number of whole months from the first day of the month in which the Change of Control occurs to the Vesting Date, rounded down to the nearest whole share. If the Participant Retires, however, the Participant’s Restricted Stock will not vest if the Company’s Chief Executive Officer in his sole discretion (or, if the Participant is the Company’s Chief Executive Officer, the Committee in its sole discretion) determines that the

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Participant’s Retirement is detrimental to the Company. The vesting will occur on the date of the Participant’s termination of employment due to death, Disability, or Retirement. Any shares of the Restricted Stock that do not vest in accordance with the terms of this subsection (ii) will be forfeited.

(iii) Involuntary Termination without Cause. All remaining shares of Restricted Stock will become vested upon the Participant’s involuntary termination by the Company or a Dominion Company without Cause before the Vesting Date, or upon the Participant’s Constructive Termination before the Vesting Date, as such terms are defined by the Employment Continuity Agreement between the Participant and the Company.

6. Termination for Cause. Notwithstanding any provision of this Agreement to the contrary, if the Participant’s employment with the Company or a Dominion Company is terminated for Cause (as defined by the Employment Continuity Agreement between the Participant and the Company), the Participant will forfeit all Restricted Stock shares awarded pursuant to this Agreement.

7. Clawback of Award Payment.

a. Restatement of Financial Statements. If the Company’s financial statements are required to be restated at any time within a two (2) year period following the Vesting Date as a result of fraud or intentional misconduct, the Committee may, in its discretion, based on the facts and circumstances surrounding the restatement, direct the Company to withhold issuance of all or a portion of the shares granted pursuant to this Agreement, or if shares have been issued, to recover all or a portion of the shares from the Participant if the Participant’s conduct directly caused or partially caused the need for the restatement.

b. Fraudulent or Intentional Misconduct. If the Company determines that the Participant has engaged in fraudulent or intentional misconduct related to or materially affecting the Company’s business operations or the Participant’s duties at the Company, the Committee may, in its discretion, based on the facts and circumstances surrounding the misconduct, direct the Company to withhold issuance of all or a portion of the shares granted pursuant to this Agreement, or if shares have been issued, to recover all or a portion of the shares from the Participant.

c. Recovery of Payout. The Company reserves the right to recover a Restricted Stock Award payout pursuant to this Section 7 by (i) seeking recovery of the vested shares from the Participant; (ii) reducing the amount that would otherwise be payable to the Participant under another Company benefit plan or compensation program to the extent permitted by

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applicable law; (iii) withholding future annual and long-term incentive awards or salary increases; or (iv) taking any combination of these actions.

d. No Limitation on Remedies. The Company’s right to recover Restricted Stock or issued shares pursuant to this Section 7 shall be in addition to, and not in lieu of, actions the Company may take to remedy or discipline a Participant’s misconduct including, but not limited to, termination of employment or initiation of a legal action for breach of fiduciary duty.

e. Subject to Future Rulemaking. The Restricted Stock granted under this Agreement is subject to any claw back policies the Company may adopt in order to conform to the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and resulting rules issued by the Securities and Exchange Commission or national securities exchanges thereunder and that the Company determines should apply to said Restricted Stock.

8. Terms and Conditions.

a. Nontransferability. Except as provided in Sections 4 and 5, the shares of Restricted Stock are not transferable and are subject to a substantial risk of forfeiture until the Vesting Date.

b. Uncertificated Shares; Power of Attorney. The Company may issue the Restricted Shares in uncertificated form. Such uncertificated shares shall be credited to a book entry account maintained by the Company (or its transfer agent) on behalf of the Participant. As a condition of accepting this award, the Participant hereby irrevocably appoints Dominion Energy Services, Inc., or its successor, as the Participant’s attorney-in-fact, with full power of substitution, to transfer (or provide instructions to the Company’s transfer agent to transfer) such shares on the Company’s books.

c. Custody of Share Certificates; Stock Power. The Company will retain custody of any share certificates for the Restricted Stock that may be issued until such shares vest or are forfeited. If share certificates are issued, the Participant shall execute and deliver a stock power, endorsed in blank, to Dominion Energy Services, Inc., with respect to such shares.

d. Shareholder Rights. The Participant will have the right to receive dividends and will have the right to vote the shares of Restricted Stock awarded under Section 1, both vested and unvested.

e. Retirement. For purposes of this Agreement, the term Retire or Retirement means a voluntary termination of employment on a date when the Participant is eligible for early or normal retirement benefits under the

4

terms of the Company Pension Plan (as defined below), or would be eligible if any crediting of deemed additional years of age or service applicable to the Participant under a supplemental retirement plan of the Company was applied under the Company Pension Plan, as in effect at the time of the determination, or, for a Participant who is not eligible to participate in a Company Pension Plan, a voluntary termination of employment on or after age 55, unless (in each case) the Company’s Chief Executive Officer in his sole discretion (or, if the Participant is the Company’s Chief Executive Officer, the Committee in its sole discretion) determines that the Participant’s retirement is detrimental to the Company. “Company Pension Plan” means the applicable pension plan of the Company or its subsidiaries, if any, in which the Participant is eligible to participate as of the Date of Grant, which may include either the Dominion Energy Pension Plan or the SCANA Corporation Retirement Plan or any successor thereto, but excluding the cash balance portion of any such plan.

f. Delivery of Shares.

(i) Share Delivery. On or as soon as administratively feasible after the Vesting Date or the date on which the shares of Restricted Stock have become vested due to the occurrence of an event described in Section 4 or 5, the Company will remove (or provide instructions to its transfer agents to remove) the transfer restrictions described herein, and (if any share certificate has been issued) shall deliver to the Participant (or in the event of the Participant’s death, the Participant’s Beneficiary) any such certificates free of the transfer restrictions described herein. The Company will also cancel any stock power covering such shares.

(ii) Withholding of Taxes. No Company Stock will be delivered until the Participant (or the Participant’s Beneficiary) has paid to the Company the amount that must be withheld under federal, state and local income and employment tax laws (the “Applicable Withholding Taxes”) or the Participant and the Company have made satisfactory arrangements for the payment of such taxes. Unless the Participant makes an alternative election, the Company will retain the number of shares of Restricted Stock (valued at their Fair Market Value) required to satisfy the Applicable Withholding Taxes. As an alternative to the Company retaining shares, the Participant or the Participant’s Beneficiary may elect to (i) deliver Mature Shares (valued at their Fair Market Value) or (ii) make a cash payment to satisfy Applicable Withholding Taxes.

g. Fractional Shares. Fractional shares of Company Stock will not be issued.

5

h. No Right to Continued Employment. This Agreement does not confer upon the Participant any right with respect to continuance of employment by the Company or a Dominion Company, nor shall it interfere in any way with the right of the Company or a Dominion Company to terminate the Participant’s employment at any time.

i. Change in Capital Structure. The number and fair market value of shares of Restricted Stock awarded by this Agreement shall be automatically adjusted as provided in Section 18(a) of the Plan if the Company has a change in capital structure.

j. Governing Law. This Agreement shall be governed by the laws of the Commonwealth of Virginia, other than its choice of law provisions.

k. Conflicts. In the event of any conflict between the provisions of the Plan and the provisions of this Agreement, the provisions of the Plan shall govern.

l. Participant Bound by Plan. By accepting this Agreement, Participant hereby acknowledges receipt of a copy of the prospectus and Plan document accessible on the Company Intranet and agrees to be bound by all the terms and provisions thereof.

m. Binding Effect. This Agreement shall be binding upon and inure to the benefit of the legatees, distributees, and personal representatives of the Participant and any successors of the Company.

6

EX-21

Exhibit 21

Dominion Energy, Inc.

Subsidiaries of the Registrant

As of February 15, 2019

Name	Jurisdiction of Incorporation	Name Under Which Business is Conducted
Dominion Energy, Inc.	Virginia	Dominion Energy, Inc.
CNG Coal Company	Delaware	CNG Coal Company
Dominion ACP Holding, Inc.	Virginia	Dominion ACP Holding, Inc.
Dominion Atlantic Coast Pipeline, LLC	Virginia	Dominion Atlantic Coast Pipeline, LLC
Dominion Alternative Energy Holdings, Inc.	Virginia	Dominion Alternative Energy Holdings, Inc.
Dominion Energy Technologies, Inc.	Virginia	Dominion Energy Technologies, Inc.
Dominion Energy Technologies II, Inc.	Virginia	Dominion Energy Technologies II, Inc.
Dominion Voltage, Inc.	Virginia	Dominion Voltage, Inc.         DVI
Tredegar Solar Fund I, LLC	Delaware	Tredegar Solar Fund I, LLC
Dominion Capital, Inc.	Virginia	Dominion Capital, Inc.
Dominion Cove Point, Inc.	Virginia	Dominion Cove Point, Inc.
Dominion Energy Cove Point LNG, LP	Delaware	Dominion Energy Cove Point LNG, LP
Dominion Energy Midstream GP, LLC	Delaware	Dominion Energy Midstream GP, LLC
Dominion Energy Midstream Partners, LP	Delaware	Dominion Energy Midstream Partners, LP
Cove Point GP Holding Company, LLC	Delaware	Cove Point GP Holding Company, LLC
Dominion Energy Cove Point LNG, LP	Delaware	Dominion Energy Cove Point LNG, LP
Dominion Energy Carolina Gas Transmission, LLC	South Carolina	Dominion Energy Carolina Gas Transmission, LLC
Dominion Energy Questar Pipeline, LLC	Utah	Dominion Energy Questar Pipeline, LLC
Dominion Energy Overthrust Pipeline, LLC	Utah	Dominion Energy Overthrust Pipeline, LLC
Questar Field Services, LLC	Utah	Questar Field Services, LLC
Questar White River Hub, LLC	Utah	Questar White River Hub, LLC
Iroquois GP Holding Company, LLC	Delaware	Iroquois GP Holding Company, LLC
Dominion Gas Projects Company, LLC	Delaware	Dominion Gas Projects Company, LLC
Dominion Energy Cove Point LNG, LP	Delaware	Dominion Energy Cove Point LNG, LP
Dominion MLP Holding Company, LLC	Delaware	Dominion MLP Holding Company, LLC
Dominion Energy Midstream Partners, LP	Delaware	Dominion Energy Midstream Partners, LP
Cove Point GP Holding Company, LLC	Delaware	Cove Point GP Holding Company, LLC
Dominion Energy Cove Point LNG, LP	Delaware	Dominion Energy Cove Point LNG, LP
Dominion Energy Carolina Gas Transmission, LLC	South Carolina	Dominion Energy Carolina Gas Transmission, LLC
Dominion Energy Questar Pipeline, LLC	Utah	Dominion Energy Questar Pipeline, LLC
Dominion Energy Overthrust Pipeline, LLC	Utah	Dominion Energy Overthrust Pipeline, LLC
Questar Field Services, LLC	Utah	Questar Field Services, LLC
Questar White River Hub, LLC	Utah	Questar White River Hub, LLC
Iroquois GP Holding Company, LLC	Delaware	Iroquois GP Holding Company, LLC
Dominion Energy BTM, Inc.	Virginia	Dominion Energy BTM, Inc.
Dominion Energy Marketplace, LLC	Virginia	Dominion Energy Marketplace, LLC
Dominion Energy Smart Home, LLC	Virginia	Dominion Energy Smart Home, LLC
Dominion Energy Carolina Gas Services, Inc.	Virginia	Dominion Energy Carolina Gas Services, Inc.
Dominion Energy Field Services, Inc.	Delaware	Dominion Energy Field Services, Inc.
Dominion Energy Fuel Services, Inc.	Virginia	Dominion Energy Fuel Services, Inc.
Dominion Energy Gas Holdings, LLC	Virginia	Dominion Energy Gas Holdings, LLC
Dominion Energy Transmission, Inc.	Delaware	Dominion Energy Transmission, Inc.
Dominion Brine, LLC	Delaware	Dominion Brine, LLC
Tioga Properties, LLC	Delaware	Tioga Properties, LLC

Farmington Properties, Inc.	Pennsylvania	Farmington Properties, Inc.
NE Hub Partners, L.L.C.	Delaware	NE Hub Partners, L.L.C.
NE Hub Partners, L.P.	Delaware	NE Hub Partners, L.P.
Dominion Gathering & Processing, Inc.	Virginia	Dominion Gathering & Processing, Inc.
Dominion Iroquois, Inc.	Delaware	Dominion Iroquois, Inc.
The East Ohio Gas Company	Ohio	Dominion Energy Ohio
Dominion Energy Payroll Company, Inc.	Virginia	Dominion Energy Payroll Company, Inc.
Dominion Energy Questar Corporation	Utah	Dominion Energy Questar Corporation
Dominion Energy Questar Pipeline Services, Inc.	Utah	Dominion Energy Questar Pipeline Services, Inc.
Dominion Energy Wexpro Services Company	Utah	Dominion Energy Wexpro Services Company
QPC Holding Company	Utah	QPC Holding Company
Dominion Energy Midstream Partners, LP	Delaware	Dominion Energy Midstream Partners, LP
Cove Point GP Holding Company, LLC	Delaware	Cove Point GP Holding Company, LLC
Dominion Energy Cove Point LNG, LP	Delaware	Dominion Energy Cove Point LNG, LP
Dominion Energy Carolina Gas Transmission, LLC	South Carolina	Dominion Energy Carolina Gas Transmission, LLC
Dominion Energy Questar Pipeline, LLC	Utah	Dominion Energy Questar Pipeline, LLC
Dominion Energy Overthrust Pipeline, LLC	Utah	Dominion Energy Overthrust Pipeline, LLC
Questar Field Services, LLC	Utah	Questar Field Services, LLC
Questar White River Hub, LLC	Utah	Questar White River Hub, LLC
Iroquois GP Holding Company, LLC	Delaware	Iroquois GP Holding Company, LLC
Questar InfoComm, Inc.	Utah	Questar InfoComm, Inc.
Questar Energy Services, Inc.	Utah	Questar Energy Services, Inc.
Questar Southern Trails Pipeline Company	Utah	Questar Southern Trails Pipeline Company
Questar Gas Company	Utah	Dominion Energy Utah (in Utah) Dominion Energy Wyoming (in Wyoming) Dominion Energy Idaho (in Idaho)
Wexpro Company	Utah	Dominion Energy Wexpro
Wexpro II Company	Utah	Wexpro II Company
Wexpro Development Company	Utah	Wexpro Development Company
Dominion Energy RNG Holdings, Inc.	Virginia	Dominion Energy RNG Holdings, Inc.
Dominion Energy Services, Inc.	Virginia	Dominion Energy Services, Inc.
Dominion Energy Solutions, Inc.	Delaware	Dominion Energy Solutions Dominion East Ohio Energy Dominion Peoples Plus
Dominion Energy Technical Solutions, Inc.	Virginia	Dominion Energy Technical Solutions, Inc.
Dominion Generation, Inc.	Virginia	Dominion Generation, Inc.
CNG Power Services Corporation	Delaware	CNG Power Services Corporation
Dominion Bridgeport Fuel Cell, LLC	Virginia	Dominion Bridgeport Fuel Cell, LLC
Dominion Cogen WV, Inc.	Virginia	Dominion Cogen WV, Inc.
Dominion Energy Generation Marketing, Inc.	Delaware	Dominion Energy Generation Marketing, Inc.
Dominion Energy Nuclear Connecticut, Inc.	Delaware	Dominion Energy Nuclear Connecticut, Inc.
Dominion Energy Solar CA, LLC	Delaware	Dominion Energy Solar CA, LLC
Dominion Energy Terminal Company, Inc.	Virginia	Dominion Energy Terminal Company, Inc.
Dominion Equipment, Inc.	Virginia	Dominion Equipment, Inc.
Dominion Equipment III, Inc.	Delaware	Dominion Equipment III, Inc.
Dominion Fairless Hills, Inc.	Delaware	Dominion Fairless Hills, Inc.
Dominion Mt. Storm Wind, LLC	Virginia	Dominion Mt. Storm Wind, LLC
Dominion North Star Generation, Inc.	Delaware	Dominion North Star Generation, Inc.
North Star Generation, LLC	Delaware	North Star Generation, LLC
Dominion Nuclear Projects, Inc.	Virginia	Dominion Nuclear Projects, Inc.
Dominion Energy Kewaunee, Inc.	Wisconsin	Dominion Energy Kewaunee, Inc.

Dominion Person, Inc.	Delaware	Dominion Person, Inc.
Dominion Solar Projects III, Inc.	Virginia	Dominion Solar Projects III, Inc.
Four Brothers Solar, LLC	Delaware	Four Brothers Solar, LLC
Enterprise Solar, LLC	Delaware	Enterprise Solar, LLC
Escalante Solar I, LLC	Delaware	Escalante Solar I, LLC
Escalante Solar II, LLC	Delaware	Escalante Solar II, LLC
Escalante Solar III, LLC	Delaware	Escalante Solar III, LLC
Granite Mountain Holdings, LLC	Delaware	Granite Mountain Holdings, LLC
Granite Mountain Solar East, LLC	Delaware	Granite Mountain Solar East, LLC
Granite Mountain Solar West, LLC	Delaware	Granite Mountain Solar West, LLC
Iron Springs Holdings, LLC	Delaware	Iron Springs Holdings, LLC
Iron Springs Solar, LLC	Delaware	Iron Springs Solar, LLC
Dominion Solar Projects VI, Inc.	Virginia	Dominion Solar Projects VI, Inc.
Dominion Solar Services, Inc.	Virginia	Dominion Solar Services, Inc.
Dominion State Line, LLC	Delaware	Dominion State Line, LLC
Dominion Wholesale, Inc.	Virginia	Dominion Wholesale, Inc.
Dominion Wind Projects, Inc.	Virginia	Dominion Wind Projects, Inc.
Dominion Fowler Ridge Wind, LLC	Virginia	Dominion Fowler Ridge Wind, LLC
Dominion Wind Development, LLC	Virginia	Dominion Wind Development, LLC
Prairie Fork Wind Farm, LLC	Virginia	Prairie Fork Wind Farm, LLC
Eagle Holdco Solar, LLC	Virginia	Eagle Holdco Solar, LLC
Eagle Solar, LLC	Virginia	Eagle Solar, LLC
Dominion Solar Projects C, Inc.	Virginia	Dominion Solar Projects C, Inc.
Dominion Solar Holdings IV, LLC	Virginia	Dominion Solar Holdings IV, LLC
96WI 8me LLC	Delaware	96WI 8me LLC
Clipperton Holdings LLC	North Carolina	Clipperton Holdings LLC
Fremont Farm, LLC	North Carolina	Fremont Farm, LLC
Innovative Solar 37, LLC	North Carolina	Innovative Solar 37, LLC
Moffett Solar 1, LLC	Delaware	Moffett Solar 1, LLC
Moorings Farm 2, LLC	North Carolina	Moorings Farm 2, LLC
Mustang Solar, LLC	North Carolina	Mustang Solar, LLC
Pikeville Farm, LLC	North Carolina	Pikeville Farm, LLC
Ridgeland Solar Farm I, LLC	Delaware	Ridgeland Solar Farm I, LLC
Siler Solar, LLC	North Carolina	Siler Solar, LLC
Wakefield Solar, LLC	North Carolina	Wakefield Solar, LLC
Dominion Solar Projects D, Inc.	Virginia	Dominion Solar Projects D, Inc.
Dominion Solar Holdings IV, LLC	Virginia	Dominion Solar Holdings IV, LLC
96WI 8me LLC	Delaware	96WI 8me LLC
Clipperton Holdings LLC	North Carolina	Clipperton Holdings LLC
Fremont Farm, LLC	North Carolina	Fremont Farm, LLC
Innovative Solar 37, LLC	North Carolina	Innovative Solar 37, LLC
Moffett Solar 1, LLC	Delaware	Moffett Solar 1, LLC
Moorings Farm 2, LLC	North Carolina	Moorings Farm 2, LLC
Mustang Solar, LLC	North Carolina	Mustang Solar, LLC
Pikeville Farm, LLC	North Carolina	Pikeville Farm, LLC
Ridgeland Solar Farm I, LLC	Delaware	Ridgeland Solar Farm I, LLC
Siler Solar, LLC	North Carolina	Siler Solar, LLC
Wakefield Solar, LLC	North Carolina	Wakefield Solar, LLC
Dominion Solar Projects IV, Inc.	Virginia	Dominion Solar Projects IV, Inc.
Eastern Shore Solar LLC	Delaware	Eastern Shore Solar LLC

Hecate Energy Cherrydale LLC	Delaware	Hecate Energy Cherrydale LLC
Hecate Energy Clarke County LLC	Delaware	Hecate Energy Clarke County LLC
Southampton Solar LLC	Delaware	Southampton Solar LLC
Virginia Solar 2017 Projects LLC	Delaware	Virginia Solar 2017 Projects LLC
Buckingham Solar I LLC	Delaware	Buckingham Solar I LLC
Correctional Solar LLC	Delaware	Correctional Solar LLC
Sappony Solar LLC	Delaware	Sappony Solar LLC
Scott-II Solar LLC	Delaware	Scott-II Solar LLC
Dominion Solar Projects V, Inc.	Virginia	Dominion Solar Projects V, Inc.
Summit Farms Solar, LLC	North Carolina	Summit Farms Solar, LLC
SBL Holdco, LLC	Virginia	SBL Holdco, LLC
Dominion Solar Projects A, Inc.	Virginia	Dominion Solar Projects A, Inc.
Dominion Solar Holdings I, LLC	Virginia	Dominion Solar Holdings I, LLC
Azalea Solar, LLC	Delaware	Azalea Solar, LLC
Dominion Solar Construction and Maintenance, LLC	Virginia	Dominion Solar Construction and Maintenance, LLC
Indy Solar Development, LLC	Delaware	Indy Solar Development, LLC
Indy Solar I, LLC	Delaware	Indy Solar I, LLC
Indy Solar II, LLC	Delaware	Indy Solar II, LLC
Indy Solar III, LLC	Delaware	Indy Solar III, LLC
Somers Solar Center, LLC	Delaware	Somers Solar Center, LLC
Dominion Solar Holdings II, LLC	Virginia	Dominion Solar Holdings II, LLC
CID Solar, LLC	Delaware	CID Solar, LLC
Dominion Solar Gen-Tie, LLC	Delaware	Dominion Solar Gen-Tie, LLC
Mulberry Farm, LLC	North Carolina	Mulberry Farm, LLC Mulberry Solar Farm, LLC
RE Adams East LLC	Delaware	RE Adams East LLC
RE Camelot LLC	Delaware	RE Camelot LLC
RE Columbia, LLC	Delaware	RE Columbia LLC
RE Columbia Two LLC	Delaware	RE Columbia Two LLC
RE Columbia, LLC	Delaware	RE Columbia LLC
RE Kansas LLC	Delaware	RE Kansas LLC
RE Kent South LLC	Delaware	RE Kent South LLC
RE Old River One LLC	Delaware	RE Old River One LLC
Selmer Farm, LLC	North Carolina	Selmer Farm, LLC
TA – Acacia, LLC	Delaware	TA – Acacia, LLC West Antelope Solar Park
Dominion Solar Projects B, Inc.	Virginia	Dominion Solar Projects B, Inc.
Dominion Solar Holdings I, LLC	Virginia	Dominion Solar Holdings I, LLC
Azalea Solar, LLC	Delaware	Azalea Solar, LLC
Dominion Solar Construction and Maintenance, LLC	Virginia	Dominion Solar Construction and Maintenance, LLC
Indy Solar Development, LLC	Delaware	Indy Solar Development, LLC
Indy Solar I, LLC	Delaware	Indy Solar I, LLC
Indy Solar II, LLC	Delaware	Indy Solar II, LLC
Indy Solar III, LLC	Delaware	Indy Solar III, LLC
Somers Solar Center, LLC	Delaware	Somers Solar Center, LLC
Dominion Solar Holdings II, LLC	Virginia	Dominion Solar Holdings II, LLC
CID Solar, LLC	Delaware	CID Solar, LLC
Dominion Solar Gen-Tie, LLC	Delaware	Dominion Solar Gen-Tie, LLC
Mulberry Farm, LLC	North Carolina	Mulberry Farm, LLC
		Mulberry Solar Farm, LLC
RE Adams East LLC	Delaware	RE Adams East LLC

RE Camelot LLC	Delaware	RE Camelot LLC
RE Columbia LLC	Delaware	RE Columbia LLC
RE Columbia Two LLC	Delaware	RE Columbia Two LLC
RE Columbia LLC	Delaware	RE Columbia LLC
RE Kansas LLC	Delaware	RE Kansas LLC
RE Kent South LLC	Delaware	RE Kent South LLC
RE Old River One LLC	Delaware	RE Old River One LLC
Selmer Farm, LLC	North Carolina	Selmer Farm, LLC
TA – Acacia, LLC	Delaware	TA – Acacia, LLC
		West Antelope Solar Park
Dominion Solar Projects I, Inc.	Virginia	Dominion Solar Projects I, Inc.
Dominion Solar Holdings III, LLC	Virginia	Dominion Solar Holdings III, LLC
Alamo Solar, LLC	California	Alamo Solar, LLC
Catalina Solar 2, LLC	Delaware	Catalina Solar 2, LLC
Cottonwood Solar, LLC	Delaware	Cottonwood Solar, LLC
Imperial Valley Solar Company (IVSC) 2, LLC	California	Imperial Valley Solar Company (IVSC) 2, LLC
Maricopa West Solar PV, LLC	Delaware	Maricopa West Solar PV, LLC
Pavant Solar LLC	Delaware	Pavant Solar LLC
Richland Solar Center, LLC	Georgia	Richland Solar Center, LLC
Dominion Solar Projects II, Inc.	Virginia	Dominion Solar Projects II, Inc.
Dominion Solar Holdings III, LLC	Virginia	Dominion Solar Holdings III, LLC
Alamo Solar, LLC	California	Alamo Solar, LLC
Catalina Solar 2, LLC	Delaware	Catalina Solar 2, LLC
Cottonwood Solar, LLC	Delaware	Cottonwood Solar, LLC
Imperial Valley Solar Company (IVSC) 2, LLC	California	Imperial Valley Solar Company (IVSC) 2, LLC
Maricopa West Solar PV, LLC	Delaware	Maricopa West Solar PV, LLC
Pavant Solar LLC	Delaware	Pavant Solar LLC
Richland Solar Center, LLC	Georgia	Richland Solar Center, LLC
Dominion Greenbrier, Inc.	Virginia	Dominion Greenbrier, Inc.
Greenbrier Pipeline Company, LLC	Delaware	Greenbrier Pipeline Company, LLC
Greenbrier Marketing Company, LLC	Delaware	Greenbrier Marketing Company, LLC
Dominion High Voltage Holdings, Inc.	Virginia	Dominion High Voltage Holdings, Inc.
Dominion High Voltage MidAtlantic, Inc.	Virginia	Dominion High Voltage MidAtlantic, Inc.
Dominion Investments, Inc.	Virginia	Dominion Investments, Inc.
Dominion Keystone Pipeline Holdings, Inc.	Delaware	Dominion Keystone Pipeline Holdings, Inc.
Dominion Keystone Pipeline, LLC	Delaware	Dominion Keystone Pipeline, LLC
Dominion MLP Holding Company II, Inc.	Virginia	Dominion MLP Holding Company II, Inc.
Dominion MLP Holding Company III, Inc.	Virginia	Dominion MLP Holding Company III, Inc.
Dominion Modular LNG Holdings, Inc.	Virginia	Dominion Modular LNG Holdings, Inc.
Niche LNG, LLC	Delaware	Niche LNG, LLC
Dominion Oklahoma Texas Exploration & Production, Inc.	Delaware	Dominion Oklahoma Texas Exploration & Production, Inc.
Dominion Privatization Holdings, Inc.	Virginia	Dominion Privatization Holdings, Inc.
Dominion Privatization Florida, LLC	Virginia	Dominion Privatization Florida, LLC
Dominion Privatization Georgia, LLC	Virginia	Dominion Privatization Georgia, LLC
Dominion Privatization Kentucky, LLC	Virginia	Dominion Privatization Kentucky, LLC
Dominion Privatization South Carolina, LLC	Virginia	Dominion Privatization South Carolina, LLC
Dominion Privatization Texas, LLC	Virginia	Dominion Privatization Texas, LLC
Dominion Privatization Virginia, LLC	Virginia	Dominion Privatization Virginia, LLC
Dominion Products and Services, Inc.	Delaware	Dominion Products and Services, Inc.
		Dominion Energy Solutions

Dominion Projects Services, Inc.	Virginia	Dominion Projects Services, Inc.
Dominion Resources Capital Trust III	Delaware	Dominion Resources Capital Trust III
Hope Gas, Inc.	West Virginia	Dominion Energy West Virginia
SCANA Corporation	South Carolina	SCANA Corporation
Public Service Company of North Carolina, Incorporated	South Carolina	Public Service Company of North Carolina, Incorporated
Clean Energy Enterprises, Inc.	North Carolina	Clean Energy Enterprises, Inc.
PSNC Blue Ridge Corporation	North Carolina	PSNC Blue Ridge Corporation
PSNC Cardinal Pipeline Company	North Carolina	PSNC Cardinal Pipeline Company
PSNC Southgate, LLC	South Carolina	PSNC Southgate, LLC
SCANA Communications Holdings, Inc.	South Carolina	SCANA Communications Holdings, Inc.
SCANA Corporate Security Services, Inc.	South Carolina	SCANA Corporate Security Services, Inc.
SCANA Energy Marketing, Inc.	South Carolina	SCANA Energy Marketing, Inc.
SCANA Services, Inc.	South Carolina	SCANA Services, Inc.
SCANA Pharmacy LLC	South Carolina	SCANA Pharmacy LLC
South Carolina Electric & Gas Company	South Carolina	South Carolina Electric & Gas Company
SRFI, LLC	South Carolina	SRFI, LLC
South Carolina Fuel Company, Inc.	South Carolina	South Carolina Fuel Company, Inc.
South Carolina Generating Company, Inc.	South Carolina	South Carolina Generating Company, Inc.
Virginia Electric and Power Company	Virginia	Dominion Energy Virginia (in Virginia)
		Dominion Energy North Carolina (in North Carolina)
Virginia Power Fuel Corporation	Virginia	Virginia Power Fuel Corporation
Virginia Power Services, LLC	Virginia	Virginia Power Services, LLC
Virginia Power Nuclear Services Company	Virginia	Virginia Power Nuclear Services Company
Virginia Power Services Energy Corp., Inc.	Virginia	Virginia Power Services Energy Corp., Inc.
VP Property, Inc.	Virginia	VP Property, Inc.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-216476, 333-219088 and 333-221291 on Form S-3 and Registration Statement Nos. 033-62705, 333-02733, 333-09167, 333-18391, 333-25587, 333-49725, 333-78173, 333-85094, 333-87529, 333-95795, 333-110332, 333-124256, 333-124257, 333-130566, 333-130570, 333-143916, 333-149989, 333-149993, 333-156027, 333-163805, 333-189578, 333-189579, 333-189580, 333-189581, 333-195768, 333-202364, 333-202366, 333-203952, 333-226041, 333-226039, 333-223265 and 333-223264 on Form S-8 of our reports dated February 28, 2019, relating to the consolidated financial statements of Dominion Energy, Inc. and subsidiaries and the effectiveness of Dominion Energy, Inc. and subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Dominion Energy, Inc. for the year ended December 31, 2018.

We consent to the incorporation by reference in Registration Statement No. 333-219085 on Form S-3 of our report dated February 28, 2019, relating to the consolidated financial statements of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Energy, Inc.) and subsidiaries, appearing in this Annual Report on Form 10-K of Virginia Electric and Power Company for the year ended December 31, 2018.

We consent to the incorporation by reference in Registration Statement No. 333-219086 on Form S-3 of our report dated February 28, 2019, relating to the consolidated financial statements of Dominion Energy Gas Holdings, LLC (a wholly-owned subsidiary of Dominion Energy, Inc.) and subsidiaries, appearing in this Annual Report on Form 10-K of Dominion Energy Gas Holdings, LLC for the year ended December 31, 2018.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2019

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-216476, 333-219088 and 333-221291 on Form S-3 and Registration Statement Nos. 033-62705, 333-02733, 333-09167, 333-18391, 333-25587, 333-49725, 333-78173, 333-85094, 333-87529, 333-95795, 333-110332, 333-124256, 333-124257, 333-130566, 333-130570, 333-143916, 333-149989, 333-149993, 333-156027, 333-163805, 333-189578, 333-189579, 333-189580, 333-189581, 333-195768, 333-202364, 333-202366, 333-203952, 333-226041, 333-226039, 333-223265 and 333-223264 on Form S-8 of our reports dated February 28, 2019, relating to the consolidated financial statements and financial statement schedule of SCANA Corporation and subsidiaries (the “Company”), and the effectiveness of the Company’s internal control over financial reporting, (which reports express an unqualified opinion), incorporated by reference in this Annual Report on Form 10-K of Dominion Energy, Inc. for the year ended December 31, 2018.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

February 28, 2019

EX-31.A

Exhibit 31.a

I, Thomas F. Farrell, II, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 28, 2019	/s/ Thomas F. Farrell, II
	Thomas F. Farrell, II President and Chief Executive Officer

EX-31.B

Exhibit 31.b

I, James R. Chapman, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 28, 2019	/s/ James R. Chapman
	James R. Chapman Executive Vice President, Chief Financial Officer and Treasurer

EX-31.C

Exhibit 31.c

I, Thomas F. Farrell, II, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 28, 2019	/s/ Thomas F. Farrell, II
	Thomas F. Farrell, II Chief Executive Officer

EX-31.D

Exhibit 31.d

I, James R. Chapman, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 28, 2019	/s/ James R. Chapman
	James R. Chapman Executive Vice President, Chief Financial Officer and Treasurer

EX-31.E

Exhibit 31.e

I, Thomas F. Farrell, II, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 28, 2019	/s/ Thomas F. Farrell, II
	Thomas F. Farrell, II Chief Executive Officer

EX-31.F

Exhibit 31.f

I, James R. Chapman, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 28, 2019	/s/ James R. Chapman
	James R. Chapman Executive Vice President, Chief Financial Officer and Treasurer

EX-32.A

Exhibit 32.a

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

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

1. the Annual Report on Form 10-K for the year ended December 31, 2018 (the “Report”), of the Company to which this certification is an exhibit fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of December 31, 2018, and for the period then ended.

/s/ Thomas F. Farrell, II

Thomas F. Farrell, II
President and Chief Executive Officer
February 28, 2019

/s/ James R. Chapman

James R. Chapman
Executive Vice President,
Chief Financial Officer and Treasurer
February 28, 2019

EX-32.B

Exhibit 32.b

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

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

1. the Annual Report on Form 10-K for the year ended December 31, 2018 (the “Report”), of the Company to which this certification is an exhibit fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of December 31, 2018, and for the period then ended.

/s/ Thomas F. Farrell, II

Thomas F. Farrell, II

Chief Executive Officer

February 28, 2019

/s/ James R. Chapman

James R. Chapman
Executive Vice President,
Chief Financial Officer and Treasurer
February 28, 2019

EX-32.C

Exhibit 32.c

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

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

1. the Annual Report on Form 10-K for the year ended December 31, 2018 (the “Report”), of the Company to which this certification is an exhibit fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of December 31, 2018, and for the period then ended.

/s/ Thomas F. Farrell, II

Thomas F. Farrell, II
Chief Executive Officer
February 28, 2019

/s/ James R. Chapman

James R. Chapman
Executive Vice President,
Chief Financial Officer and Treasurer
February 28, 2019

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 15, 2019	Jun. 30, 2018
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Trading Symbol	D
Entity Registrant Name	DOMINION ENERGY INC /VA/
Entity Central Index Key	0000715957
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		799,313,999
Entity Public Float			$ 44,400,000,000
Virginia Electric and Power Company
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Trading Symbol	VEL - PE
Entity Registrant Name	VIRGINIA ELECTRIC & POWER CO
Entity Central Index Key	0000103682
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		274,723
Entity Public Float			0
Dominion Energy Gas Holdings, LLC
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Entity Registrant Name	Dominion Energy Gas Holdings, LLC
Entity Central Index Key	0001603291
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		799,314,079
Entity Public Float			$ 0

XML

Consolidated Statements of Income - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating revenue	[1]	$ 13,366	$ 12,586	$ 11,737
Operating Expenses
Electric fuel and other energy-related purchases		2,814	2,301	2,333
Purchased electric capacity		122	6	99
Purchased gas		645	701	459
Other operations and maintenance		3,458	3,200	3,279
Depreciation and amortization		2,000	1,905	1,559
Other taxes		703	668	596
Impairment of assets and related charges		403	15	4
Gains on sales of assets		(380)	(147)	(40)
Total operating expenses		9,765	8,649	8,289
Income from operations		3,601	3,937	3,448
Earnings from equity method investee		197	(18)	111
Other income	[1]	1,021	358	429
Interest and related charges		1,493	1,205	1,010
Income from operations before income tax expense		3,129	3,090	2,867
Income tax expense		580	(30)	655
Net Income Including Noncontrolling Interests		2,549	3,120	2,212
Noncontrolling Interests		102	121	89
Net Income		$ 2,447	$ 2,999	$ 2,123
Earnings Per Common Share
Net income attributable to Dominion Energy-Basic		$ 3.74	$ 4.72	$ 3.44
Net income attributable to Dominion Energy-Diluted		$ 3.74	$ 4.72	$ 3.44
Virginia Electric and Power Company
Operating revenue	[2]	$ 7,619	$ 7,556	$ 7,588
Operating Expenses
Electric fuel and other energy-related purchases	[2]	2,318	1,909	1,973
Purchased electric capacity		122	6	99
Affiliated suppliers		305	309	310
Other		1,371	1,169	1,547
Depreciation and amortization		1,132	1,141	1,025
Other taxes		300	290	284
Total operating expenses		5,548	4,824	5,238
Income from operations		2,071	2,732	2,350
Other income		22	76	56
Interest and related charges	[2]	511	494	461
Income from operations before income tax expense		1,582	2,314	1,945
Income tax expense		300	774	727
Net Income		1,282	1,540	1,218
Dominion Energy Gas Holdings, LLC
Operating revenue	[3]	1,940	1,814	1,638
Operating Expenses
Purchased gas	[3]	40	132	109
Other energy-related purchases		135	21	12
Affiliated suppliers		94	87	81
Other	[3]	665	578	514
Depreciation and amortization		244	227	204
Other taxes		200	185	170
Impairment of assets and related charges		346	16
Gains on sales of assets		(119)	(70)	(45)
Total operating expenses		1,605	1,176	1,045
Income from operations		335	638	593
Earnings from equity method investee		24	21	21
Other income		133	104	87
Interest and related charges	[3]	105	97	94
Income from operations before income tax expense		387	666	607
Income tax expense		86	51	215
Net Income		$ 301	$ 615	$ 392

[1] See Note 9 for amounts attributable to related parties.

[2] See Note 24 for amounts attributable to affiliates.

[3] See Note 24 for amounts attributable to related parties.

XML

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net income including noncontrolling interests	$ 2,549	$ 3,120	$ 2,212
Net income	2,447	2,999	2,123
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of tax	30	8	55
Changes in unrealized net gains (losses) on investment securities, net of tax	(18)	215	93
Changes in net unrecognized pension and other postretirement benefit (costs), net of tax	(215)	(69)	(319)
Amounts reclassified to net income (loss):
Net derivative (gains) losses-hedging activities, net of tax	102	(29)	(159)
Net realized (gains) losses on investment securities, net of tax	5	(37)	(28)
Net pension and other postretirement benefit costs, net of tax	78	50	34
Changes in other comprehensive gains (losses) from equity method investees, net of tax	1	3	(1)
Total other comprehensive income (loss)	(17)	141	(325)
Comprehensive income including noncontrolling interests	2,532	3,261	1,887
Comprehensive income attributable to noncontrolling interests	103	122	89
Comprehensive income	2,429	3,139	1,798
Virginia Electric and Power Company
Net income	1,282	1,540	1,218
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of tax	1	(5)	(2)
Changes in unrealized net gains (losses) on investment securities, net of tax		24	11
Amounts reclassified to net income (loss):
Net derivative (gains) losses-hedging activities, net of tax	1	1	1
Net realized (gains) losses on investment securities, net of tax		(4)	(4)
Total other comprehensive income (loss)	2	16	6
Comprehensive income	1,284	1,556	1,224
Dominion Energy Gas Holdings, LLC
Net income	301	615	392
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of tax	(17)	5	(16)
Changes in net unrecognized pension and other postretirement benefit (costs), net of tax	(52)	20	(20)
Amounts reclassified to net income (loss):
Net derivative (gains) losses-hedging activities, net of tax	20	(4)	9
Net pension and other postretirement benefit costs, net of tax	4	4	3
Total other comprehensive income (loss)	(45)	25	(24)
Comprehensive income	$ 256	$ 640	$ 368

XML

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net deferred gains (losses) on derivative-hedging activities, tax	$ (10)	$ (3)	$ (37)
Changes in unrealized net gains (losses) on investment securities, tax	5	(121)	(53)
Changes in net unrecognized pension and other postretirement benefit costs, tax	75	32	189
Net derivative (gains) losses on derivative-hedging activities, tax	(35)	18	100
Net realized (gains) losses on investment securities, tax	(2)	21	15
Net pension and other postretirement benefit costs, tax	(21)	(32)	(22)
Changes in other comprehensive income (loss) from equity method investees, tax	(1)	(2)
Virginia Electric and Power Company
Net deferred gains (losses) on derivative-hedging activities, tax	(1)	3	1
Changes in unrealized net gains (losses) on investment securities, tax		(16)	(7)
Net realized (gains) losses on investment securities, tax		3	2
Dominion Energy Gas Holdings, LLC
Net deferred gains (losses) on derivative-hedging activities, tax	6	(3)	10
Changes in net unrecognized pension and other postretirement benefit costs, tax	20	(8)	14
Net derivative (gains) losses on derivative-hedging activities, tax	(7)	3	(6)
Net pension and other postretirement benefit costs, tax	$ (2)	$ (2)	$ (2)

XML

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents		$ 268	$ 120
Customer receivables (less allowance for doubtful accounts)		1,749	1,660
Other receivables (less allowance for doubtful accounts)	[1]	331	126
Inventories
Materials and supplies		1,039	1,049
Fossil fuel		287	328
Gas stored		92	100
Prepayments		265	260
Regulatory assets		496	294
Other		634	397
Total current assets		5,161	4,334
Investments
Nuclear decommissioning trust funds		4,938	5,093
Investment in equity method affiliates		1,278	1,544
Other		344	327
Total investments		6,560	6,964
Property, Plant and Equipment
Property, plant and equipment		76,578	74,823
Accumulated depreciation, depletion and amortization		(22,018)	(21,065)
Total property, plant and equipment, net		54,560	53,758
Deferred Charges and Other Assets
Goodwill	[2]	6,410	6,405
Pension and other postretirement benefit assets		1,279	1,378
Intangible assets, net		670	685
Regulatory assets		2,676	2,480
Other		598	581
Total deferred charges and other assets		11,633	11,529
Total assets		77,914	76,585
Current Liabilities
Securities due within one year		3,624	3,078
Credit facility borrowings	[3]	73
Short-term debt		334	3,298
Accounts payable		914	875
Accrued interest, payroll and taxes		836	848
Regulatory liabilities	[4]	356	193
Other		1,866	1,537
Total current liabilities		7,647	9,636
Long-Term Debt
Long-term debt		26,328	25,588
Junior subordinated notes		3,430	3,981
Remarketable subordinated notes		1,386	1,379
Total long-term debt		31,144	30,948
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		5,116	4,523
Regulatory liabilities		6,840	6,916
Asset retirement obligations		2,250	2,169
Pension and other postretirement benefit liability		2,328	2,160
Other	[1]	541	863
Total deferred credits and other liabilities		17,075	16,631
Total liabilities		55,866	57,215
Commitments and Contingencies (see Note 22)
Common Shareholder's Equity
Common stock - no par	[5]	12,588	9,865
Retained earnings		9,219	7,936
Accumulated other comprehensive income (loss)		(1,700)	(659)
Total common shareholder's equity		20,107	17,142
Noncontrolling interests		1,941	2,228
Total equity		22,048	19,370
Total liabilities and equity		77,914	76,585
Virginia Electric and Power Company
Current Assets
Cash and cash equivalents		29	14
Customer receivables (less allowance for doubtful accounts)		999	951
Other receivables (less allowance for doubtful accounts)		76	64
Affiliated receivables		101	3
Inventories
Materials and supplies		550	531
Fossil fuel		287	319
Prepayments		28	27
Regulatory assets		424	205
Other	[6]	77	110
Total current assets		2,571	2,224
Investments
Nuclear decommissioning trust funds		2,369	2,399
Other		3	3
Total investments		2,372	2,402
Property, Plant and Equipment
Property, plant and equipment		44,524	42,329
Accumulated depreciation, depletion and amortization		(14,003)	(13,277)
Total property, plant and equipment, net		30,521	29,052
Deferred Charges and Other Assets
Pension and other postretirement benefit assets	[6]	254	199
Intangible assets, net		250	233
Regulatory assets		737	810
Other	[6]	175	219
Total deferred charges and other assets		1,416	1,461
Total assets		36,880	35,139
Current Liabilities
Securities due within one year		350	850
Short-term debt		314	542
Accounts payable		339	361
Payables to affiliates		209	125
Affiliated current borrowings		224	33
Accrued interest, payroll and taxes		248	256
Asset retirement obligations		245	216
Regulatory liabilities		299	127
Other	[6]	587	410
Total current liabilities		2,815	2,920
Long-Term Debt
Long-Term Debt		11,321	10,496
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		3,017	2,728
Regulatory liabilities		4,647	4,760
Asset retirement obligations		1,200	1,149
Pension and other postretirement benefit liability	[6]	632	505
Other		201	357
Total deferred credits and other liabilities		9,697	9,499
Total liabilities		23,833	22,915
Commitments and Contingencies (see Note 22)
Common Shareholder's Equity
Common stock - no par	[7]	5,738	5,738
Other paid-in capital		1,113	1,113
Retained earnings		6,208	5,311
Accumulated other comprehensive income (loss)		(12)	62
Total common shareholder's equity		13,047	12,224
Total equity		13,047	12,224
Total liabilities and equity		36,880	35,139
Dominion Energy Gas Holdings, LLC
Current Assets
Cash and cash equivalents		10	4
Customer receivables (less allowance for doubtful accounts)	[8]	309	297
Other receivables (less allowance for doubtful accounts)	[8]	17	15
Affiliated receivables		10	10
Inventories
Materials and supplies		53	55
Gas stored		12	9
Prepayments		116	112
Regulatory assets	[9]	29	26
Gas imbalances	[8]	162	46
Other	[8]	58	52
Total current assets		747	600
Investments
Investment in equity method affiliates		91	95
Total investments		93	97
Property, Plant and Equipment
Property, plant and equipment		11,238	11,173
Accumulated depreciation, depletion and amortization		(2,971)	(3,018)
Total property, plant and equipment, net		8,267	8,155
Deferred Charges and Other Assets
Goodwill	[2]	547	542
Pension and other postretirement benefit assets	[8]	1,775	1,828
Intangible assets, net		109	109
Regulatory assets		727	511
Other	[8]	86	98
Total deferred charges and other assets		3,244	3,088
Total assets		12,351	11,940
Current Liabilities
Securities due within one year		449
Short-term debt		10	629
Accounts payable		196	193
Payables to affiliates		65	62
Affiliated current borrowings		218	18
Accrued interest, payroll and taxes		265	250
Regulatory liabilities	[4]	21	38
Other	[8]	198	189
Total current liabilities		1,401	1,341
Long-Term Debt
Long-Term Debt		3,609	3,570
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		1,465	1,454
Regulatory liabilities		1,285	1,227
Other	[8]	194	185
Total deferred credits and other liabilities		2,944	2,866
Total liabilities		7,954	7,777
Commitments and Contingencies (see Note 22)
Common Shareholder's Equity
Membership interests		4,566	4,261
Accumulated other comprehensive income (loss)		(169)	(98)
Total equity		4,397	4,163
Total equity		4,397	4,163
Total liabilities and equity		$ 12,351	$ 11,940

[1] See Note 9 for amounts attributable to related parties.

[2] Goodwill amounts do not contain any accumulated impairment losses.

[3] In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy's Consolidated Balance Sheets at December 31, 2018.

[4] Current regulatory liabilities are presented in other current liabilities in Dominion Energy and Dominion Energy Gas' Consolidated Balance Sheets.

[5] 1 billion shares authorized; 681 million shares and 645 million shares outstanding at December 31, 2018 and 2017, respectively.

[6] See Note 24 for amounts attributable to affiliates.

[7] 500,000 shares authorized; 274,723 shares outstanding at December 31, 2018 and 2017.

[8] See Note 24 for amounts attributable to related parties.

[9] Current regulatory assets are presented in other current assets in Dominion Energy Gas' Consolidated Balance Sheets.

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Customer receivables, allowance for doubtful accounts		$ 14	$ 17
Other receivables, allowance for doubtful accounts	[1]	$ 4	$ 2
Common stock, shares authorized		1,000,000,000	1,000,000,000
Common stock, shares outstanding		681,000,000	645,000,000
Virginia Electric and Power Company
Customer receivables, allowance for doubtful accounts		$ 9	$ 10
Other receivables, allowance for doubtful accounts		$ 3	$ 1
Common stock, shares authorized		500,000	500,000
Common stock, shares outstanding		274,723	274,723
Dominion Energy Gas Holdings, LLC
Customer receivables, allowance for doubtful accounts	[2]	$ 1	$ 1
Other receivables, allowance for doubtful accounts	[2]	$ 2	$ 1

[1] See Note 9 for amounts attributable to related parties.

[2] See Note 24 for amounts attributable to related parties.

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Consolidated Statements of Equity - USD ($) shares in Millions, $ in Millions		Total	Sun Edison Inc	NRG Energy, Inc	Virginia Electric and Power Company	Dominion Energy Gas Holdings, LLC	Common Units	Convertible Preferred Units	Common Stock	Common Stock Virginia Electric and Power Company	Retained Earnings	Retained Earnings Virginia Electric and Power Company	Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Virginia Electric and Power Company	Accumulated Other Comprehensive Income (Loss) Dominion Energy Gas Holdings, LLC	Total Common Shareholders' Equity	Noncontrolling Interests	Noncontrolling Interests Sun Edison Inc	Noncontrolling Interests NRG Energy, Inc	Noncontrolling Interests Common Units	Noncontrolling Interests Convertible Preferred Units	Other Paid-In Capital Virginia Electric and Power Company	Member Units Dominion Energy Gas Holdings, LLC
Beginning balance at Dec. 31, 2015		$ 13,602			$ 10,641	$ 3,318			$ 6,680	$ 5,738	$ 6,458	$ 3,750	$ (474)	$ 40	$ (99)	$ 12,664	$ 938					$ 1,113	$ 3,417
Beginning balance (in shares) at Dec. 31, 2015									596	275
Net income including noncontrolling interests		2,212									2,123					2,123	89
Net income attributable to Dominion		2,123			$ 1,218	392						1,218											392
Sale of interest in merchant solar projects		139							$ 22							22	117
Contributions to Four Brothers and Three Cedars			$ 189															$ 189
Distributions						(150)																	(150)
Purchase of Dominion Energy Midstream common units		(17)							(3)							(3)	(14)
Issuance of common stock		2,152							$ 2,152							2,152
Issuance of common stock (in shares)					0				32
Sale of Dominion Energy Midstream common units - net of offering costs							$ 482	$ 490												$ 482	$ 490
Stock awards (net of change in unearned compensation)		14							$ 14							14
Present value of stock purchase contract payments related to RSNs	[1]	(191)							(191)							(191)
Tax effect of Dominion Energy Questar Pipeline contribution to Dominion Energy Midstream		(116)							(116)							(116)
Dividends and distributions		(1,789)									(1,727)					(1,727)	(62)
Other comprehensive income (loss), net of tax		(325)			$ 6	(24)							(325)	6	(24)	(325)
Other		(2)							(8)							(8)	6
Ending balance at Dec. 31, 2016		16,840			11,865	3,536			$ 8,550	$ 5,738	6,854	4,968	(799)	46	(123)	14,605	2,235					1,113	3,659
Ending Balance (in shares) at Dec. 31, 2016									628	275
Net income including noncontrolling interests		3,120									2,999					2,999	121
Net income attributable to Dominion		2,999			$ 1,540	615						1,540											615
Contributions to Four Brothers and Three Cedars				$ 9															$ 9
Distributions						(15)																	(15)
Issuance of common stock		1,302							$ 1,302							1,302
Issuance of common stock (in shares)					0				17
Sale of Dominion Energy Midstream common units - net of offering costs							$ 18													$ 18
Stock awards (net of change in unearned compensation)		22							$ 22							22
Dividends and distributions		(2,087)			$ (1,199)						(1,931)	(1,199)				(1,931)	(156)
Other comprehensive income (loss), net of tax		141			16	25							140	16	25	140	1
Other		5			2	2			(9)		14	2				5							2
Ending balance at Dec. 31, 2017		19,370			12,224	4,163			$ 9,865	$ 5,738	7,936	5,311	(659)	62	(98)	17,142	2,228					1,113	4,261
Ending Balance (in shares) at Dec. 31, 2017									645	275
Cumulative-effect of changes in accounting principles		6			3	3			$ (127)		1,029	79	(1,023)	(76)	(26)	(121)	127						29
Net income including noncontrolling interests		2,549									2,447					2,447	102
Net income attributable to Dominion		2,447			$ 1,282	301						1,282											301
Distributions						(25)																	(25)
Issuance of common stock		2,461							$ 2,461							2,461
Issuance of common stock (in shares)					0				36
Sale of Dominion Energy Midstream common units - net of offering costs		4															4
Remeasurement of noncontrolling interest in Dominion Energy Midstream									$ 375							375	(375)
Stock awards (net of change in unearned compensation)		22							22							22
Dividends and distributions		(2,331)			$ (464)						(2,185)	(464)				(2,185)	(146)
Other comprehensive income (loss), net of tax		(17)			2	(45)							(18)	2	(45)	(18)	1
Other		(16)							(8)		(8)					(16)
Ending balance at Dec. 31, 2018		$ 22,048			$ 13,047	$ 4,397			$ 12,588	$ 5,738	$ 9,219	$ 6,208	$ (1,700)	$ (12)	$ (169)	$ 20,107	$ 1,941					$ 1,113	$ 4,566
Ending Balance (in shares) at Dec. 31, 2018									681	275

[1] See Note 17 for further information.

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Consolidated Statements of Equity (Parenthetical) - $ / shares	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Stockholders' Equity [Abstract]
Dividends declared per common share	$ 0.835	$ 0.835	$ 0.835	$ 0.835	$ 0.770	$ 0.770	$ 0.755	$ 0.755	$ 3.34	$ 3.035	$ 2.80

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Consolidated Statements of Cash Flows - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Activities
Net income including noncontrolling interests		$ 2,549	$ 3,120	$ 2,212
Net income		2,447	2,999	2,123
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		2,280	2,202	1,849
Deferred income taxes and investment tax credits		517	(3)	725
Current income tax for Dominion Energy Questar Pipeline contribution to Dominion Energy Midstream				(212)
Proceeds from assignment of rental portfolio			91
Contribution to pension plan			(75)
Gains on sales of assets and equity method investments		(1,006)	(148)	(50)
Provision for rate credits to electric utility customers		77
Charges associated with equity method investments			158
Charges associated with future ash pond and landfill closure costs		81		197
Impairment of assets and related charges		395	15	4
Net (gains) losses on nuclear decommissioning trusts funds and other investments		102	(117)	(96)
Other adjustments		19	33	8
Changes in:
Accounts receivable		(110)	(103)	(286)
Inventories		(29)	15	1
Deferred fuel and purchased gas costs, net		(247)	(71)	54
Prepayments		(51)	(62)	21
Accounts payable		67	(89)	97
Accrued interest, payroll and taxes		(12)	64	203
Margin deposit assets and liabilities			(10)	(66)
Net realized and unrealized changes related to derivative activities		181	44	(335)
Asset retirement obligations		(35)	(94)	(61)
Pension and other postretirement benefits		(114)	(177)	(152)
Other operating assets and liabilities		109	(291)	38
Net cash provided by operating activities		4,773	4,502	4,151
Investing Activities
Plant construction and other property additions (including nuclear fuel)		(4,254)	(5,504)	(6,085)
Acquisition of Dominion Energy Questar, net of cash acquired				(4,381)
Acquisition of solar development projects		(151)	(405)	(40)
Proceeds from sales of securities		1,804	1,831	1,422
Purchases of securities		(1,894)	(1,940)	(1,504)
Proceeds from the sale of certain retail energy marketing assets		54	68
Proceeds from sales of certain merchant generation facilities and equity method investments		2,379
Proceeds from assignment of shale development rights		109	70	10
Contributions to equity method affiliates		(428)	(370)	(198)
Distributions from equity method affiliates		36	275	2
Other		(13)	33	83
Net cash used in investing activities		(2,358)	(5,942)	(10,691)
Financing Activities
Issuance (repayment) of short-term debt, net		(2,964)	143	(654)
Issuance of short-term notes		1,450		1,200
Repayment and repurchase of short-term notes		(1,450)	(250)	(1,800)
Issuance and remarketing of long-term debt		6,362	3,880	7,722
Repayment and repurchase of long-term debt		(5,682)	(1,572)	(1,610)
Credit facility borrowings		73
Net proceeds from issuance of Dominion Energy Midstream common units		4	18	482
Net proceeds from issuance of Dominion Energy Midstream preferred units				490
Proceeds from sale of interest in merchant solar projects				117
Contributions from NRG and SunEdison to Four Brothers and Three Cedars			9	189
Issuance of common stock		2,461	1,302	2,152
Common dividend payments		(2,185)	(1,931)	(1,727)
Other		(278)	(296)	(331)
Net cash provided by (used in) financing activities		(2,209)	1,303	6,230
Increase (decrease) in cash, restricted cash and equivalents		206	(137)	(310)
Cash, restricted cash and equivalents at beginning of year		185	322	632
Cash, restricted cash and equivalents at end of year		391	185	322
Supplemental Cash Flow Information
Interest and related charges, excluding capitalized amounts		1,362	1,083	905
Income taxes		89	9	145
Significant noncash investing and financing activities:
Accrued capital expenditures	[1],[2]	307	343	427
Receivables from sales of assets and equity method investments	[1],[2]	159
Guarantee provided by equity method affiliate	[1],[2]		30
Virginia Electric and Power Company
Operating Activities
Net income		1,282	1,540	1,218
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		1,309	1,333	1,210
Deferred income taxes and investment tax credits		224	269	469
Proceeds from assignment of rental portfolio			91
Charges associated with future ash pond and landfill closure costs		81		197
Provision for rate credits to customers		77
Other adjustments		(21)	(36)	(16)
Changes in:
Accounts receivable		(60)	(27)	(65)
Affiliated receivables and payables		(14)	125	220
Inventories		13	3	20
Deferred fuel and purchased gas costs, net		(269)	(59)	69
Prepayments		(1)	3	8
Accounts payable		(26)	(42)	25
Accrued interest, payroll and taxes		(8)	17	49
Net realized and unrealized changes related to derivative activities		119	13	(153)
Asset retirement obligations		(54)	(88)	(59)
Other operating assets and liabilities		188	(181)	77
Net cash provided by operating activities		2,840	2,961	3,269
Investing Activities
Plant construction and other property additions (including nuclear fuel)		(2,228)	(2,496)	(2,489)
Purchases of nuclear fuel		(173)	(192)	(153)
Acquisition of solar development projects		(141)	(41)	(7)
Proceeds from sales of securities		887	849	733
Purchases of securities		(925)	(884)	(775)
Other		(63)	(41)	(33)
Net cash used in investing activities		(2,643)	(2,805)	(2,724)
Financing Activities
Issuance (repayment) of short-term debt, net		(228)	477	(1,591)
Issuance (repayment) of affiliated current borrowings, net		191	(229)	(114)
Issuance and remarketing of long-term debt		1,300	1,500	1,688
Repayment and repurchase of long-term debt		(964)	(681)	(517)
Common dividend payments		(464)	(1,199)
Other		(18)	(11)	(18)
Net cash provided by (used in) financing activities		(183)	(143)	(552)
Increase (decrease) in cash, restricted cash and equivalents		14	13	(7)
Cash, restricted cash and equivalents at beginning of year		24	11	18
Cash, restricted cash and equivalents at end of year		38	24	11
Supplemental Cash Flow Information
Interest and related charges, excluding capitalized amounts		498	458	435
Income taxes		128	362	79
Significant noncash investing and financing activities:
Accrued capital expenditures		204	169	256
Dominion Energy Gas Holdings, LLC
Operating Activities
Net income		301	615	392
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		244	227	204
Deferred income taxes and investment tax credits		33	27	238
Gains on sales of assets and equity method investments		(109)	(70)	(50)
Impairment of assets and related charges		348	15
Other adjustments		(7)	(7)	(6)
Changes in:
Accounts receivable		(14)	(17)	(68)
Affiliated receivables and payables		3	40	88
Inventories		(1)	6	8
Prepayments		(4)	(18)	(6)
Accounts payable		(5)	(17)	15
Accrued interest, payroll and taxes		15	24	42
Pension and other postretirement benefits		(155)	(143)	(141)
Other operating assets and liabilities		(17)	(16)	(68)
Net cash provided by operating activities		632	666	648
Investing Activities
Plant construction and other property additions (including nuclear fuel)		(772)	(778)	(854)
Proceeds from sale of equity method investment in Iroquois				7
Proceeds from assignment of shale development rights		109	70	10
Other		(16)	(19)	(12)
Net cash used in investing activities		(679)	(727)	(849)
Financing Activities
Issuance (repayment) of short-term debt, net		(619)	169	69
Issuance (repayment) of affiliated current borrowings, net		200	(100)	23
Issuance and remarketing of long-term debt		500		680
Repayment and repurchase of long-term debt				(400)
Distribution payments to parent		(25)	(15)	(150)
Other		(5)	(6)	(5)
Net cash provided by (used in) financing activities		51	48	217
Increase (decrease) in cash, restricted cash and equivalents		4	(13)	16
Cash, restricted cash and equivalents at beginning of year		30	43	27
Cash, restricted cash and equivalents at end of year		34	30	43
Supplemental Cash Flow Information
Interest and related charges, excluding capitalized amounts		95	89	81
Income taxes		79	9	(92)
Significant noncash investing and financing activities:
Accrued capital expenditures		$ 38	$ 38	$ 59

[1] See Note 19 for noncash activities related to the remeasurement of Dominion Energy's noncontrolling interest in Dominion Energy Midstream.

[2] See Note 9 for noncash activities related to equity method investments.

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Nature Of Operations

12 Months Ended

Dec. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature Of Operations

NOTE 1. NATURE OF OPERATIONS

Dominion Energy, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Energy Gas. Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s stock is owned by Dominion Energy. Dominion Energy 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. All of Dominion Energy Gas’ membership interests are held by Dominion Energy. The SCANA Combination was completed in January 2019. See Note 3 for a description of operations acquired in the SCANA Combination.

Dominion Energy’s operations also include the Cove Point LNG Facility, Cove Point Pipeline, Liquefaction Project, an equity investment in Atlantic Coast Pipeline and regulated gas transportation and distribution operations primarily in the eastern and Rocky Mountain regions of the U.S. Dominion Energy’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations.

At December 31, 2018, Dominion Energy owned the general partner, 60.9% of the common units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owned a preferred equity interest and the general partner interest in Cove Point, DECG, Dominion Energy Questar Pipeline and a 25.93% noncontrolling partnership interest in Iroquois. In January 2019, Dominion Energy acquired all outstanding partnership interests not owned by Dominion Energy and Dominion Energy Midstream became a wholly-owned subsidiary of Dominion Energy. At December 31, 2018, the public’s ownership interest in Dominion Energy Midstream is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements.

Through December 2018, Dominion Energy managed its daily operations through three primary operating segments: Power Delivery, Power Generation and Gas Infrastructure. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt). In addition, Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. Subsequent to the SCANA Combination, Dominion Energy manages the operations of SCANA through an additional operating segment, Southeast Energy.

Virginia Power manages its daily operations through two primary operating segments: Power Delivery and Power Generation. It also reports a Corporate and Other segment that 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.

Dominion Energy Gas manages its daily operations through one primary operating segment: Gas Infrastructure. It also reports a Corporate and Other segment that primarily includes specific items attributable to its 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 Energy Gas as a result of Dominion Energy’s basis in the net assets contributed.

See Note 25 for further discussion of the Companies’ operating segments.

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Significant Accounting Policies

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES

General

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, expenses and cash flows for the periods presented. Actual results may differ from those estimates.

The Companies’ 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. At December 31, 2018, Dominion Energy 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. In August 2018, NRG’s ownership interest in Four Brothers and Three Cedars was transferred to GIP. GIP’s ownership interest in Four Brothers and Three Cedars, Terra Nova Renewable Partners’ 33% interest in certain of Dominion Energy’s merchant solar projects and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019), is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion Energy’s remaining 67% ownership in certain merchant projects upon the occurrence of certain events, none of which are expected to occur in 2019.

The Companies report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements.

The Companies consider acquisitions or dispositions in which substantially all of the fair value of the gross assets acquired or disposed of is concentrated into a single identifiable asset or group of similar identifiable assets to be an acquisition or a disposition of an asset, rather than a business. See Notes 3 and 10 for further information on such transactions.

Dominion Energy maintains pension and other postretirement benefit plans. Virginia Power and Dominion Energy Gas participate in certain of these plans. See Note 21 for further information on these plans.

Certain amounts in the Companies’ 2017 and 2016 Consolidated Financial Statements and Notes have been reclassified to conform to the 2018 presentation for comparative purposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.

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

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Dominion Energy and Virginia Power collect sales, consumption and consumer utility taxes and Dominion Energy Gas collects sales taxes; however, these amounts are excluded from revenue. Dominion Energy’s customer receivables at December 31, 2018 and 2017 included $626 million and $661 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 2018 and 2017 included $392 million and $400 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers. Dominion Energy Gas’ customer receivables at December 31, 2018 and 2017 included $131 million and $121 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas delivered but not yet billed to its customers. See Note 24 for amounts attributable to related parties.

The primary types of sales and service activities reported as operating revenue for Dominion Energy, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:

REVENUE FROM CONTRACTS WITH CUSTOMERS

• Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

• Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated hedging activity;

• Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;

• Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties and associated hedging activity;

• Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

• Nonregulated gas transportation and storage sales consist primarily of LNG terminalling services;

• Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities; and

• Other nonregulated revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity. Other nonregulated revenue also includes services performed for Atlantic Coast Pipeline, sales of energy-related products and services from Dominion Energy’s retail energy marketing operations, service concession arrangements and gas processing and handling revenue.

OTHER REVENUE

• Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

The primary types of sales and service activities reported as operating revenue for Dominion Energy, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:

• Regulated electric sales consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

• Nonregulated electric sales consisted primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;

• Regulated gas sales consisted primarily of state- and FERC-regulated natural gas sales and related distribution services and associated derivative activity;

• Nonregulated gas sales consisted primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity;

• Gas transportation and storage sales consisted primarily of FERC-regulated sales of transmission and storage services. Also included were state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services; and

• Other revenue consisted primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also included miscellaneous service revenue from electric and gas distribution operations, sales of energy-related products and services from Dominion Energy’s retail energy marketing operations and gas processing and handling revenue.

The primary types of sales and service activities reported as operating revenue for Virginia Power, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:

REVENUE FROM CONTRACTS WITH CUSTOMERS

• Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services;

• Other regulated revenue consists primarily of sales of excess capacity and other commodities and miscellaneous service revenue from electric distribution operations; and

• Other nonregulated revenue consists primarily of sales to non-jurisdictional customers from certain solar facilities, revenue from renting space on certain electric transmission poles and distribution towers and service concession arrangements.

OTHER REVENUE

• Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

The primary types of sales and service activities reported as operating revenue for Virginia Power, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:

• Regulated electric sales consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; and

• Other revenue consisted primarily of miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities.

The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:

REVENUE FROM CONTRACTS WITH CUSTOMERS

• Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;

• Nonregulated gas sales consist primarily of sales of gas purchased from third parties and royalty revenues;

• Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

• NGL revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity;

• Management service revenue consists primarily of services performed for Atlantic Coast Pipeline;

• Other regulated revenue consists primarily of miscellaneous regulated revenues; and

• Other nonregulated revenue consists primarily of miscellaneous service revenue.

OTHER REVENUE

• Other revenue consists primarily of gains and losses from derivative instruments not subject to hedge accounting.

The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:

• Regulated gas sales consisted primarily of state- and FERC-regulated natural gas sales and related distribution services;

• Nonregulated gas sales consisted primarily of sales of natural gas production at market-based rates and contracted fixed prices and sales of gas purchased from third parties. Revenue from sales of gas production was recognized based on actual volumes of gas sold to purchasers and was reported net of royalties;

• Gas transportation and storage sales consisted primarily of FERC-regulated sales of transmission and storage services. Also included were state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

• NGL revenue consisted primarily of sales of NGL production and condensate, extracted products and associated derivative activity; and

• Other revenue consisted primarily of miscellaneous service revenue, gas processing and handling revenue.

Dominion Energy and Virginia Power record refunds to customers as required by state commissions as a reduction to regulated electric sales or regulated gas sales, as applicable. Dominion Energy and Virginia Power’s revenue accounted for under the alternative revenue program guidance primarily consists of the equity return for under-recovery of certain riders. Alternative revenue programs compensate Dominion Energy and Virginia Power for certain projects and initiatives. Revenues arising from these programs are presented separately from revenue arising from contracts with customers in the categories above.

Revenues from electric and gas sales are recognized over time, as the customers of the Companies consume gas and electricity as it is delivered. Transportation and storage contracts are primarily stand-ready service contracts that include fixed reservation and variable usage fees. LNG terminalling services are also stand-ready service contracts, primarily consisting of fixed fees, offset by service credits associated with the start-up phase of the Liquefaction Project. Fixed fees are recognized ratably over the life of the contract as the stand-ready performance obligation is satisfied, while variable usage fees are recognized when Dominion Energy and Dominion Energy Gas have a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the performance obligation completed to date. Sales of products and services, including NGLs, typically transfer control and are recognized as revenue upon delivery of the product or service. The customer is able to direct the use of, and obtain substantially all of the benefits from, the product at the time the product is delivered. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. Payment for most sales and services varies by contract type, but is typically due within a month of billing.

Dominion Energy and Dominion Energy Gas typically receive or retain NGLs and natural gas from customers when providing natural gas processing, transportation or storage services. The revised guidance for revenue from contracts with customers requires entities to include the fair value of the noncash consideration in the transaction price. Therefore, subsequent to the adoption of the revised guidance for revenue recognition from contracts with customers, Dominion Energy and Dominion Energy Gas record the fair value of NGLs received during natural gas processing as service revenue recognized over time, and continue to recognize revenue from the subsequent sale of the NGLs to customers upon delivery. Dominion Energy and Dominion Energy Gas typically retain natural gas under certain transportation service arrangements that are intended to facilitate performance of the service and allow for natural losses that occur. As the intent of the allowance is to enable fulfillment of the contract rather than to provide compensation for services, the fuel allowance is not included in revenue.

Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs

Where permitted by regulatory authorities, the differences between Dominion Energy and Virginia Power’s actual electric fuel and purchased energy expenses and Dominion Energy and Dominion Energy Gas’ purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.

Of the cost of fuel used in electric generation and energy purchases to serve utility customers, at December 31, 2018, approximately 84% is subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.

Virtually all of Dominion Energy Gas, Cove Point, Questar Gas, Hope and SCE&G and PSNC’s, following the SCANA Combination, natural gas purchases are either subject to deferral accounting or are recovered from the customer in the same accounting period as the sale.

Income Taxes

A consolidated federal income tax return is filed for Dominion Energy and its subsidiaries, including Virginia Power and Dominion Energy Gas’ subsidiaries. In addition, where applicable, combined income tax returns for Dominion Energy and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed.

Although Dominion Energy Gas is disregarded for income tax purposes, a provision for income taxes is recognized to reflect the inclusion of its business activities in the tax returns of its parent, Dominion Energy. Virginia Power and Dominion Energy Gas participate in intercompany tax sharing agreements with Dominion Energy and its subsidiaries. Current income taxes are based on taxable income or loss and credits determined on a separate company basis.

Under the agreements, if a subsidiary incurs a tax loss or earns a credit, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or credit or to the extent the tax loss or credit is absorbed by the taxable income of other Dominion Energy consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax asset until realized.

The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies, including changes in corporate tax rates and business deductions. The 2017 Tax Reform Act reduces the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. Deferred tax assets and liabilities are classified as noncurrent in the Consolidated Balance Sheets and measured at the enacted tax rate expected to apply when temporary differences are realized or settled. Thus, at the date of enactment, federal deferred taxes were remeasured based upon the new 21% tax rate. The total effect of tax rate changes on deferred tax balances was recorded as a component of the income tax provision related to continuing operations for the period in which the law is enacted, even if the assets and liabilities relate to other components of the financial statements, such as items of accumulated other comprehensive income. For Dominion Energy subsidiaries that are not rate-regulated utilities, existing deferred income tax assets or liabilities were adjusted for the reduction in the corporate income tax rate and allocated to continuing operations. Dominion Energy’s rate-regulated utility subsidiaries likewise were required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, if it is probable that the effect of the change in income tax rates will be recovered or refunded in future rates, the regulated utility recorded a regulatory asset or liability instead of an increase or decrease to deferred income tax expense.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. The Companies establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

The Companies recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the Consolidated Balance Sheets and current payables are included in accrued interest, payroll and taxes on the Consolidated Balance Sheets.

The Companies recognize interest on underpayments and overpayments of income taxes in interest expense and other income, respectively. Penalties are also recognized in other income.

Interest for the Companies was immaterial in 2018 and 2016. Dominion Energy and Virginia Power both recognized interest income of $11 million in 2017. Dominion Energy Gas’ interest was immaterial in 2017. Dominion Energy, Virginia Power and Dominion Energy Gas’ penalties were immaterial in 2018, 2017 and 2016.

At December 31, 2018, Virginia Power had an income tax-related affiliated receivable of $36 million, comprised of $34 million of federal income taxes and $2 million of state income taxes due from Dominion Energy. Dominion Energy Gas also had a net affiliated receivable of $2 million due from Dominion Energy, representing $8 million of federal income taxes receivable and $6 million of state income taxes payable to Dominion Energy. The net affiliated receivables are expected to be received from Dominion Energy.

In addition, Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2018 included $13 million of state income taxes receivable. State income taxes receivable at Virginia Power were immaterial at December 31, 2018.

At December 31, 2017, Virginia Power had an income tax-related affiliated payable of $16 million, comprised of $16 million of federal income taxes due to Dominion Energy. Dominion Energy Gas also had an affiliated payable of $25 million due to Dominion Energy, representing $21 million of federal income taxes and $4 million of state income taxes. The net affiliated payables were paid to Dominion Energy.

In addition, Virginia Power’s Consolidated Balance Sheet at December 31, 2017 included $1 million of noncurrent federal income taxes receivable, less than $1 million of state income taxes receivable and $1 million of noncurrent state income taxes receivable. Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2017 included $14 million of state income taxes receivable.

Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.

Cash, Restricted Cash and Equivalents

Cash, restricted cash and equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Current banking arrangements generally do not require checks to be funded until they are presented for payment. The following table illustrates the checks outstanding but not yet presented for payment and recorded in accounts payable for the Companies:

At December 31,	2018		2017
(millions)
Dominion Energy	$	35	$	30
Virginia Power		16		17
Dominion Energy Gas		7		7

RESTRICTED CASH AND EQUIVALENTS

The Companies hold restricted cash and equivalent balances that primarily consist of amounts held for customer deposits, future debt payments on SBL Holdco and Dominion Solar Projects III, Inc.’s term loan agreements and on Eagle Solar’s senior note agreement.

The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within the Companies’ Consolidated Balance Sheets to the corresponding amounts reported within the Companies’ Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016:

	Cash, Restricted Cash and Equivalents at End/Beginning of Year
	December 31, 2018		December 31, 2017		December 31, 2016		December 31, 2015
(millions)
Dominion Energy
Cash and cash equivalents	$	268	$	120	$	261	$	607
Restricted cash and equivalents(1)		123		65		61		25
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	391	$	185	$	322	$	632
Virginia Power
Cash and cash equivalents	$	29	$	14	$	11	$	18
Restricted cash and equivalents(1)		9		10		—		—
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	38	$	24	$	11	$	18
Dominion Energy Gas
Cash and cash equivalents	$	10	$	4	$	23	$	13
Restricted cash and equivalents(1)		24		26		20		14
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	34	$	30	$	43	$	27

(1) Restricted cash and equivalent balances are presented within other current assets in the Companies’ Consolidated Balance Sheets.

DISTRIBUTIONS FROM EQUITY METHOD INVESTEES

Dominion Energy and Dominion Energy Gas each hold investments that are accounted for under the equity method of accounting. Dominion Energy and Dominion Energy Gas classify distributions from equity method investees as either cash flows from operating activities or cash flows from investing activities in the Consolidated Statements of Cash Flows according to the nature of the distribution. Distributions received are classified on the basis of the nature of the activity of the investee that generated the distribution as either a return on investment (classified as cash flows from operating activities) or a return of an investment (classified as cash flows from investing activities) when such information is available to Dominion Energy and Dominion Energy Gas.

Derivative Instruments

The Companies are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as interest rate and foreign currency exchange rate risks of their business operations. Dominion Energy uses derivative instruments such as physical and financial forwards, futures, swaps, options and FTRs to manage the commodity, interest rate and foreign currency exchange rate risks of its business operations. Virginia Power uses derivative instruments such as physical and financial forwards, futures, swaps, options and FTRs to manage commodity and interest rate risks. Dominion Energy Gas uses derivative instruments such as physical and financial forwards, futures and swaps to manage commodity, interest rate and foreign currency exchange rate risks.

All derivatives, except those for which an exception applies, are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.

The Companies do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion Energy had margin assets of $95 million and $92 million associated with cash collateral at December 31, 2018 and 2017, respectively. Dominion Energy’s margin liabilities associated with cash collateral were less than $1 million at December 31, 2018 and 2017. Virginia Power had margin assets of $23 million associated with cash collateral at December 31, 2017. Virginia Power had no margin assets associated with cash collateral at December 31, 2018 and no margin liabilities associated with cash collateral at December 31, 2018 and 2017. Dominion Energy Gas had no margin assets or liabilities associated with cash collateral at December 31, 2018 and 2017. See Note 7 for further information about derivatives.

To manage price risk, the Companies hold certain derivative instruments that are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices. All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses, interest and related charges or other income based on the nature of the underlying risk.

Changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.

DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS

In accordance with accounting guidance pertaining to derivatives and hedge accounting, the Companies designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For derivative instruments that are accounted for as fair value hedges or cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.

Cash Flow Hedges-A majority of the Companies’ hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas and NGLs. The Companies also use interest rate swaps to hedge their exposure to variable interest rates on long-term debt as well as foreign currency swaps to hedge their exposure to interest payments denominated in Euros. For transactions in which the Companies are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Dominion Energy entered into interest rate derivative instruments to hedge its forecasted interest payments related to planned debt issuances in 2014. These interest rate derivatives were designated by Dominion Energy as cash flow hedges prior to the formation of Dominion Energy Gas. For the purposes of the Dominion Energy Gas financial statements, the derivative balances, AOCI balance, and any income statement impact related to these interest rate derivative instruments entered into by Dominion Energy have been, and will continue to be, included in the Dominion Energy Gas’ Consolidated Financial Statements as the forecasted interest payments related to the debt issuances now occur at Dominion Energy Gas.

Fair Value Hedges-Dominion Energy has also designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. In addition, Dominion Energy has used fair value hedges to mitigate the fixed price exposure inherent in commodity inventory. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7 for further information on derivatives.

Property, Plant and Equipment

Property, plant and equipment is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is generally charged to expense as it is incurred.

In 2018, 2017 and 2016, Dominion Energy capitalized interest costs and AFUDC to property, plant and equipment of $134 million, $236 million and $159 million, respectively. In 2018, 2017 and 2016, Virginia Power capitalized AFUDC to property, plant and equipment of $56 million, $37 million and $21 million, respectively. In 2018, 2017 and 2016, Dominion Energy Gas capitalized AFUDC to property, plant and equipment of $18 million, $25 million and $8 million, respectively.

Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2018, 2017 and 2016, Virginia Power recorded $4 million, $22 million and $31 million of AFUDC related to these projects, respectively.

For property subject to cost-of-service rate regulation, including Dominion Energy and Virginia Power electric distribution, electric transmission and generation property, Dominion Energy Gas natural gas distribution and transmission property, and for certain Dominion Energy natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be abandoned. In January 2019, Virginia Power committed to a plan to retire certain automated meter reading infrastructure associated with its electric operations before the end of its useful life and replace such equipment with more current AMI technology. As a result, Virginia Power expects to incur a charge of approximately $190 million ($141 million after-tax) in 2019.

For property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. The Companies’ average composite depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,	2018		2017		2016
(percent)
Dominion Energy
Generation		2.71		2.94		2.83
Transmission		2.54		2.55		2.47
Distribution		2.97		3.00		3.02
Storage		2.40		2.48		2.29
Gas gathering and processing		2.62		2.21		2.66
General and other		4.56		4.89		4.12
Virginia Power
Generation		2.71		2.94		2.83
Transmission		2.52		2.54		2.36
Distribution		3.31		3.32		3.32
General and other		4.52		4.68		3.49
Dominion Energy Gas
Transmission		2.45		2.40		2.43
Distribution		2.41		2.42		2.55
Storage		2.46		2.45		2.19
Gas gathering and processing		3.07		2.42		2.58
General and other		5.59		4.96		4.54

In the second quarter of 2018, Virginia Power recorded an adjustment for the retroactive application of depreciation rates for regulated nuclear plants to comply with Virginia Commission requirements. This adjustment resulted in a decrease of $60 million ($44 million after-tax) in depreciation expense in Virginia Power’s Consolidated Statements of Income for the year ended December 31, 2018. This resulted in an increase to Dominion Energy’s EPS of $0.07 per share for the year ended December 31, 2018. This revision is expected to decrease annual depreciation expense by approximately $30 million ($23 million after-tax).

In the first quarter of 2017, Virginia Power revised the depreciation rates for its assets to reflect the results of a new depreciation study. This change resulted in an increase in annual depreciation expense of $40 million ($25 million after-tax) for 2017. Additionally, Dominion Energy revised the depreciable lives for its merchant generation assets, excluding Millstone, which resulted in a decrease in annual depreciation expense of $26 million ($16 million after-tax) for 2017.

Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved gas and oil reserves, at a rate of $1.89 and $2.11 per mcfe in 2018 and 2017, respectively.

Dominion Energy’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:

Asset	Estimated Useful Lives
Merchant generation-nuclear		44 years
Merchant generation-other		15-30 years
Nonutility gas gathering and processing		3-50 years
LNG facility		40 years
General and other		5-59 years

Depreciation and amortization related to Virginia Power and Dominion Energy Gas’ nonutility property, plant and equipment and exploration and production properties was immaterial for the years ended December 31, 2018, 2017 and 2016, except for Dominion Energy Gas’ nonutility gas gathering and processing properties which are depreciated using the straight-line method over estimated useful lives between 10 and 50 years.

Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion Energy and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.

Long-Lived and Intangible Assets

The Companies perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for further discussion on the impairment of long-lived assets.

Regulatory Assets and Liabilities

The accounting for Dominion Energy and Dominion Energy Gas’ regulated gas and Dominion Energy and Virginia Power’s regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.

The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions, legislation or historical experience, as well as discussions with applicable regulatory authorities and legal counsel. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made.

Asset Retirement Obligations

The Companies recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. Quarterly, the Companies assess their AROs to determine if circumstances indicate that estimates of the amounts or timing of future cash flows associated with retirement activities have changed. AROs are adjusted when significant changes in the amounts or timing of future cash flows are identified. Dominion Energy and Dominion Energy Gas report accretion of AROs and depreciation on asset retirement costs associated with their natural gas pipeline and storage well assets as an adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Dominion Energy, following the SCANA Combination, and Virginia Power report accretion of AROs and depreciation on asset retirement costs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions. Additionally, Dominion Energy and Virginia Power report accretion of AROs and depreciation on asset retirement costs associated with certain rider and prospective rider projects as an adjustment to the regulatory asset for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs are reported in other operations and maintenance expense and depreciation expense, respectively, in the Consolidated Statements of Income.

Debt Issuance Costs

The Companies defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as a reduction in long-term debt in the Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest expense. Unamortized costs associated with redemptions of debt securities prior to stated maturity dates are generally recognized and recorded in interest expense immediately. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation are deferred and amortized.

Investments

DEBT AND EQUITY SECURITIES WITH READILY DETERMINABLE FAIR VALUES

Dominion Energy accounts for and classifies investments in debt securities as trading or available-for-sale securities. Virginia Power classifies investments in debt securities as available-for-sale securities.

• Debt securities classified as trading securities include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.

• Debt securities classified as available-for-sale securities include all other debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other available-for-sale debt securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.

In determining realized gains and losses for debt securities, the cost basis of the security is based on the specific identification method.

Equity securities with readily determinable fair values include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans and securities held by Dominion Energy and Virginia Power in the nuclear decommissioning trusts. Dominion Energy and Virginia Power record all equity securities with a readily determinable fair value, or for which they are permitted to estimate fair value using NAV (or its equivalent), at fair value in nuclear decommissioning trust funds and other investments in the Consolidated Balance Sheets. However, Dominion Energy and Virginia Power may elect a measurement alternative for equity securities without a readily determinable fair value. Under the measurement alternative, equity securities are reported at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. Dominion Energy and Virginia Power qualitatively assess equity securities reported using the measurement alternative to determine whether an investment is impaired on an ongoing basis. Net realized and unrealized gains and losses on equity securities held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other equity securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts and rabbi trusts, net realized and unrealized gains and losses are included in other income in the Consolidated Statements of Income.

EQUITY SECURITIES WITHOUT READILY DETERMINABLE FAIR VALUES

The Companies account for illiquid and privately held securities without readily determinable fair values under either the equity method or cost method. Equity securities without readily determinable fair values include:

• Equity method investments when the Companies have the ability to exercise significant influence, but not control, over the investee. Dominion Energy’s investments are included in investments in equity method affiliates and Dominion Energy Gas’ investments are included in investments in their Consolidated Balance Sheets. Dominion Energy and Dominion Energy Gas record equity method adjustments in other income and earnings from equity method investee, respectively, in their Consolidated Statements of Income, including their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.

• Cost method investments when Dominion Energy and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion Energy and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds. Cost method investments are reported at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same issuer.

OTHER-THAN-TEMPORARY IMPAIRMENT

The Companies periodically review their investments in debt securities and equity method investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in the fair value of any security is determined to be other-than-temporary, the security is written down to its fair value at the end of the reporting period.

Decommissioning Trust Investments —Special Considerations for Debt Securities

• The recognition provisions of other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity.

• Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion Energy and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, Dominion Energy and Virginia Power record the credit loss in earnings and any remaining portion of the unrealized loss in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.

Inventories

Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory is valued using the weighted-average cost method, except for East Ohio gas distribution operations, which are valued using the LIFO method. Under the LIFO method, current stored gas inventory was valued at $12 million and $9 million at December 31, 2018 and December 31, 2017, respectively. Based on the average price of gas purchased during 2018 and 2017, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $87 million and $79 million, respectively.

Gas Imbalances

Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion Energy and Dominion Energy Gas value these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion Energy from other parties are reported in other current assets and imbalances that Dominion Energy and Dominion Energy Gas owe to other parties are reported in other current liabilities in the Consolidated Balance Sheets.

Goodwill

Dominion Energy and Dominion Energy Gas evaluate goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount.

New Accounting Standards

REVENUE RECOGNITION

In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. The Companies adopted this revised accounting guidance for interim and annual reporting periods beginning January 1, 2018 using the modified retrospective method. Upon the adoption of the standard, Dominion Energy and Dominion Energy Gas recorded the cumulative-effect of a change in accounting principle of $3 million to retained earnings and membership interests, respectively, and to establish a contract asset related to changes in the timing of revenue recognition for three existing contracts with customers at DETI.

As a result of adopting this revised accounting guidance, Dominion Energy and Dominion Energy Gas record offsetting operating revenue and other energy-related purchases for non-cash consideration of performing processing and fractionation services related to NGLs. Such amounts at Dominion Energy were $107 million and at Dominion Energy Gas were $103 million, recorded in the Consolidated Statements of Income for the year ended December 31, 2018. No such amounts were recorded during the year ended December 31, 2017. Dominion Energy and Dominion Energy Gas no longer record offsetting operating revenue and purchased gas for fuel retained to offset costs on certain transportation and storage arrangements. Such amounts at Dominion Energy were $111 million and at Dominion Energy Gas were $79 million, recorded in the Consolidated Statements of Income for the year ended December 31, 2017.

FINANCIAL INSTRUMENTS

In January 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of financial instruments. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018 and the Companies adopted the standard using the modified retrospective method. Upon adoption of this guidance for equity securities held at January 1, 2018, Dominion Energy and Virginia Power recorded the cumulative-effect of a change in accounting principle to reclassify net unrealized gains from AOCI to retained earnings and to recognize equity securities previously categorized as cost method investments at fair value (using NAV) in nuclear decommissioning trust funds in the Consolidated Balance Sheets and a cumulative-effect adjustment to retained earnings. Dominion Energy and Virginia Power reclassified approximately $1.1 billion ($734 million after-tax) and $119 million ($73 million after-tax), respectively, of net unrealized gains from AOCI to retained earnings. Dominion Energy and Virginia Power also recorded approximately $36 million ($22 million after-tax) in net unrealized gains on equity securities previously classified as cost method investments, of which $3 million was recorded to retained earnings and $33 million was recorded to regulatory liabilities for net unrealized gains subject to cost-based regulation. As a result of adopting this revised accounting guidance, Dominion Energy recorded unrealized losses on equity securities, net of regulatory deferrals, of $190 million ($142 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018, resulting in an $0.22 loss per share for the year ended December 31, 2018. Virginia Power recorded unrealized losses on equity securities, net of regulatory deferrals, of $24 million ($18 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018.

LEASES

In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases currently classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.

The guidance is effective for the Companies’ interim and annual reporting periods beginning January 1, 2019. The Companies will adopt this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Companies are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Companies will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. Dominion Energy, Virginia Power and Dominion Energy Gas anticipate that the adoption of this guidance will result in approximately $450 million to $500 million, $200 million to $250 million and $60 million to $70 million, respectively, of offsetting right-of-use assets and liabilities added to their Consolidated Balance Sheets for operating leases in effect at the adoption date. Dominion Energy’s anticipated right-of-use asset and liability associated with operating leases includes those acquired as part of the SCANA Combination of approximately $30 million to $35 million. No material changes are expected to the Companies’ results of operations.

DERECOGNITION AND PARTIAL SALES OF NONFINANCIAL ASSETS

In February 2017, the FASB issued revised accounting guidance clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, and the Companies adopted the standard using the modified retrospective method. Upon adoption of the standard, Dominion Energy recorded the cumulative-effect of a change in accounting principle to reclassify $127 million from noncontrolling interests to common stock related to the sale of a noncontrolling interest in certain merchant solar projects completed in December 2015 and January 2016.

NET PERIODIC PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

In March 2017, the FASB issued revised accounting guidance for the presentation of net periodic pension and other postretirement benefit costs. This guidance became effective for the Companies beginning January 1, 2018 and requires that the service cost component of net periodic pension and other postretirement benefit costs be classified in the same line item as other compensation costs arising from services rendered by employees, while all other components of net periodic pension and other postretirement costs are classified outside of income from operations. In addition, only the service cost component remains eligible for capitalization during construction. These changes do not impact the accounting by participants in a multi-employer plan. The standard also recognizes that in the event that a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in recognition of a regulatory asset or liability. For costs not capitalized for which regulators are expected to provide recovery, a regulatory asset will be established. As such, the amounts eligible for capitalization in the Consolidated Financial Statements of Virginia Power and Dominion Energy Gas, as subsidiary participants in Dominion Energy’s multi-employer plans, will differ from the amounts eligible for capitalization in the Consolidated Financial Statements of Dominion Energy, the plan administrator. These differences will result in a regulatory asset or liability recorded in the Consolidated Financial Statements of Dominion Energy.

TAX REFORM

In December 2017, the staff of the SEC issued guidance which clarifies accounting for income taxes if information is not yet available or complete and provided for up to a one-year measurement period in which to complete the required analyses and accounting. The guidance described three scenarios associated with a company’s status of accounting for income tax reform: (1) a company is complete with its accounting for certain effects of tax reform, (2) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply accounting for income taxes based on the provisions of the tax laws that were in effect immediately prior to the 2017 Tax Reform Act being enacted. The Companies have accounted for the effects of the 2017 Tax Reform Act, although additional changes could occur as guidance is issued and finalized as described below. In addition, certain states in which the Companies operate may or may not conform to some or all of the provisions of the 2017 Tax Reform Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to results of operations and cash flows, and adjustments to tax-related assets and liabilities, and could be material.

In August 2018, the U.S. Department of Treasury issued proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017 through December 31, 2017. The application of these changes decreased Dominion Energy’s net operating loss carryforward utilization on its 2017 tax return as discussed in Note 5.

In November 2018, the U.S. Department of Treasury issued proposed regulations defining interest as any amounts associated with the time value of money or use of funds. These proposed regulations provide guidance for purposes of the exception to the interest limitation for regulated public utilities, the application of the interest limitation to consolidated groups, such as Dominion Energy, and the interest limitation with respect to partnerships and partners in those partnerships. It is unclear when the guidance may be finalized, or whether that guidance could result in a disallowance of a portion of the Companies’ interest deductions in the future.

In February 2018, the FASB issued revised accounting guidance to provide clarification on the application of the 2017 Tax Reform Act for balances recorded within AOCI. The revised guidance provides for stranded amounts within AOCI from the impacts of the 2017 Tax Reform Act to be reclassified to retained earnings. The Companies adopted this guidance for interim and annual reporting periods beginning January 1, 2018 on a prospective basis. In connection with the adoption of this guidance, Dominion Energy reclassified a benefit of $289 million from AOCI to retained earnings, Virginia Power reclassified a benefit of $3 million from AOCI to retained earnings and Dominion Energy Gas reclassified a benefit of $26 million from AOCI to membership interests. The amounts reclassified reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of the Companies’ AOCI.

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Acquisitions And Dispositions

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Acquisitions And Dispositions

NOTE 3. ACQUISITIONS AND DISPOSITIONS

DOMINION ENERGY

Acquisition of SCANA

In January 2019, Dominion Energy issued 95.6 million shares of Dominion Energy common stock, valued at $6.8 billion, representing 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock, in connection with the completion of the SCANA Combination. SCANA, through its regulated subsidiaries, is primarily engaged in the generation, transmission and distribution of electricity in the central, southern, and southwestern portions of South Carolina and in the distribution of natural gas in North Carolina and South Carolina. In addition, SCANA markets natural gas to retail customers in the southeast U.S. Following completion of the SCANA Combination, SCANA operates as a wholly-owned subsidiary of Dominion Energy. In addition, SCANA’s outstanding debt totaled $6.9 billion at closing. The SCANA Combination expands Dominion Energy’s portfolio of regulated electric generation, transmission and distribution and regulated natural gas distribution infrastructure and operations.

MERGER APPROVAL AND CONDITIONS

Merger Approval

The SCANA Combination required approval of SCANA’s shareholders, FERC, the North Carolina Commission, the South Carolina Commission, the Georgia Public Service Commission and the NRC and clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act. All such approvals were received prior to closing of the SCANA Combination.

Various parties filed petitions for rehearing or reconsideration of the SCANA Merger Approval Order. In January 2019, the South Carolina Commission issued a directive (1) granting the request of various parties and finding that SCE&G was imprudent in its actions by not disclosing material information to the South Carolina Office of Regulatory Staff and the South Carolina Commission with regard to costs incurred subsequent to March 2015 and (2) denying the petitions for rehearing or consideration as to other issues raised in the various petitions. The SCANA Merger Approval Order and the order on rehearing are subject to appeal by various parties.

Refunds to Customers

As a condition to the SCANA Merger Approval Order, SCE&G will provide refunds and restitution of $2.0 billion over 20 years with capital support from Dominion Energy.

In September and October 2017, SCE&G received proceeds from Toshiba Corporation totaling $1.1 billion in full satisfaction of its share of a settlement agreement between SCE&G, Santee Cooper and Toshiba Corporation in connection with Westinghouse and WECTEC, both wholly-owned subsidiaries of Toshiba Corporation and responsible for the engineering and construction of the NND Project, filing for bankruptcy. The purchase price allocation below includes a previously established regulatory liability at SCE&G totaling $1.1 billion associated with the monetization of the bankruptcy settlement with Toshiba Corporation. In accordance with the terms of the SCANA Merger Approval Order, this regulatory liability, net of amounts that may be required to satisfy any liens against NND Project property totaling $1.0 billion, will be refunded to SCE&G electric service customers over a 20-year period ending in 2039.

Additionally, SCE&G will reflect in the first quarter of 2019 a reduction in operating revenue and a corresponding regulatory liability of $1.0 billion of which approximately $140 million will be considered current, representing a refund of amounts previously collected from retail electric customers of SCE&G for the NND Project to be credited over an estimated 11-year period. This will result in a $756 million after-tax charge in Dominion Energy’s Consolidated Statements of Income in the first quarter of 2019.

NND Project

As a condition to the SCANA Merger Approval Order, SCE&G will exclude from rate recovery $2.4 billion of costs related to the NND Project and $180 million of costs associated with the purchase of the Columbia Energy Center power station. Regulatory assets included in SCANA’s historical balance sheet at December 31, 2018 reflected these disallowances.

The remaining regulatory asset associated with the NND Project of $2.8 billion will be collected over a 20-year period, including a return on investment. In January 2019, SCE&G filed the NND Project rider in accordance with the terms of the SCANA Merger Approval Order for rates effective in February 2019 for SCE&G’s retail electric customers. The South Carolina Commission approved this filing in January 2019.

Other Terms and Conditions

• SCE&G will not file an application for a general rate case with the South Carolina Commission with a requested effective date earlier than January 2021;

• PSNC will not file an application for a general rate case with the North Carolina Commission with a requested effective date earlier than April 2021;

• Dominion Energy has committed to increasing SCANA’s historical level of corporate contributions to charities by $1 million per year over the next five years;

• Dominion Energy will maintain SCE&G and PSNC’s headquarters in Cayce, South Carolina and Gastonia, North Carolina, respectively; and

• Dominion Energy will seek to minimize reductions in local employment by allowing some DES employees supporting shared and common services functions and activities to be located in Cayce, South Carolina where it makes economic and practical sense to do so.

PURCHASE PRICE ALLOCATION

SCANA’s assets acquired and liabilities assumed will be measured at estimated fair value at closing and will be included in the Southeast Energy operating segment, which was established following the closing of the SCANA Combination. The majority of the operations acquired are subject to the rate setting authority of FERC and the North and South Carolina Commissions and are therefore accounted for pursuant to ASC 980, Regulated Operations. The fair values of SCANA’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the unaudited pro forma financial information, reflect any adjustments related to these amounts.

The fair value of SCANA’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions discussed above and the fair values of SCANA’s investments accounted for under the equity method will be determined using the income approach and the market approach. The valuation of SCANA’s long-term debt is considered a Level 2 fair value measurement. All other valuations will be considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future market prices.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed will be reflected as goodwill in the first quarter of 2019. The goodwill reflects the value associated with enhancing Dominion Energy’s portfolio of regulated operations in the growing southeast region of the U.S. The goodwill to be recognized will not be deductible for income tax purposes, and as such, no deferred taxes will be recorded related to goodwill.

The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at closing to be reflected in Dominion Energy’s Consolidated Balance Sheet in the first quarter of 2019. The allocation is subject to change during the measurement period as additional information is obtained about the facts and circumstances that existed at closing. The allocation of the purchase price excludes certain contracts and intangible assets related to nonregulated operations, including SEMI, equity method investments and certain income tax-related amounts, which will be included as Dominion Energy completes its valuation analysis. As a result, the amount of goodwill included below may change by a material amount as Dominion Energy finalizes the allocation of the purchase price during the first quarter of 2019.

	Amount
(millions)
Total current assets	$	1,756
Investments		213
Property, plant and equipment, net		10,982
Goodwill		2,438
Regulatory assets		4,219
Other deferred charges and other assets, including intangible assets		314
Total Assets		19,922
Total current liabilities		1,506
Long-term debt		6,707
Deferred income taxes		1,097
Regulatory liabilities		2,664
Other deferred credits and other liabilities		1,109
Total Liabilities		13,083
Total purchase price	$	6,839

INFORMATION ON ASSETS AND LIABILITIES ACQUIRED

Cash, Restricted Cash and Equivalents

The total current assets line above includes $389 million of cash, restricted cash and equivalents, of which $115 million is considered restricted, acquired by Dominion Energy in connection with the SCANA Combination.

Investments

Investments acquired in connection with the SCANA Combination include $20 million pertaining to certain investments accounted for under the equity method, at carrying value. Dominion Energy is still assessing the fair value of these investments.

Income Taxes

Deferred income taxes include a deferred tax asset recorded on a federal net operating loss carryforward of $1.8 billion and a state net operating loss carryforward of $2.4 billion. Based on the available evidence, Dominion Energy believes it is more likely than not that the benefit of the federal net operating loss will be utilized during the carryforward period, and therefore no valuation allowance has been established. Dominion Energy is still assessing whether a valuation allowance is required on the state net operating loss carryforward. Deferred income taxes also include unrecognized tax benefits of $106 million, which could increase as Dominion Energy continues and completes its evaluation of positions taken on SCANA’s federal and state income tax returns.

Property, Plant and Equipment

At the date of the SCANA Combination, major classes of property, plant and equipment and their respective balances for SCANA are as follows:

	2018
(millions)
Utility:
Generation	$	5,720
Transmission		2,416
Distribution		6,044
Storage		99
Nuclear fuel		611
General and other		631
Plant under construction		527
Total utility		16,048
Nonutility, including plant under construction		283
Total property, plant and equipment	$	16,331

In connection with the SCANA Combination, Dominion Energy intends to forego recovery of approximately $105 million of certain assets for which it expects to recognize a $79 million after-tax charge in the first quarter of 2019.

Regulated property will be depreciated on a straight-line basis based on projected service lives. Actual average composite depreciation rates for SCANA’s utility property, plant and equipment were as follows:

	2018
(millions)
Generation		2.61	%
Transmission		2.47
Distribution		2.48
Storage		2.48
General and other		5.64

Nonregulated property, plant and equipment, excluding land, will be depreciated on a straight-line basis over the remaining useful lives of such property, primarily ranging from 5 to 78 years.

SCE&G jointly owns and is the operator of Summer. At December 31, 2018, and subsequent to the SCANA Combination, SCE&G had a 66.7% ownership interest in Summer, of which its proportionate share of plant in service, accumulated depreciation and plant under construction was $1.5 billion, $644 million and $128 million, respectively. The co-owners are obligated to pay their share of all future construction expenditures and operating costs of Summer in the same proportion as their respective ownership interest.

Regulatory Assets

In addition to the items discussed above related to the NND Project, Dominion Energy intends to forego recovery of approximately $190 million of regulatory assets related to certain deferred income taxes for which it expects to recognize a $145 million after-tax charge in the first quarter of 2019.

Intangible Assets

Other current assets presented in the table above include intangible assets subject to regulatory recovery with a gross carrying value of $281 million and related accumulated amortization of $181 million. Such intangible assets have an estimated weighted-average amortization period of approximately five years. Annual amortization expense for these intangible assets is estimated to be as follows:

	2019		2020		2021		2022		2023
(millions)
SCANA	$	95	$	90	$	80	$	74	$	71

Asset Retirement Obligations

The purchase price allocation above includes $577 million of AROs, of which $23 million is considered to be a current liability. These AROs are associated with SCANA’s legal obligation to decommission Summer, as well as conditional obligations related to generation, transmission and distribution properties, including gas pipelines.

Short-Term and Long-Term Debt

At closing of the SCANA Combination, commercial paper and letters of credit outstanding, as well as capacity available under SCANA’s existing credit facilities were as follows:

	SCANA Corporation			SCE&G			PSNC			Total
(millions, except percentages)
Total facility limit	$	400		$	1,200	(1)	$	200		$	1,800
Letters of credit advances		40	(2)		—			—			40
Weighted-average interest rate		3.87	%		n/a			n/a			3.87	%
Outstanding commercial paper		2			73			98			173
Weighted-average interest rate		3.65	%		3.82	%		3.49	%		3.63	%
Outstanding letters of credit		37			—			—			37
Facility capacity available	$	321		$	1,127		$	102		$	1,550

(1) Includes South Carolina Fuel Company, Inc.’s $500 million credit facility.

(2) In January 2019, SCANA repaid $40 million in letter of credit advances.

In connection with the SCANA Combination, Dominion Energy intends to terminate SCANA, SCE&G and PSNC’s existing credit facilities, scheduled to expire in December 2020, and add SCE&G as a co-borrower to its $6.0 billion joint revolving credit facility in the first quarter of 2019 once certain regulatory approvals are obtained. In January 2019, Virginia Power and SCE&G, as co-borrowers, filed with the Virginia Commission and the South Carolina Commission, respectively, for approval. In February 2019, the Virginia Commission approved the request. SCE&G is required to obtain FERC approval to issue short-term indebtedness, including commercial paper, and to assume liabilities as a guarantor. In February 2019, Dominion Energy terminated South Carolina Fuel Company, Inc.’s existing credit facility, scheduled to expire in December 2020.

At closing of the SCANA Combination, SCANA had the following long-term debt outstanding which is part of the total consideration provided for the transaction.

	Weighted- average Coupon(1)			Amount
(millions, except percentages)
Unsecured medium term notes, due 2020 to 2022		5.42	%	$	800
Unsecured senior notes, due 2019 to 2034		3.44			70
First mortgage bonds, due 2021 to 2065		5.52			4,990
GENCO notes, due 2019 to 2024		5.49			40
Industrial and pollution control bonds, due 2028 to 2038(2)		3.52			122
PSNC senior debentures and notes, due 2020 to 2047		5.07			700
Other, due 2019 to 2027		3.46			73
Total principal				$	6,795
Current maturities of long-term debt					(59	)
Unamortized discount, premium and debt issuance costs, net					(29	)
SCANA total long-term debt				$	6,707

(1) Represents weighted-average coupon rates for debt outstanding at closing of the SCANA Combination.

(2) Includes variable rate debt of $68 million, with a weighted-average interest rate of 1.72%, which is hedged by fixed swaps.

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at closing of the SCANA Combination, were as follows:

	2019			2020			2021			2022			2023			Thereafter			Total
(millions, except percentages)
Unsecured senior notes	$	4		$	4		$	4		$	4		$	4		$	50		$	70
Unsecured medium term notes		—			250			300			250			—			—			800
First mortgage bonds		—			—			330			—			—			4,660			4,990
PSNC senior debentures and notes		—			100			150			—			—			450			700
GENCO notes		7			7			7			7			7			5			40
Industrial and pollution control bonds		—			—			—			—			—			122			122
Other		48			7			6			5			3			4			73
Total	$	59		$	368		$	797		$	266		$	14		$	5,291		$	6,795
Weighted-average coupon		3.91	%		6.26	%		4.20	%		5.22	%		3.29	%		5.51	%		5.36	%

In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any and all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of $1.0 billion. SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer.

Preferred Stock

At the closing of the SCANA Combination, authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were held by SCANA.

REGULATORY MATTERS AND PROCEEDINGS

Base Load Review Act

In 2016, the South Carolina Commission approved revised rates under the Base Load Review Act allowing the incorporation of financing costs associated with SCE&G’s incremental construction work in progress incurred for the NND Project and setting an allowed ROE of 10.5%. In July 2018, the South Carolina Commission issued orders implementing a June 2018 legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from its electric utility customers under the Base Load Review Act and altering certain provisions previously applicable under the Base Load Review Act, including redefining the standard of care required by the associated regulations and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the NND Project. These orders reduced the portion of SCE&G’s retail electric rates associated with the NND Project from approximately 18% of the average residential electric customer’s bill, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 2018. These lower rates remained in effect until February 2019, when the new rates pursuant to the SCANA Merger Approval Order became effective.

In June 2018, SCE&G filed a lawsuit in the U.S. District Court for the District of South Carolina challenging the constitutionality of the rate reductions under the Base Load Review Act. In the lawsuit, which was subsequently amended, SCE&G sought a declaration that the new laws are unconstitutional. In January 2019, SCE&G voluntarily dismissed this lawsuit.

2017 Tax Reform Act

In connection with the SCANA Merger Approval Order, the South Carolina Commission approved SCE&G’s provision of approximately $100 million in bill credits related to the 2017 Tax Reform Act’s impact on retail electric customer rates for the period beginning January 2018 through January 2019. These credits have been included in bills rendered on and after the first billing cycle of February 2019. In addition, the South Carolina Commission approved a tax rider whereby the effects of the reduction in the corporate income tax rate resulting from the 2017 Tax Reform Act will benefit retail electric customers. This tax rider is expected to reduce base rates to retail electric customers by approximately $67 million in each of 2019 and 2020, effective with the first billing cycle of February 2019.

In October 2018, the South Carolina Commission issued an order approving adjustment to SCE&G’s natural gas rate schedules, under the terms of the Natural Gas Rate Stabilization Act, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. The approved natural gas rate schedules also included a tax reform rate rider to refund certain income tax amounts previously collected from customers. These lower rates, representing a $20 million decreased revenue requirement, became effective for bills rendered on and after the first billing cycle in November 2018.

In December 2018, the North Carolina Commission issued an order approving PSNC’s proposed adjustments to customer rates, representing a $13 million decreased revenue requirement, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. These lower rates became effective for service rendered on and after January 1, 2019. Amounts collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC’s next general rate case proceeding or in three years, whichever is sooner. The reduction in the federal corporate tax rate and its impact on PSNC’s various rate riders will be addressed in future proceedings related to those riders.

DSM Programs

SCE&G has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2019, SCE&G filed an application with the South Carolina Commission seeking approval to recover $30 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. This matter is pending.

LEGAL PROCEEDINGS

The following describes certain legal proceedings to which SCANA or SCE&G were a party to at closing of the SCANA Combination. Dominion Energy intends to vigorously contest the lawsuits, claims and assessments which have been filed or initiated against SCANA and SCE&G. No reference to, or disclosure of, any proceeding, item or matter described below shall be construed as an admission or indication that such proceeding, item or matter is material. Due to the uncertainty surrounding these matters, Dominion Energy is unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on its results of operations, financial condition and/or cash flows.

Ratepayer Class Actions

In May 2018, a consolidated complaint against SCE&G, SCANA, and the State of South Carolina was filed in the State Court of Common Pleas in Hampton County, South Carolina (the SCE&G Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that SCE&G was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the NND Project, and that SCE&G committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that SCE&G may not charge its customers for any past or continuing costs of the NND Project, sought to have SCANA and SCE&G’s assets frozen and all monies recovered from Toshiba Corporation and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the NND Project.

In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the SCE&G Ratepayer Case. The settlement agreement, contingent upon the closing of the SCANA Combination, provides that SCANA and SCE&G would establish an escrow account and proceeds from the escrow account would be distributed to the class members, after payment of certain taxes, attorneys’ fees and other expenses and administrative costs. The escrow account would include (1) up to $2.0 billion, net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the escrow account in favor of class members over a period of time established by the South Carolina Commission in its order related to matters before the South Carolina Commission related to the NND Project, (2) a cash payment of $115 million and (3) the transfer of certain SCE&G-owned real estate or sales proceeds from the sale of such properties, which counsel for the SCE&G Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and SCE&G have funded this escrow account. The court has scheduled a fairness hearing on the settlement in May 2019. Any distribution from the escrow account is subject to court approval. As a result, Dominion Energy expects to reflect an approximately $180 million ($135 million after-tax) charge in the first quarter of 2019.

In September 2017, a purported class action was filed against Santee Cooper, SCE&G, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the State Court of Common Pleas in Hampton County, South Carolina (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the SCE&G Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the NND Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants, including certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina. In December 2018, Santee Cooper filed its answer to the plaintiffs’ fourth amended complaint and filed cross claims against SCE&G. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

RICO Class Action

In January 2018, a purported class action was filed, and subsequently amended, against SCANA, SCE&G and certain former executive officers in the U.S. District Court for the District of South Carolina. The plaintiff alleges, among other things, that SCANA, SCE&G and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. The SCE&G Ratepayer Class Action settlement described previously contemplates dismissal of claims by SCE&G ratepayers in this case against SCE&G, SCANA and their officers. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

State Court Shareholder Actions

In September 2017, a purported shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina. In September 2018, this action was consolidated with another action in the Business Court Pilot Program in Richland County. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the NND Project, and that the defendants were unjustly enriched by bonuses they were paid in connection with the project. The defendants have filed a motion to dismiss the consolidated action in favor of the pending federal derivative action. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal has been consolidated with a similar appeal and remains pending. In October 2018, the U.S. District Court for the District of South Carolina granted Dominion Energy’s motion to stay pending appeal. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

In February 2018, a purported class action was filed against certain former directors of SCANA and SCE&G and Dominion Energy in the State Court of Common Pleas in Richland County, South Carolina. The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the City of Warren Lawsuit. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the State Court of Common Pleas in Richland County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal has been consolidated with the City of Warren Lawsuit. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

Federal Court Shareholder Action

In November 2017, a purported shareholder derivative action was filed against SCANA and certain former executive officers and directors in the U.S. District Court of the District of South Carolina. Another purported shareholder derivative action was filed against nearly all of these defendants. In January 2018, the U.S. District Court for the District of South Carolina consolidated these suits, and the plaintiffs filed a consolidated amended complaint. The plaintiffs allege, among other things, that the defendants violated their fiduciary duties to shareholders by disseminating false and misleading information about the NND Project, failing to maintain proper internal controls, failing to properly oversee and manage SCANA and that the individual defendants were unjustly enriched in their compensation. In June 2018, the court denied the defendants’ motions to dismiss and in October 2018, the court denied SCANA’s motion to stay all proceedings pending investigation by a Special Litigation Committee, with leave to refile after the SCANA Merger Approval Order was issued. The plaintiffs have agreed to a stay of this action on the condition that defendants file a motion for judgment on the pleadings, which was filed in January 2019. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

Federal Court 10b-5 and Merger Actions

In September 2017, a purported class action was filed against SCANA and certain former executive officers and directors in the U.S. District Court for the District of South Carolina. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants. In January 2018, the U.S. District Court for the District of South Carolina consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated thereunder, and that the individually named defendants are liable under §20(a) of same act. In June 2018, the defendants filed motions to dismiss, which are pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

Employment Class Action and Indemnification

In July 2018, a case filed in the U.S. District Court for the District of South Carolina was certified as a class action on behalf of persons who were formerly employed at the NND Project. The plaintiffs allege, among other things, that SCANA, Fluor Corporation and Fluor Enterprises, Inc. violated the Worker Adjustment and Retraining Notification Act in connection with the decision to stop construction at the NND Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment, which is estimated to be as much as $75 million. SCE&G as co-owner of the NND project would have a 55% proportional share in the ultimate outcome. The ultimate loss could rise due to the Fluor defendants seeking indemnification from SCE&G.

In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against SCE&G and Santee Cooper. The plaintiffs make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants’ alleged failure and refusal to defend and indemnify the Fluor defendants in the aforementioned case. These cases are pending.

FILOT Litigation and Related Matters

In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against SCE&G in the State Court of Common Pleas in Fairfield County, South Carolina, making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of implied duty of good faith and fair dealing and unfair trade practices related to SCE&G’s termination of the FILOT agreement between SCE&G and Fairfield County related to the NND Project. The plaintiff sought a temporary and permanent injunction to prevent SCE&G from terminating the FILOT agreement. The plaintiff withdrew the motion for temporary injunction in December 2017. Dominion Energy is currently unable to make an estimate of the potential impacts to its consolidated financial statements related to this matter. This case is pending.

Governmental Proceedings and Investigations

In June 2018, SCE&G received a notice of proposed assessment of approximately $410 million, excluding interest, from the SCDOR following its audit of SCE&G’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NND Project, is based on the SCDOR’s position that SCE&G’s sales and use tax exemption for the NND Project does not apply because the facility will not become operational. SCE&G has protested the proposed assessment, which remains pending, and recorded an $11 million liability in its Consolidated Balance Sheet as of December 31, 2018 for its share of any taxes ultimately due.

In September and October 2017, SCANA was served with subpoenas issued by the U.S. Attorney’s Office for the District of South Carolina and the Staff of the SEC’s Division of Enforcement seeking documents related to the NND Project. In addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and SCE&G. These matters are pending. SCANA and SCE&G are cooperating fully with the investigations; however, Dominion Energy cannot currently predict whether or to what extent SCANA or SCE&G may incur a material liability.

Other

In December 2018, arbitration proceedings commenced between SCE&G and Cameco Corporation related to a supply agreement signed in May 2008. This agreement provides the terms and conditions under which SCE&G agreed to purchase uranium hexafluoride from Cameco Corporation over a period from 2010 to 2020. Cameco Corporation alleges that SCE&G violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for 2017 and 2018 delivery years. SCE&G denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement. Dominion Energy cannot determine the outcome or timing of this matter.

COMMITMENTS AND CONTINGENCIES

Abandoned NND Project

SCE&G, for itself and as agent for Santee Cooper, entered into an engineering, construction and procurement contract with Westinghouse and WECTEC in 2008 for the design and construction of the NND Project, of which SCE&G’s ownership share is 55%. Various difficulties were encountered in connection with the project. The ability of Westinghouse and WECTEC to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters preceded the filing for bankruptcy protection by Westinghouse and WECTEC in March 2017, and were the subject of comprehensive analyses performed by SCANA and Santee Cooper.

Based on the results of SCANA’s analysis, and in light of Santee Cooper’s decision to suspend construction on the NND Project, in July 2017, SCANA determined to stop the construction of the units and to pursue recovery of costs incurred in connection with the construction under the abandonment provisions of the Base Load Review Act or through other means. This decision by SCANA became the focus of numerous legislative, regulatory and legal proceedings. Some of these proceedings remain unresolved and are described above under the heading Legal Proceedings.

In September 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of Westinghouse and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by Westinghouse and WECTEC of the contract, and assert against Westinghouse and WECTEC any and all claims that are based thereon or that may be related thereto. SCE&G and Santee Cooper remain responsible for any claims that may be made by Westinghouse and WECTEC against them relating to the contract.

Westinghouse’s reorganization plan was confirmed by the Bankruptcy Court and became effective in August 2018. In connection with the effectiveness of the reorganization plan, the contract associated with the NND Project was deemed rejected. SCE&G is contesting approximately $285 million of filed liens in Fairfield County, South Carolina. Most of these asserted liens are claims that relate to work performed by Westinghouse subcontractors before the Westinghouse bankruptcy, although some of them are claims arising from work performed after the Westinghouse bankruptcy.

Westinghouse has indicated that some unsecured creditors have sought or may seek amounts beyond what Westinghouse allocated when it submitted its reorganization plan to the Bankruptcy Court. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the bankruptcy reorganization plan allocated by Westinghouse, it is possible that the reorganization plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant.

SCE&G and Santee Cooper are responsible for amounts owed to Westinghouse for valid work performed by Westinghouse subcontractors on the NND Project after the Westinghouse bankruptcy filing until termination of the interim assessment agreement. SCE&G does not believe that the claims asserted related to the interim assessment agreement period will exceed the amounts previously funded, whether relating to claims already paid or those remaining to be paid. SCE&G intends to oppose any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the interim assessment agreement. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.

Further, some Westinghouse subcontractors who have made claims against Westinghouse in the bankruptcy proceeding also filed against SCE&G and Santee Cooper in South Carolina state court for damages. Many of these claimants have also asserted construction liens against the NND Project site. SCE&G also intends to oppose these claims and liens. With respect to claims of Westinghouse Subcontractors, SCE&G believes there were sufficient amounts previously funded during the interim assessment agreement period to pay such validly asserted claims. With respect to the Westinghouse subcontractor claims which relate to other periods, SCE&G understands that such claims will be paid pursuant to Westinghouse’s confirmed bankruptcy reorganization plan. SCE&G further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, SCE&G believes that the Westinghouse subcontractors may be paid substantially (and potentially in full) by Westinghouse. While Dominion Energy cannot be assured that it will not have any exposure on account of unpaid Westinghouse subcontractor claims, which SCE&G is presently disputing, Dominion Energy believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.

Environmental Matters

Contingencies involving environmental matters, including ash pond and landfill closure costs, affecting SCANA have been included within Note 22.

Nuclear Insurance and Spent Nuclear Fuel

SCE&G’s maximum assessment for a nuclear incident under the Price-Anderson Amendments Act of 1988 would be $92 million per incident, but not more than $14 million per year, for its proportionate ownership interest in Summer. SCE&G currently maintains insurance policies, for itself and on behalf of Santee Cooper, with NEIL. The policies provide coverage to Summer for property damage and outage costs up to $2.8 billion resulting from an event of nuclear origin. The NEIL policies, in aggregate, are subject to a maximum loss of $2.8 billion for any single loss occurrence. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $23 million.

In addition, SCE&G currently maintains an excess property insurance policy, for itself and on behalf of Santee Cooper. The policy provides coverage to Summer for property damage and outage costs up to $415 million resulting from an event of non-nuclear origin. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $2 million.

SCE&G entered into a contract with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982.

Long-Term Purchase Agreements

SCANA has the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that a third party has used to secure financing for the facility that will provide the contracted goods or services:

	2019		2020		2021		2022		2023		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	31	$	30	$	30	$	30	$	30	$	310	$	461

(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities which expire at various dates through 2046. Capacity payments under the contracts are generally based on fixed dollar amounts per month.

Lease Commitments

SCANA is obligated under various operating leases for land, office space, furniture, equipment, rail cars and airplanes. Such leases expire at various dates through 2057.

	2019		2020		2021		2022		2023		Thereafter		Total
(millions)
Operating leases	$	10	$	8	$	7	$	6	$	4	$	30	$	65

Unaudited Pro Forma Information

Dominion Energy incurred transaction costs of $27 million, recorded in other operations and maintenance expense in the Consolidated Statements of Income for the year end December 31, 2018. These costs consist of professional fees and other miscellaneous costs.

The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the SCANA Combination had taken place on January 1, 2018. The unaudited pro forma financial information has been presented for illustrative purposes only and may change as Dominion Energy finalizes its valuation of certain assets acquired and liabilities assumed at the acquisition date. The unaudited pro forma financial information is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.

	Twelve Months Ended December 31,
	2018(1)
(millions, except EPS)
Operating Revenue	$	17,505
Net income attributable to Dominion Energy		2,081
Earnings Per Common Share – Basic	$	2.78
Earnings Per Common Share – Diluted	$	2.77

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

ACQUISITION OF DOMINION ENERGY QUESTAR

In September 2016, Dominion Energy completed the Dominion Energy Questar Combination and Dominion Energy Questar, a Rockies-based integrated natural gas company consisting of Questar Gas, Wexpro and Dominion Energy Questar Pipeline, became a wholly-owned subsidiary of Dominion Energy. Questar Gas has regulated gas distribution operations in Utah, southwestern Wyoming and southeastern Idaho. Wexpro develops and produces natural gas from reserves supplied to Questar Gas under a cost-of-service framework. Dominion Energy Questar Pipeline provides FERC-regulated interstate natural gas transportation and storage services in Utah, Wyoming and western Colorado. The Dominion Energy Questar Combination provides Dominion Energy with pipeline infrastructure that provides a principal source of gas supply to Western states. Dominion Energy Questar’s regulated businesses also provide further balance between Dominion Energy’s electric and gas operations.

In accordance with the terms of the Dominion Energy Questar Combination, at closing, each share of issued and outstanding Dominion Energy Questar common stock was converted into the right to receive $25.00 per share in cash. The total consideration was $4.4 billion based on 175.5 million shares of Dominion Energy Questar outstanding at closing.

Dominion Energy financed the Dominion Energy Questar Combination through the: (1) August 2016 issuance of $1.4 billion of 2016 Equity Units, (2) August 2016 issuance of $1.3 billion of senior notes, (3) September 2016 borrowing of $1.2 billion under a term loan agreement and (4) $500 million of the proceeds from the April 2016 issuance of common stock.

Purchase Price Allocation

Dominion Energy Questar’s assets acquired and liabilities assumed were measured at estimated fair value at the closing date and are included in the Gas Infrastructure operating segment. The majority of operations acquired are subject to the rate-setting authority of FERC, as well as the Utah Commission and/or the Wyoming Commission and therefore are accounted for pursuant to ASC 980, Regulated Operations. The fair values of Dominion Energy Questar’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts.

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

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

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at closing which reflects the following adjustments from the preliminary valuation recognized during the measurement period. During the fourth quarter of 2016, certain modifications were made to preliminary valuation amounts for acquired property, plant and equipment, current liabilities, and deferred income taxes, resulting in a $6 million net decrease to goodwill, which related primarily to the sale of Questar Fueling Company in December 2016 as further described in the Sale of Questar Fueling Company. In the third quarter of 2017, certain modifications were made to the valuation amounts for regulatory liabilities, current liabilities and deferred income taxes, resulting in a $6 million net increase to goodwill recorded in Dominion Energy’s Consolidated Balance Sheets. The modifications relate primarily to the finalization of Dominion Energy Questar’s 2016 tax return for the period January 1, 2016 through the Dominion Energy Questar Combination, as well as certain regulatory adjustments.

	Amount
(millions)
Total current assets	$	224
Investments(1)		58
Property, plant and equipment, net(2)		4,131
Goodwill		3,111
Total deferred charges and other assets, excluding goodwill		75
Total Assets		7,599
Total current liabilities(3)		793
Long-term debt(4)		963
Deferred income taxes		807
Regulatory liabilities		259
Asset retirement obligations		160
Other deferred credits and other liabilities		220
Total Liabilities		3,202
Total purchase price		4,397

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

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

(3) Includes $301 million of short-term debt, of which no amounts remain outstanding at December 31, 2018, as well as a $250 million variable interest rate term loan due in August 2017 that was paid in July 2017.

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

Regulatory Matters

The transaction required approval of Dominion Energy Questar’s shareholders, clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act and approval from both the Utah Commission and the Wyoming Commission. In February 2016, the Federal Trade Commission granted antitrust approval of the Dominion Energy Questar Combination under the Hart-Scott-Rodino Act. In May 2016, Dominion Energy Questar’s shareholders voted to approve the Dominion Energy Questar Combination. In August 2016 and September 2016, approvals were granted by the Utah Commission and the Wyoming Commission, respectively. Information regarding the transaction was also provided to the Idaho Commission, who acknowledged the Dominion Energy Questar Combination in October 2016, and directed Dominion Energy Questar to notify the Idaho Commission when it makes filings with the Utah Commission.

With the approval of the Dominion Energy Questar Combination in Utah and Wyoming, Dominion Energy agreed to the following:

• Contribution of $75 million to Dominion Energy Questar’s qualified and non-qualified defined-benefit pension plans and its other post-employment benefit plans within six months of the closing date. This contribution was made in January 2017.

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

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

Results of Operations and Unaudited Pro Forma Information

The impact of the Dominion Energy Questar Combination on Dominion Energy’s operating revenue and net income attributable to Dominion Energy in the Consolidated Statements of Income for the twelve months ended December 31, 2016 was an increase of $379 million and $73 million, respectively.

Dominion Energy incurred transaction and transition costs in 2018, 2017 and 2016, of which $9 million, $26 million and $58 million was recorded in other operations and maintenance expense, respectively, and $16 million was recorded in interest and related charges in 2016 in Dominion Energy’s Consolidated Statements of Income. These costs consist of the amortization of financing costs, the charitable contribution commitment described above, employee-related expenses, professional fees, and other miscellaneous costs.

The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the Dominion Energy Questar Combination had taken place on January 1, 2016. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.

	Twelve Months Ended December 31,
	2016(1)
(millions, except EPS)
Operating Revenue	$	12,497
Net income attributable to Dominion Energy		2,300
Earnings Per Common Share – Basic	$	3.73
Earnings Per Common Share – Diluted	$	3.73

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

Contribution of Dominion Energy Questar Pipeline to Dominion Energy Midstream

In October 2016, Dominion Energy entered into the Contribution Agreement under which Dominion Energy contributed Dominion Energy Questar Pipeline to Dominion Energy Midstream. Upon closing of the agreement on December 1, 2016, Dominion Energy Midstream became the owner of all of the issued and outstanding membership interests of Dominion Energy Questar Pipeline in exchange for consideration consisting of Dominion Energy Midstream common and convertible preferred units with a combined value of $467 million and cash payment of $823 million, $300 million of which is considered a debt-financed distribution, for a total of $1.3 billion. In addition, under the terms of the Contribution Agreement, Dominion Energy Midstream repurchased 6,656,839 common units from Dominion Energy, and repaid its $301 million promissory note to Dominion Energy in December 2016. The cash proceeds from these transactions were utilized in December 2016 to repay the $1.2 billion term loan agreement borrowed in September 2016. Since Dominion Energy consolidates Dominion Energy Midstream for financial reporting purposes, the transactions associated with the Contribution Agreement were eliminated upon consolidation. See Note 5 for the tax impacts of the transactions.

Sale of Questar Fueling Company

In December 2016, Dominion Energy completed the sale of Questar Fueling Company. The proceeds from the sale were $28 million, net of transaction costs. No gain or loss was recorded in Dominion Energy’s Consolidated Statements of Income, as the sale resulted in measurement period adjustments to the net assets acquired of Dominion Energy Questar. See the Purchase Price Allocation section above for additional details on the measurement period adjustments recorded.

Wholly-Owned Merchant Solar Projects

ACQUISITIONS

The following table presents significant completed acquisitions of wholly-owned merchant solar projects by Dominion Energy.

Completed Acquisition Date	Seller	Number of Projects			Project Location	Project Name(s)	Initial Acquisition (millions)(1)		Project Cost (millions)(2)		Date of Commercial Operations	MW Capacity
February 2017	Community Energy Solar, LLC		1		Virginia	Amazon Solar Farm Virginia—Southhampton	$	29	$	205	December 2017		100
March 2017	Solar Frontier Americas Holding LLC		1	(3)	California	Midway II		77		78	June 2017		30
May 2017	Cypress Creek Renewables, LLC		1		North Carolina	IS37		154		160	June 2017		79
June 2017	Hecate Energy Virginia C&C LLC		1		Virginia	Clarke County		16		16	August 2017		10
June 2017	Strata Solar Development, LLC/Moorings Farm 2 Holdco, LLC		2		North Carolina	Fremont, Moorings 2		20		20	November 2017		10
September 2017	Hecate Energy Virginia C&C LLC		1		Virginia	Cherrydale		40		41	November 2017		20
October 2017	Strata Solar Development, LLC		2		North Carolina	Clipperton, Pikeville		20		21	November 2017		10

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

(2) Includes acquisition cost.

(3) In April 2017, Dominion Energy discontinued efforts on the acquisition of the additional 20 MW solar project from Solar Frontier Americas Holding LLC.

In addition during 2016, Dominion Energy acquired 100% of the equity interests of seven solar projects in Virginia, North Carolina and South Carolina for an aggregate purchase price of $32 million, all of which was allocated to property, plant and equipment. The projects cost $421 million in total, including initial acquisition costs, and generate 221 MW combined. One of the projects commenced commercial operations in 2016 and the remaining projects commenced commercial operations in 2017.

Long-term power purchase, interconnection and operation and maintenance agreements have been executed for all of the projects described above. These projects are included in the Power Generation operating segment. Dominion Energy has claimed federal investment tax credits on these solar projects.

SALE OF INTEREST IN MERCHANT SOLAR PROJECTS

In September 2015, Dominion Energy 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 425 MW, to SunEdison. 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.

Non-Wholly-Owned Merchant Solar Projects

ACQUISITIONS OF FOUR BROTHERS AND THREE CEDARS

In June 2015, Dominion Energy acquired 50% of the units in Four Brothers from SunEdison for $64 million of consideration. Four Brothers operates four solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, generating 320 MW, at a cost of approximately $670 million.

In September 2015, Dominion Energy acquired 50% of the units in Three Cedars from SunEdison for $43 million of consideration. Three Cedars operates three solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, generating 210 MW, at a cost of approximately $450 million.

The Four Brothers and Three Cedars facilities operate under long-term power purchase, interconnection and operation and maintenance agreements. Dominion Energy claimed 99% of the federal investment tax credits on the projects.

Dominion Energy has assumed the majority of the agreements to provide administrative and support services in connection with 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 years ended December 31, 2018, 2017 and 2016.

In November 2016, NRG acquired the 50% of units in Four Brothers and Three Cedars previously held by SunEdison. Subsequent to Dominion Energy’s acquisition of Four Brothers and Three Cedars, SunEdison and NRG made contributions to Four Brothers and Three Cedars of $301 million in aggregate through December 31, 2017, which are reflected as noncontrolling interests in the Consolidated Balance Sheets. In August 2018, NRG’s ownership in Four Brothers and Three Cedars was transferred to GIP.

DOMINION ENERGY AND DOMINION ENERGY GAS

Blue Racer

See Note 9 for a discussion of transactions related to Blue Racer.

XML

Operating Revenue

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Operating Revenue

NOTE 4. OPERATING REVENUE

The Companies’ operating revenue, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, consists of the following:

Year Ended December 31,	2018
(millions)
Dominion Energy
Regulated electric sales:
Residential	$	3,413
Commercial		2,503
Industrial		490
Government and other retail		854
Wholesale		137
Nonregulated electric sales		1,294
Regulated gas sales:
Residential		818
Commercial		221
Other		36
Nonregulated gas sales		214
Regulated gas transportation and storage:
FERC-regulated		1,091
State-regulated		640
Nonregulated gas transportation and storage		442
Other regulated revenues		179
Other nonregulated revenues(1)(2)		563
Total operating revenue from contracts with customers		12,895
Other revenues(2)(3)		471
Total operating revenue	$	13,366
Virginia Power
Regulated electric sales:
Residential	$	3,413
Commercial		2,503
Industrial		490
Government and other retail		854
Wholesale		137
Other regulated revenues		132
Other nonregulated revenues(1)(2)		55
Total operating revenue from contracts with customers		7,584
Other revenues(1)(3)		35
Total operating revenue	$	7,619
Dominion Energy Gas
Regulated gas sales:
Residential	$	81
Other		27
Nonregulated gas sales(1)		13
Regulated gas transportation and storage:
FERC-regulated(1)		763
State-regulated(1)		605
NGL revenue(1)(2)		223
Management service revenue(1)		205
Other regulated revenues(1)		22
Other nonregulated revenues(1)		10
Total operating revenue from contracts with customers		1,949
Other revenues		(9	)
Total operating revenue	$	1,940

(1) See Notes 9 and 24 for amounts attributable to related parties and affiliates.

(2) Amounts above include $241 million and $206 million for the year ended December 31, 2018 primarily consisting of NGL sales at Dominion Energy and Dominion Energy Gas, respectively, which are considered to be goods transferred at a point in time. In addition, the amounts include $17 million and $11 million of sales of renewable energy credits at both Dominion Energy and Virginia Power for the year ended December 31, 2018, respectively, which are considered to be goods transferred at a point in time.

(3) Amounts above include $15 million of alternative revenue at Dominion Energy and Virginia Power for the year ended December 31, 2018.

The table below discloses the aggregate amount of the transaction price allocated to fixed-price performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and when the Companies expect to recognize this revenue. These revenues relate to contracts containing fixed prices where the Companies will earn the associated revenue over time as they stand ready to perform services provided. This disclosure does not include revenue related to performance obligations that are part of a contract with original durations of one year or less. In addition, this disclosure does not include expected consideration related to performance obligations for which the Companies elect to recognize revenue in the amount they have a right to invoice.

Revenue expected to be recognized on multi-year contracts in place at December 31, 2018	2019		2020		2021		2022		2023		Thereafter		Total
(millions)
Dominion Energy	$	1,643	$	1,563	$	1,448	$	1,319	$	1,154	$	13,693	$	20,820
Virginia Power		21		3		1		—		—		—		25
Dominion Energy Gas		600		560		475		384		268		1,612		3,899

Contract assets represent an entity’s right to consideration in exchange for goods and services that the entity has transferred to a customer. At December 31, 2018 and December 31, 2017, Dominion Energy’s contract asset balances were $42 million and $46 million, respectively. Dominion Energy Gas’ contract asset balances were $58 million and $66 million at December 31, 2018 and December 31, 2017, respectively. Dominion Energy and Dominion Energy Gas’ contract assets are recorded in other deferred charges and other assets in the Consolidated Balance Sheets. Contract liabilities represent an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration, or the amount that is due, from the customer. At December 31, 2018 and December 31, 2017, Dominion Energy’s contract liability balances were $106 million and $132 million, respectively. At December 31, 2018 and December 31, 2017, Virginia Power’s contract liability balances were $22 million and $50 million, respectively. At December 31, 2018 and December 31, 2017, Dominion Energy Gas’ contract liability balances were $40 million and $41 million, respectively. During the year ended December 31, 2018, Dominion Energy, Virginia Power and Dominion Energy Gas recognized revenue of $94 million, $25 million and $41 million, respectively, from the beginning contract liability balances as the Companies fulfilled their obligations to provide service to their customers. The Companies’ contract liabilities are recorded in other current liabilities and other deferred credits and other liabilities in the Consolidated Balance Sheets.

The Companies’ operating revenue, prior to the adoption of revised guidance for revenue recognition from contracts with customers, consisted of the following:

Year Ended December 31,	2017		2016
(millions)
Dominion Energy
Electric sales:
Regulated	$	7,383	$	7,348
Nonregulated		1,429		1,519
Gas sales:
Regulated		1,067		500
Nonregulated		457		354
Gas transportation and storage		1,786		1,636
Other		464		380
Total operating revenue	$	12,586	$	11,737
Virginia Power
Regulated electric sales	$	7,383	$	7,348
Other		173		240
Total operating revenue	$	7,556	$	7,588
Dominion Energy Gas
Gas sales:
Regulated	$	87	$	119
Nonregulated		20		13
Gas transportation and storage		1,435		1,307
NGL revenue		91		62
Other		181		137
Total operating revenue	$	1,814	$	1,638

XML

Income Taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Taxes

NOTE 5. INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. The Companies are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies as discussed in Note 2. The 2017 Tax Reform Act reduced the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. At the date of enactment, deferred tax assets and liabilities were remeasured based upon the new 21% enacted tax rate expected to apply when temporary differences are realized or settled. The specific provisions related to regulated public utilities in the 2017 Tax Reform Act generally allow for the continued deductibility of interest expense, changed the tax depreciation of certain property acquired after September 27, 2017, and continued certain rate normalization requirements for accelerated depreciation benefits.

As indicated in Note 2, certain of the Companies’ operations, including accounting for income taxes, are subject to regulatory accounting treatment. For regulated operations, many of the changes in deferred taxes represent amounts probable of collection from or refund to customers, and were recorded as either an increase to a regulatory asset or liability. The 2017 Tax Reform Act included provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred taxes may be determined by our regulators. See Note 13 for more information.

The Companies have accounted for the effects of the 2017 Tax Reform Act, although changes could occur as additional guidance is issued and finalized. In addition, certain states in which the Companies operate may or may not conform to some or all of the provisions of the 2017 Tax Reform Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities and could be material. The changes in deferred taxes resulting from the 2017 Tax Reform Act, and the Companies’ interpretations of proposed regulations issued in 2018, were recorded as either an increase to a regulatory liability or as an adjustment to the deferred tax provision.

Continuing Operations

Details of income tax expense for continuing operations including noncontrolling interests were as follows:

	Dominion Energy									Virginia Power									Dominion Energy Gas
Year Ended December 31,	2018			2017			2016			2018			2017			2016			2018			2017			2016
(millions)
Current:
Federal	$	(45	)	$	(1	)	$	(155	)	$	36		$	432		$	168		$	23		$	16		$	(27	)
State		108			(26	)		85			40			73			90			30			8			4
Total current expense (benefit)		63			(27	)		(70	)		76			505			258			53			24			(23	)
Deferred:
Federal
2017 Tax Reform Act impact		46			(851	)		—			21			(93	)		—			(11	)		(197	)		—
Taxes before operating loss carryforwards and investment tax credits		436			739			1,050			199			319			435			48			199			239
Tax utilization expense (benefit) of operating loss carryforwards		92			174			(161	)		—			4			(2	)		—			5			(2	)
Investment tax credits		(56	)		(200	)		(248	)		(51	)		(23	)		(25	)		—			—			—
State		(1	)		132			50			55			59			27			(4	)		20			1
Total deferred expense (benefit)		517			(6	)		691			224			266			435			33			27			238
Investment tax credit-gross deferral		2			5			35			2			5			35			—			—			—
Investment tax credit-amortization		(2	)		(2	)		(1	)		(2	)		(2	)		(1	)		—			—			—
Total income tax expense (benefit)	$	580		$	(30	)	$	655		$	300		$	774		$	727		$	86		$	51		$	215

The 2017 Tax Reform Act reduced the statutory federal income tax rate to 21% beginning in January 2018. Accordingly, current income taxes, and deferred income taxes that originate in 2018, are recorded at the new 21% rate. Dominion Energy had less than $1 million of state deferred income tax expense as a result of the reversal of deferred taxes upon the sale of its interest in Blue Racer and Fairless and Manchester. Dominion Energy’s current federal income taxes primarily include the recognition of a $47 million benefit related to a carryback claim for specified liability losses involving prior tax years.

The accounting for the reduction in the corporate income tax rate decreased deferred income tax expense by $851 million at Dominion Energy, $93 million at Virginia Power, and $197 million for Dominion Energy Gas for the year ending December 31, 2017. The decrease in deferred income taxes at Dominion Energy primarily relates to the remeasurement of deferred taxes on merchant operations and includes the effects at Virginia Power and Dominion Energy Gas. Virginia Power and Dominion Energy Gas have certain regulatory assets and liabilities that have not yet been charged or returned to customers through rates, or on which they do not earn a return, including unrecognized pension and other postretirement benefits. The remeasurement of the deferred taxes on these regulatory balances was charged to continuing operations in 2017. For ratemaking purposes, Dominion Energy Gas’ subsidiary DETI follows the cash method on pension contributions. Deferred taxes recorded on pension balances as required by GAAP are not included as a component of rates and therefore the remeasurement of these deferred taxes were charged to continuing operations in 2017.

In 2016, Dominion Energy realized a taxable gain resulting from the contribution of Dominion Energy Questar Pipeline to Dominion Energy Midstream. The contribution and related transactions resulted in increases in the tax basis of Dominion Energy Questar Pipeline’s assets and the number of Dominion Energy Midstream’s common and convertible preferred units held by noncontrolling interests. The direct tax effects of the transactions included a provision for current income taxes ($212 million) and an offsetting benefit for deferred income taxes ($96 million) and were charged to common shareholders’ equity. The federal tax liability was reduced by $129 million of tax credits generated in 2016 that otherwise would have resulted in additional credit carryforwards and a $17 million benefit provided by the domestic production activities deduction. These benefits, as indirect effects of the contribution transaction, were reflected in Dominion Energy’s 2016 current federal income tax expense.

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

	Dominion Energy									Virginia Power									Dominion Energy Gas
Year Ended December 31,	2018			2017			2016			2018			2017			2016			2018			2017			2016
U.S. statutory rate		21.0	%		35.0	%		35.0	%		21.0	%		35.0	%		35.0	%		21.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		3.0			2.0			2.4			4.7			3.7			3.8			3.2			2.4			0.5
Investment tax credits		(1.9	)		(6.3	)		(11.7	)		(3.5	)		(0.8	)		—			—			—			—
Production tax credits		(0.7	)		(0.7	)		(0.8	)		(0.7	)		(0.4	)		(0.5	)		—			—			—
Valuation allowances		0.3			0.2			1.2			—			—			0.1			1.8			0.3			—
Reversal of excess deferred income taxes		(2.0	)		—			—			(3.2	)		—			—			(1.7	)		—			—
Federal legislative change		1.5			(27.5	)		—			1.3			(4.0	)		—			(2.8	)		(29.5	)		—
State legislative change		(0.6	)		—			(0.6	)		—			—			—			0.2			—			—
AFUDC—equity		(0.8	)		(1.4	)		(0.6	)		(0.5	)		(0.6	)		(0.6	)		(0.6	)		(0.9	)		(0.2	)
Employee stock ownership plan deduction		(0.4	)		(0.6	)		(0.6	)		—			—			—			—			—			—
Other, net		(0.9	)		(1.7	)		(1.4	)		(0.1	)		0.6			(0.4	)		1.2			0.4			0.1
Effective tax rate		18.5	%		(1.0	)%		22.9	%		19.0	%		33.5	%		37.4	%		22.3	%		7.7	%		35.4	%

For the Companies’ rate-regulated entities, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, which in some cases will be 35%. The Companies have recorded an estimate of the portion of excess deferred income tax amortization in 2018, and changes in estimates of amounts probable of collection from or return to customers. The reversal of these excess deferred income taxes will impact the effective tax rate, and may ultimately impact rates charged to customers. As described in Note 13 to the Consolidated Financial Statements, the Companies decreased revenue and increased regulatory liabilities to offset these deferred tax impacts in accordance with applicable regulatory commission orders or formula rate mechanisms.

In 2018, the Companies applied the provisions of recently proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017 through December 31, 2017. The application of these changes increased Dominion Energy’s 2017 net operating loss carryforward, the benefit of which will be recognized at the 21% rate. As a result, Dominion Energy’s effective tax rate reflects a $23 million increase to deferred income tax expense associated with the remeasurement of this deferred tax asset. The application of these proposed regulations at Dominion Energy Gas had no impact on income tax expense as the changes in, and remeasurement of, deferred tax liabilities increased regulatory liabilities by $35 million. The effects of these changes at Virginia Power were immaterial. These amounts and adjustments represent the Companies’ best estimate based on available information, and could be subject to change based on additional guidance in yet to be finalized regulations. In addition, changes in estimates of amounts probable of return to or collection from customers increased deferred income tax expense at Virginia Power by $23 million and increased regulatory liabilities by $31 million. At Dominion Energy Gas similar changes in estimates decreased income tax expense by $11 million and regulatory liabilities by $16 million. These changes also impacted Dominion Energy. In addition, Dominion Energy and Dominion Energy Gas’ effective tax rates reflect the impacts of a state legislative change enacted in the second quarter of 2018 that was retroactive to January 1, 2018.

In 2017, the Companies’ effective tax rates reflect the net benefit of remeasurement of deferred taxes resulting from the lower corporate income tax rate promulgated by the 2017 Tax Reform Act, and the completion of audits by state tax authorities that resulted in the recognition of previously unrecognized tax benefits. At December 31, 2016, Virginia Power’s unrecognized tax benefits included state refund claims for open tax years through 2011. Management believed settlement of the claims, including interest thereon, within the next twelve months was remote. In June 2017, Virginia Power received and accepted a cash offer to settle the refund claims. As a result of the settlement, Virginia Power decreased its unrecognized tax benefits by $8 million, and recognized a $2 million tax benefit, which impacted its effective tax rate. Also in connection with this settlement, Virginia Power realized interest income of $11 million, which is reflected in other income in the Consolidated Statements of Income.

In 2016, Dominion Energy’s effective tax rate reflects a valuation allowance on a state credit not expected to be utilized by a Dominion Energy subsidiary which files a separate state return.

The Companies’ deferred income taxes consist of the following:

	Dominion Energy						Virginia Power						Dominion Energy Gas
At December 31,	2018			2017			2018			2017			2018			2017
(millions)
Deferred income taxes:
Total deferred income tax assets	$	2,748		$	2,686		$	1,054			$   923			$   318		$	320
Total deferred income tax liabilities		7,813			7,158			4,020			3,600			1,783			1,774
Total net deferred income tax liabilities	$	5,065		$	4,472		$	2,966			$2,677			$1,465		$	1,454
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	$	4,933		$	5,056		$	3,367			$2,969			$1,170		$	1,132
Excess deferred income taxes		(993	)		(1,050	)		(678	)		(687	)		(254	)		(244	)
Nuclear decommissioning		815			829			273			260			—			—
Deferred state income taxes		626			834			284			378			175			227
Federal benefit of deferred state income taxes		(132	)		(175	)		(60	)		(79	)		(37	)		(48	)
Deferred fuel, purchased energy and gas costs		60			1			59			(3	)		1			2
Pension benefits		81			141			(132	)		(104	)		431			419
Other postretirement benefits		(5	)		(51	)		55			44			(1	)		(2	)
Loss and credit carryforwards		(1,546	)		(1,536	)		(183	)		(111	)		(7	)		(4	)
Valuation allowances		158			146			5			5			12			3
Partnership basis differences		1,135			473			—			—			26			26
Other		(67	)		(196	)		(24	)		5			(51	)		(57	)
Total net deferred income tax liabilities	$	5,065		$	4,472		$	2,966			$2,677			$1,465		$	1,454
Deferred Investment Tax Credits – Regulated Operations		51			51			51			51			—			—
Total Deferred Taxes and Deferred Investment Tax Credits	$	5,116		$	4,523		$	3,017			$2,728			$1,465		$	1,454

The most significant impact reflected for the 2017 Tax Reform Act is the adjustment of the net accumulated deferred income tax liability for the reduction in the corporate income tax rate to 21%. In addition to amounts recognized in deferred income tax expense, the impacts of the 2017 Tax Reform Act decreased the accumulated deferred income tax liability by $3.1 billion at Dominion Energy, $1.9 billion at Virginia Power and $0.8 billion at Dominion Energy Gas at December 31, 2017. At Dominion Energy, the December 31, 2017 balance sheet reflected the impact of the 2017 Tax Reform Act on our regulatory liabilities which increased our regulatory liabilities by $4.2 billion, and created a corresponding deferred tax asset of $1.1 billion. At Virginia Power, our regulatory liabilities increased $2.6 billion, and created a deferred tax asset of $0.7 billion. At Dominion Energy Gas, our regulatory liabilities increased $1.0 billion, and created a deferred tax asset of $0.2 billion. These adjustments had no impact on 2017 cash flows.

At December 31, 2018, Dominion Energy had the following deductible loss and credit carryforwards:

	Deductible Amount		Deferred Tax Asset		Valuation Allowance			Expiration Period
(millions)
Federal losses		$   120	$	25		$    —			2034
Federal investment credits		—		1,007		—			2033-2038
Federal production credits		—		150		—			2031-2038
Other federal credits		—		62		—			2031-2038
State losses		1,126		73		(61	)		2019-2038
State minimum tax credits		—		122		—			No expiration
State investment and other credits		—		107		(90	)		2019-2025
Total		$1,246	$	1,546		$(151)

At December 31, 2018, Virginia Power had the following deductible loss and credit carryforwards:

	Deductible Amount		Deferred Tax Asset		Valuation Allowance			Expiration Period
(millions)
Federal losses		$  1		$   —		$ —			2034
Federal investment credits		—		113		—			2034-2038
Federal production and other credits		—		61		—			2031-2038
State investment credits		—		9		(5	)		2024
Total		$  1		$183		$(5	)

At December 31, 2018, Dominion Energy Gas had the following deductible loss and credit carryforwards:

	Deductible Amount		Deferred Tax Asset		Valuation Allowance			Expiration Period
(millions)
Other federal credits	$	—	$	1	$	—			2032-2037
State losses		53		5		(5	)		2036-2038
Total	$	53	$	6	$	(5	)

A reconciliation of changes in the Companies’ unrecognized tax benefits follows:

	Dominion Energy									Virginia Power									Dominion Energy Gas
	2018			2017			2016			2018			2017			2016			2018		2017			2016
(millions)
Balance at January 1	$	38		$	64		$	103		$	4		$	13		$	12			$ —	$	7			$29
Increases-prior period positions		10			1			9			—			—			4			—		—			1
Decreases-prior period positions		—			(9	)		(44	)		—			(1	)		(3	)		—		—			(19	)
Increases-current period positions		10			5			6			—			—			—			—		—			—
Settlements with tax authorities		(6	)		(23	)		(8	)		(1	)		(8	)		—			—		(7	)		(4	)
Expiration of statutes of limitations		(8	)		—			(2	)		(1	)		—			—			—		—			—
Balance at December 31	$	44		$	38		$	64		$	2		$	4		$	13			$—	$	—			$  7

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. For Dominion Energy and its subsidiaries, these unrecognized tax benefits were $37 million, $31 million and $45 million at December 31, 2018, 2017 and 2016, respectively. For Dominion Energy, the change in these unrecognized tax benefits increased income tax expense by $5 million in 2018 and decreased income tax expense by $9 million and $18 million in 2017 and 2016 respectively. For Virginia Power, these unrecognized tax benefits were $2 million, $3 million, and $9 million at December 31, 2018, 2017 and 2016, respectively. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by $2 million and $6 million in 2018 and 2017, respectively, and increased income tax expense by $1 million in 2016. For Dominion Energy Gas, these unrecognized tax benefits were less than $1 million, at December 31, 2018 and 2017, and $5 million at December 31, 2016. For Dominion Energy Gas, the change in these unrecognized tax benefits decreased income tax expense by less than $1 million, $5 million, and $11 million in 2018, 2017, and 2016, respectively.

Dominion Energy participates in the IRS Compliance Assurance Process which provides the opportunity to resolve complex tax matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions agreed to by the IRS. In 2018, Dominion Energy submitted carryback claims for specified liability losses involving prior tax years. These claims will be subject to IRS examination. With the exception of these claims, the IRS has completed its audit of tax years through 2017. The statute of limitations has not yet expired for tax years after 2012. Although Dominion Energy has not received a final letter indicating no changes to its taxable income for tax year 2017, no material adjustments are expected. The IRS examination of tax year 2018 is ongoing.

It is reasonably possible that settlement negotiations and expiration of statutes of limitations could result in a decrease in unrecognized tax benefits in 2019 by up to $18 million for Dominion Energy and less than $1 million for Virginia Power and Dominion Energy Gas. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could increase by up to $17 million for Dominion Energy and less than $1 million for Virginia Power and Dominion Energy Gas.

Otherwise, with regard to 2018 and prior years, Dominion Energy, Virginia Power and Dominion Energy Gas cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2019.

For each of the major states in which Dominion Energy operates, the earliest tax year remaining open for examination is as follows:

State	Earliest Open Tax Year
Pennsylvania(1)		2012
Connecticut		2015
Virginia(2)		2015
West Virginia(1)		2015
New York(1)		2011
Utah		2015

(1) Considered a major state for Dominion Energy Gas’ operations.

(2) Considered a major state for Virginia Power’s operations.

The Companies are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion Energy utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are generally subject to examination.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

NOTE 6. FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of the Companies’ own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion Energy applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments, and other investments including those held in nuclear decommissioning, Dominion Energy’s rabbi, and pension and other postretirement benefit plan trusts, in accordance with the requirements discussed above. Virginia Power applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments and other investments including those held in the nuclear decommissioning trust, in accordance with the requirements discussed above. Dominion Energy Gas applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments and other investments including those held in pension and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above.

Inputs and Assumptions

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including industry publications, and to a lesser extent, broker quotes. When evaluating pricing information provided by Designated Contract Market settlement pricing, other pricing services, or brokers, the Companies consider the ability to transact at the quoted price, i.e. if the quotes are based on an active market or an inactive market and to the extent which pricing models are used, if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases 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 sources.

For options and contracts with option-like characteristics where observable pricing information is not available from external sources, Dominion Energy and Virginia Power generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. Dominion Energy and Virginia Power use other option models under special circumstances, including but not limited to Spread Approximation Model and a Swing Option Model. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.

The inputs and assumptions used in measuring fair value include the following:

For commodity derivative contracts:

• Forward commodity prices

• Transaction prices

• Price volatility

• Price correlation

• Volumes

• Commodity location

• Interest rates

• Credit quality of counterparties and the Companies

• Credit enhancements

• Time value

For interest rate derivative contracts:

• Interest rate curves

• Credit quality of counterparties and the Companies

• Notional value

• Credit enhancements

• Time value

For foreign currency derivative contracts:

• Foreign currency forward exchange rates

• Interest rates

• Credit quality of counterparties and the Companies

• Notional value

• Credit enhancements

• Time value

For investments:

• Quoted securities prices and indices

• Securities trading information including volume and restrictions

• Maturity

• Interest rates

• Credit quality

Levels

The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

• Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as certain exchange-traded derivatives, and exchange-listed equities, U.S. and international equity securities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion Energy and Virginia Power, benefit plan trust funds for Dominion Energy and Dominion Energy Gas, and rabbi trust funds for Dominion Energy.

• Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include commodity forwards and swaps, interest rate swaps, foreign currency swaps and cash and cash equivalents, corporate debt instruments, government securities and other fixed income investments held in nuclear decommissioning trust funds for Dominion Energy and Virginia Power, benefit plan trust funds for Dominion Energy and Dominion Energy Gas and rabbi trust funds for Dominion Energy.

• Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for the Companies consist of long-dated commodity derivatives, FTRs, certain natural gas and power options and other modeled commodity derivatives.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. Alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments held in nuclear decommissioning and benefit plan trust funds, are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date. Alternative investments recorded at NAV are not classified in the fair value hierarchy.

Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.

Level 3 Valuations

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, certain forward market prices and implied price volatilities are considered unobservable.

The following table presents Dominion Energy’s quantitative information about Level 3 fair value measurements at December 31, 2018. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques		Unobservable Input		Range		Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)		$42		Discounted cash flow		Market price (per Dth)(3)		(2) - 8		(1	)
FTRs		15		Discounted cash flow		Market price (per MWh)(3)		(2) - 7		1
Physical options:
Natural gas		2		Option model		Market price (per Dth)(3)		1 - 8		3
						Price volatility (4)		18% - 73%		30	%
Electricity		11		Option model		Market price (per MWh)(3)		34 - 50		42
						Price volatility (4)		39% - 60%		49	%
Total assets		$70
Liabilities
Financial forwards:
FTRs		$  6		Discounted cash flow		Market price (per MWh)(3)		(2) - 6		—
Total liabilities		$  6

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

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

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

Nonrecurring Fair Value Measurements

DOMINION ENERGY

See Note 9 for information regarding an impairment charge recognized associated with Dominion Energy’s equity method investment in Fowler Ridge.

ATLANTIC COAST PIPELINE GUARANTEE AGREEMENT

In October 2017, Dominion Energy entered into a guarantee agreement in connection with Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility. See Note 22 for more information about the guarantee agreement associated with Atlantic Coast Pipeline’s revolving credit facility. Dominion Energy recorded a liability of $30 million, the fair value of the guarantee at inception, associated with the guarantee agreement. The fair value was estimated using a discounted cash flow method and is considered a Level 3 fair value measurement due to the use of a significant unobservable input related to the interest rate differential between the interest rate charged on the guaranteed revolving credit facility and the estimated interest rate that would have been charged had the loan not been guaranteed.

DOMINION ENERGY GAS

In the fourth quarter of 2018, subsequent to the announcement of the sale of Dominion Energy’s interest in Blue Racer, Dominion Energy Gas conducted a review of strategic alternatives of its remaining gathering and processing assets at DGP. Based on an evaluation of DGP’s long-lived assets for recoverability under a probability weighted approach, Dominion Energy Gas determined the assets were impaired. As a result of this evaluation, Dominion Energy Gas recorded a charge of $219 million ($165 million after-tax) in impairment of assets and related charges in its Consolidated Statements of Income to write down DGP’s property, plant and equipment to its estimated fair value of $190 million. The fair value of the property, plant and equipment was estimated using an income approach and market approach. The valuation is considered a Level 3 fair value measurement due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risks inherent in the future cash flows and market prices.

Recurring Fair Value Measurements

Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion Energy and Dominion Energy Gas’ pension and other postretirement benefit plans are presented in Note 21.

DOMINION ENERGY

The following table presents Dominion Energy’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)
December 31, 2018
Assets
Derivatives:
Commodity	$	—	$	180		$  70	$	250
Interest rate		—		18		—		18
Foreign currency		—		26		—		26
Investments(1):
Equity securities:
U.S.		3,277		—		—		3,277
Fixed income:
Corporate debt instruments		—		431		—		431
Government securities		455		688		—		1,143
Cash equivalents and other		11		—		—		11
Total assets	$	3,743	$	1,343		$  70	$	5,156
Liabilities
Derivatives:
Commodity	$	—	$	129		$    6	$	135
Interest rate		—		142		—		142
Foreign currency		—		2		—		2
Total liabilities	$	—	$	273		$    6	$	279
December 31, 2017
Assets
Derivatives:
Commodity	$	—	$	101		$157	$	258
Interest rate		—		17		—		17
Foreign currency		—		32		—		32
Investments(1):
Equity securities:
U.S.		3,493		—		—		3,493
Fixed income:
Corporate debt instruments		—		444		—		444
Government securities		307		794		—		1,101
Cash equivalents and other		34		—		—		34
Total assets	$	3,834	$	1,388		$157	$	5,379
Liabilities
Derivatives:
Commodity	$	—	$	190		$    7	$	197
Interest rate		—		85		—		85
Foreign currency		—		2		—		2
Total liabilities	$	—	$	277		$    7	$	284

(1) Includes investments held in the nuclear decommissioning and rabbi trusts. Excludes $220 million and $88 million of assets at December 31, 2018 and 2017, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

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

	2018			2017			2016
(millions)
Balance at January 1,	$	150		$	139		$	95
Total realized and unrealized gains (losses):
Included in earnings:
Operating Revenue		(2	)		3			—
Electric fuel and other energy-related purchases		(15	)		(42	)		(35	)
Purchased gas		—			1			—
Included in other comprehensive income (loss)		1			(2	)		—
Included in regulatory assets/liabilities		(44	)		42			(39	)
Settlements		(27	)		6			38
Purchases		—			—			87
Transfers out of Level 3		1			3			(7	)
Balance at December 31,	$	64		$	150		$	139
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date:
Operating Revenue	$	—		$	2		$	—
Electric fuel and other energy-related purchases		—			—			(1	)

VIRGINIA POWER

The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2018. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques		Unobservable Input		Range		Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)		$38		Discounted cash flow		Market price (per Dth)(3)		(2)-8		(1	)
FTRs		15		Discounted cash flow		Market price (per MWh)(3)		(2)-7		1
Physical options:
Natural gas		2		Option model		Market price (per Dth)(3)		1-8		3
						Price volatility (4)		18%-73%		30	%
Electricity		11		Option model		Market price (per MWh)(3)		34-50		42
						Price volatility (4)		39%-60%		49	%
Total assets		$66
Liabilities
Financial forwards:
FTRs		$  6		Discounted cash flow		Market price (per MWh)(3)		(2)-6		—
Total liabilities		$  6

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

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

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

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

	Level 1		Level 2		Level 3		Total
(millions)
December 31, 2018
Assets
Derivatives:
Commodity	$	—	$	24	$	66	$	90
Interest rate		—		3		—		3
Investments(1):
Equity securities:
U.S.		1,476		—		—		1,476
Fixed income:
Corporate debt instruments		—		221		—		221
Government securities		164		343		—		507
Total assets	$	1,640	$	591	$	66	$	2,297
Liabilities
Derivatives:
Commodity	$	—	$	9	$	6	$	15
Interest rate		—		88		—		88
Total liabilities	$	—	$	97	$	6	$	103
December 31, 2017
Assets
Derivatives:
Commodity	$	—	$	14	$	152	$	166
Investments(1):
Equity securities:
U.S.		1,566		—		—		1,566
Fixed income:
Corporate debt instruments		—		224		—		224
Government securities		168		326		—		494
Cash equivalents and other		16		—		—		16
Total assets	$	1,750	$	564	$	152	$	2,466
Liabilities
Derivatives:
Commodity	$	—	$	4	$	5	$	9
Interest rate		—		57		—		57
Total liabilities	$	—	$	61	$	5	$	66

(1) Includes investments held in the nuclear decommissioning trusts. Excludes $160 million and $27 million of assets at December 31, 2018 and 2017, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

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:

	2018			2017			2016
(millions)
Balance at January 1,	$	147		$	143		$	93
Total realized and unrealized gains (losses):
Included in earnings:
Electric fuel and other energy-related purchases		(17	)		(43	)		(35	)
Included in regulatory assets/liabilities		(45	)		40			(37	)
Settlements		(25	)		7			35
Purchases		—			—			87
Balance at December 31,	$	60		$	147		$	143

There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2018, 2017 and 2016.

DOMINION ENERGY GAS

The following table presents Dominion Energy 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)
December 31, 2018
Assets
Commodity		$ —		$  3		$ —		$  3
Foreign currency		—		26		—		26
Total assets		$ —		$29		$ —		$29
Liabilities
Interest rate		$ —		$17		$ —		$17
Foreign currency		—		2		—		2
Total liabilities		$ —		$19		$ —		$19
December 31, 2017
Assets
Foreign currency		$ —		$32		$ —		$32
Total assets		$ —		$32		$ —		$32
Liabilities
Commodity		$ —		$  4		$   2		$  6
Foreign currency		—		2		—		2
Total liabilities		$ —		$  6		$   2		$  8

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

	2018			2017			2016
(millions)
Balance at January 1,	$	(2	)	$	(2	)	$	6
Total realized and unrealized gains (losses):
Included in other comprehensive income (loss)		1			(3	)		—
Transfers out of Level 3		1			3			(8	)
Balance at December 31,	$	—		$	(2	)	$	(2	)

There were no gains and losses included in earnings in the Level 3 fair value category for the years ended December 31, 2018, 2017 and 2016. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2018, 2017 and 2016.

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, restricted cash and equivalents, customer and other receivables, affiliated 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:

December 31,	2018				2017
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion Energy
Long-term debt, including securities due within one year(2)	$	29,952		$31,045	$	28,666		$31,233
Credit facility borrowings		73		73		—		—
Junior subordinated notes(3)		3,430		3,358		3,981		4,102
Remarketable subordinated notes(3)		1,386		1,340		1,379		1,446
Virginia Power
Long-term debt, including securities due within one year(3)	$	11,671		$12,400	$	11,346		$12,842
Dominion Energy Gas
Long-term debt, including securities due within one year(4)	$	4,058		$  4,072	$	3,570		$  3,719

(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 issuances 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 or premium, and foreign currency remeasurement adjustments. At December 31, 2018, and 2017, includes the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt of $(20) million and $(22) million, respectively.

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

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

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Derivatives And Hedge Accounting Activities

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives And Hedge Accounting Activities

NOTE 7. DERIVATIVES AND HEDGE ACCOUNTING ACTIVITIES

See Note 2 for the Companies’ accounting policies, objectives, and strategies for using derivative instruments. See Note 6 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 Energy’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. Virginia Power and Dominion Energy Gas’ derivative contracts include over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. 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. See Note 23 for further information regarding credit-related contingent features for the Companies derivative instruments.

DOMINION ENERGY

Balance Sheet Presentation

The tables below present Dominion Energy’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

			December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	175	$	12	$	—	$	163	$	174	$	9	$	—	$	165
Exchange		68		68		—		—		80		80		—		—
Interest rate contracts:
Over-the-counter		18		1		—		17		17		8		—		9
Foreign currency contracts:
Over-the-counter		26		2		—		24		32		2		—		30
Total derivatives, subject to a master netting or similar arrangement	$	287	$	83	$	—	$	204	$	303	$	99	$	—	$	204

(1) Excludes $7 million and $4 million of derivative assets at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.

	December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	19	$	12	$	—	$	7	$	76	$	9	$	6	$	61
Exchange		115		68		47		—		120		80		40		—
Interest rate contracts:
Over-the-counter		142		1		—		141		85		8		—		77
Foreign currency contracts:
Over-the-counter		2		2		—		—		2		2		—		—
Total derivatives, subject to a master netting or similar arrangement	$	278	$	83	$	47	$	148	$	283	$	99	$	46	$	138

(1) Excludes $1 million of derivative liabilities at December 31, 2018 and 2017, which are not subject to master netting or similar arrangements.

Volumes

The following table presents the volume of Dominion Energy’s derivative activity as of December 31, 2018. 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)		56		27
Basis		214		557
Electricity (MWh):
Fixed price(1)		11,101,869		1,537,200
FTRs		45,351,415		—
Liquids (Gal)(2)		14,413,200		—
Interest rate(3)	$	2,700,000,000	$	3,915,839,913
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 years ended December 31, 2018, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were immaterial. 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 Energy’s Consolidated Balance Sheet at December 31, 2018:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12  Months After-Tax			Maximum Term
(millions)
Commodities:
Gas		$     —			$   1			36 months
Electricity		27			26			24 months
Other		2			2			3 months
Interest rate		(276	)		(29	)		396 months
Foreign currency		12			(2	)		90 months
Total		$(235	)		$ (2	)

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

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of Dominion Energy’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 December 31, 2018
ASSETS
Current Assets
Commodity		$  55		$154	$	209
Interest rate		14		—		14
Total current derivative assets(1)		69		154		223
Noncurrent Assets
Commodity		6		35		41
Interest rate		4		—		4
Foreign currency		26		—		26
Total noncurrent derivative assets(2)		36		35		71
Total derivative assets		$105		$189	$	294
LIABILITIES
Current Liabilities
Commodity		$  17		$112	$	129
Interest rate		26		—		26
Foreign currency		2		—		2
Total current derivative liabilities(3)		45		112		157
Noncurrent Liabilities
Commodity		5		1		6
Interest rate		116		—		116
Total noncurrent derivative liabilities(4)		121		1		122
Total derivative liabilities		$166		$113	$	279
At December 31, 2017
ASSETS
Current Assets
Commodity		$    5		$158	$	163
Interest rate		6		—		6
Total current derivative assets(1)		11		158		169
Noncurrent Assets
Commodity		—		95		95
Interest rate		11		—		11
Foreign currency		32		—		32
Total noncurrent derivative assets(2)		43		95		138
Total derivative assets		$  54		$253	$	307
LIABILITIES
Current Liabilities
Commodity		$103		$  92	$	195
Interest rate		53		—		53
Foreign currency		2		—		2
Total current derivative liabilities(3)		158		92		250
Noncurrent Liabilities
Commodity		1		1		2
Interest rate		32		—		32
Total noncurrent derivative liabilities(4)		33		1		34
Total derivative liabilities		$191		$  93	$	284

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

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

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

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

The following tables present the gains and losses on Dominion Energy’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)
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$  (90	)
Electric fuel and other energy-related purchases					14
Total commodity		$  64			$(76	)		$ —
Interest rate(3)		(18	)		(48	)		39
Foreign currency(4)		(6	)		(13	)		—
Total		$  40			$(137	)		$39
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$  81
Purchased gas					(2	)
Total commodity		$    1			$  79			$ —
Interest rate(3)		(8	)		(52	)		(58	)
Foreign currency(4)		18			20			—
Total		$  11			$  47			$(58	)
Year Ended December 31, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$330
Purchased gas					(13	)
Electric fuel and other energy-related purchases					(10	)
Total commodity		$164			$307			$ —
Interest rate(3)		(66	)		(31	)		(26	)
Foreign currency(4)		(6	)		(17	)		—
Total		$  92			$259			$(26	)

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

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

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

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2018			2017			2016
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue		$(28	)		$  18			$  2
Purchased gas		11			(3	)		4
Electric fuel and other energy-related purchases		(9	)		(59	)		(70	)
Other operations & maintenance		—			(1	)		1
Total		$(26	)		$(45	)		$(63	)

(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy’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, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

	December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter		$64		$  6		$—		$58		$155		$  4		$—		$151
Interest rate contracts:
Over-the-counter		3		—		—		3		—		—		—		—
Total derivatives, subject to a master netting or similar arrangement		$67		$  6		$—		$61		$155		$  4		$—		$151

(1) Excludes $26 million and $11 million of derivative assets at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.

	December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet						Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts:
Over-the-counter		$  6		$  6		$—		$—		$  4		$  4		$—		$ —
Interest rate contracts:
Over-the-counter		88		—		—		88		57		—		—		57
Total derivatives, subject to a master netting or similar arrangement		$94		$  6		$—		$88		$61		$  4		$—		$57

(1) Excludes $9 million and $5 million of derivative liabilities at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.

Volumes

The following table presents the volume of Virginia Power’s derivative activity at December 31, 2018. 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)		29		8
Basis		136		488
Electricity (MWh):
Fixed price(1)		367,019		—
FTRs		45,351,415		—
Interest rate(2)	$	700,000,000	$	1,200,000,000

(1) Includes options.

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

Ineffectiveness and AOCI

For the years ended December 31, 2018, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective were immaterial.

The following table presents selected information related to losses on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at December 31, 2018:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Interest rate	$	(13	)	$	(1	)		396 months
Total	$	(13	)	$	(1	)

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

Fair Value and Gains and Losses on Derivative Instruments

The following tables present 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 December 31, 2018
ASSETS
Current Assets
Commodity		$ —		$   60		$   60
Interest rate		3		—		3
Total current derivative assets(1)		3		60		63
Noncurrent Assets
Commodity		—		30		30
Total noncurrent derivative assets(2)		—		30		30
Total derivative assets		$  3		$   90		$   93
LIABILITIES
Current Liabilities
Commodity		$ —		$   15		$   15
Interest rate		10		—		10
Total current derivative liabilities(3)		10		15		25
Noncurrent Liabilities
Interest rate		78		—		78
Total noncurrent derivatives liabilities(4)		78		—		78
Total derivative liabilities		$88		$   15		$103
At December 31, 2017
ASSETS
Current Assets
Commodity		$ —		$   75		$   75
Total current derivative assets(1)		—		75		75
Noncurrent Assets
Commodity		—		91		91
Total noncurrent derivative assets(2)		—		91		91
Total derivative assets		$ —		$166		$166
LIABILITIES
Current Liabilities
Commodity		$ —		$     9		$     9
Interest rate		44		—		44
Total current derivative liabilities(3)		44		9		53
Noncurrent Liabilities
Interest rate		13		—		13
Total noncurrent derivative liabilities(4)		13		—		13
Total derivative liabilities		$57		$     9		$   66

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

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

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

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

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

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Interest rate(3)	$	2		$	(1	)	$	39
Total	$	2		$	(1	)	$	39
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Interest rate(3)	$	(8	)	$	(1	)	$	(58	)
Total	$	(8	)	$	(1	)	$	(58	)
Year Ended December 31, 2016
Derivative type and location of gains (losses):
Interest rate(3)	$	(3	)	$	(1	)	$	(26	)
Total	$	(3	)	$	(1	)	$	(26	)

(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.

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2018		2017		2016
(millions)
Derivative type and location of gains (losses):
Commodity(2)		$2		$(57)		$(70)
Total		$2		$(57)		$(70)

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

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

DOMINION ENERGY GAS

Balance Sheet Presentation

The tables below present Dominion Energy Gas’ derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

	December 31, 2018								December 31, 2017
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	3	$	—	$	—	$	3	$	—	$	—	$	—	$	—
Foreign currency contracts:
Over-the-counter		26		2		—		24		32		2		—		30
Total derivatives, subject to a master netting or similar arrangement	$	29	$	2	$	—	$	27	$	32	$	2	$	—	$	30

	December 31, 2018								December 31, 2017
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Off set in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts
Over-the-counter	$	—	$	—	$	—	$	—	$	6	$	—	$	—	$	6
Interest rate contracts:
Over-the-counter		17		—		—		17		—		—		—		—
Foreign currency contracts:
Over-the-counter		2		2		—		—		2		2		—		—
Total derivatives, subject to a master netting or similar arrangement	$	19	$	2	$	—	$	17	$	8	$	2	$	—	$	6

Volumes

The following table presents the volume of Dominion Energy Gas’ derivative activity at December 31, 2018. 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
NGLs (Gal)		14,413,200		—
Interest rate(1)	$	300,000,000	$	750,000,000
Foreign currency(1)(2)	$	—	$	280,000,000

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

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

Ineffectiveness and AOCI

For the years ended December 31, 2018, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective were immaterial.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2018:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
NGLs		$     2			$   2			3 months
Interest rate		(39	)		(4	)		312 months
Foreign currency		12			(2	)		90 months
Total		$(25	)		$(4	)

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

Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of Dominion Energy 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 December 31, 2018
ASSETS
Current Assets
Commodity		$  3		$—		$  3
Total current derivative assets(1)		3		—		3
Noncurrent Assets
Foreign currency		26		—		26
Total noncurrent derivative assets(2)		26		—		26
Total derivative assets		$29		$—		$29
LIABILITIES
Current Liabilities
Interest rate		$  9		$—		$  9
Foreign currency		2		—		2
Total current derivative liabilities(3)		11		—		11
Noncurrent Liabilities
Interest rate		8		—		8
Total noncurrent derivative liabilities(4)		8		—		8
Total derivative liabilities		$19		$—		$19
At December 31, 2017
ASSETS
Noncurrent Assets
Foreign currency	$32		$—		$32
Total noncurrent derivative assets(2)		32		—		32
Total derivative assets		$32		$—		$32
LIABILITIES
Current Liabilities
Commodity		$  6		$—		$  6
Foreign currency		2		—		2
Total current derivative liabilities(3)		8		—		8
Total derivative liabilities		$  8		$—		$  8

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

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

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

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

The following tables present the gains and losses on Dominion Energy 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)
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$  (8	)
Total commodity		$   1			$  (8	)
Interest rate(2)		(18	)		(6	)
Foreign currency(3)		(6	)		(13	)
Total		$(23	)		$(27	)
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$  (8	)
Total commodity		$(10	)		$  (8	)
Interest rate(2)		—			(5	)
Foreign currency(3)		18			20
Total		$   8			$   7
Year Ended December 31, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$   4
Total commodity		$(12	)		$   4
Interest rate(2)		(8	)		(2	)
Foreign currency(3)		(6	)		(17	)
Total		$(26	)		$(15	)

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

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

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

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives
Year Ended December 31,	2018			2017		2016
(millions)
Derivative type and location of gains (losses):
Commodity
Operating revenue		$(11	)		$—		$1
Total		$(11	)		$—		$1

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Earnings Per Share

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Earnings Per Share

NOTE 8. EARNINGS PER SHARE

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

	2018		2017		2016
(millions, except EPS)
Net Income Attributable to Dominion Energy	$	2,447	$	2,999	$	2,123
Average shares of common stock outstanding – Basic		654.2		636.0		616.4
Net effect of dilutive securities(1)		0.7		—		0.7
Average shares of common stock outstanding – Diluted		654.9		636.0		617.1
Earnings Per Common Share – Basic	$	3.74	$	4.72	$	3.44
Earnings Per Common Share – Diluted	$	3.74	$	4.72	$	3.44

(1) Dilutive securities for 2018 consist primarily of forward sale agreements, effective April 2018 to December 2018. Dilutive securities for 2016 consist primarily of the 2013 Equity Units. See Notes 17 and 19 for more information.

The 2014 Equity Units were excluded from the calculation of diluted EPS for the year ended December 31, 2016 as the dilutive stock price threshold was not met. The 2016 Equity Units were excluded from the calculation of diluted EPS for the years ended December 31, 2018, 2017 and 2016, as the dilutive stock price threshold was not met. See Note 17 for more information. The Dominion Energy Midstream convertible preferred units were potentially dilutive securities but had no effect on the calculation of diluted EPS for the years ended December 31, 2018, 2017 and 2016. See Note 19 for more information.

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Investments

12 Months Ended

Dec. 31, 2018

Investments, Debt and Equity Securities [Abstract]

Investments

NOTE 9. INVESTMENTS

DOMINION ENERGY

Equity and Debt Securities

RABBI TRUST SECURITIES

Equity and debt securities and cash equivalents in Dominion Energy’s rabbi trusts and classified as trading totaled $111 million and $112 million at December 31, 2018 and 2017, respectively.

DECOMMISSIONING TRUST SECURITIES

Dominion Energy holds equity and debt securities, cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion Energy’s decommissioning trust funds are summarized below:

	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Fair Value
(millions)
December 31, 2018
Equity securities:(1)
U.S.		$1,741		$1,640		$(51)			$3,330
Fixed income securities:(2)
Corporate debt instruments		435		5		(9)			431
Government securities		1,092		17		(12)			1,097
Common/collective trust funds		76		—		—			76
Cash equivalents and other(3)		4		—		—			4
Total		$3,348		$1,662		$(72)	(4)		$4,938
December 31, 2017
Equity securities:(2)
U.S.		$1,569		$1,857		$ —			$3,426
Fixed income securities:(2)
Corporate debt instruments		430		15		(1)			444
Government securities		1,039		27		(5)			1,061
Common/collective trust funds		60		—		—			60
Cost method investments		68		—		—			68
Cash equivalents and other(3)		34		—		—			34
Total		$3,200		$1,899		$  (6)	(4)		$5,093

(1) Effective January 2018, unrealized gains and losses on equity securities, including those previously classified as cost method investments, are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(2) Unrealized gains and losses on equity securities (for 2017) and fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(3) Includes pending sales of securities of $5 million at December 31, 2017.

(4) The fair value of securities in an unrealized loss position was $833 million and $565 million at December 31, 2018 and 2017, respectively.

The portion of unrealized gains and losses that relates to equity securities held within Dominion Energy’s nuclear decommissioning trusts is summarized below:

	Twelve Months Ended December 31, 2018
(millions)
Net losses recognized during the period	$	(245	)
Less: Net gains recognized during the period on securities sold during the period		(58	)
Unrealized losses recognized during the period on securities still held at December 31, 2018(1)	$	(303	)

(1) Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

The fair value of Dominion Energy’s debt securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2018 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	167
Due after one year through five years		389
Due after five years through ten years		376
Due after ten years		672
Total	$	1,604

Presented below is selected information regarding Dominion Energy’s equity and debt securities with readily determinable fair values held in nuclear decommissioning trust funds.

Year Ended December 31,	2018		2017		2016
(millions)
Proceeds from sales	$	1,804	$	1,831	$	1,422
Realized gains(1)		140		166		128
Realized losses(1)		91		71		55

(1) Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.

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

Year Ended December 31,	2018			2017			2016
(millions)
Total other-than-temporary impairment losses(1)	$	30		$	44		$	51
Losses recorded to the nuclear decommissioning trust regulatory liability		—			(16	)		(16	)
Losses recognized in other comprehensive income (before taxes)		(30	)		(5	)		(12	)
Net impairment losses recognized in earnings	$	—		$	23		$	23

(1) Amounts include other-than-temporary impairment losses for debt securities of $5 million and $13 million at December 31, 2017 and 2016, respectively.

VIRGINIA POWER

Virginia Power holds equity and debt securities, 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		Total Unrealized Losses			Fair Value
(millions)
December 31, 2018
Equity securities:(1)
U.S.		$858		$751		$(24	)		$1,585
Fixed income securities:(2)
Corporate debt instruments		224		2		(5	)		221
Government securities		504		7		(5	)		506
Common/collective trust funds		51		—		—			51
Cash equivalents and other(3)		6		—		—			6
Total		$1,643		$760		$(34)	(4)		$2,369
December 31, 2017
Equity securities:(2)
U.S.		$   734		$831		$—			$1,565
Fixed income securities:(2)
Corporate debt instruments		216		8		—			224
Government securities		482		13		(2	)		493
Common/collective trust funds		27		—		—			27
Cost method investments		68		—		—			68
Cash equivalents and other(3)		22		—		—			22
Total		$1,549		$852		$(2	)(4)		$2,399

(1) Effective January 2018, unrealized gains and losses on equity securities, including those previously classified as cost method investments, are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(2) Unrealized gains and losses on equity securities (for 2017) and fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(3) Includes pending sales of securities of $6 million at both December 31, 2018 and 2017.

(4) The fair value of securities in an unrealized loss position was $404 million and $234 million at December 31, 2018 and 2017, respectively.

The portion of unrealized gains and losses that relates to equity securities held within Virginia Power’s nuclear decommissioning trusts is summarized below:

	Twelve Months Ended December 31, 2018
(millions)
Net losses recognized during the period	$	(105	)
Less: Net gains recognized during the period on securities sold during the period		(32	)
Unrealized losses recognized during the period on securities still held at December 31, 2018(1)	$	(137	)

(1) Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

The fair value of Virginia Power’s debt securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2018, by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	54
Due after one year through five years		156
Due after five years through ten years		210
Due after ten years		358
Total	$	778

Presented below is selected information regarding Virginia Power’s equity and debt securities with readily determinable fair values held in nuclear decommissioning trust funds.

Year Ended December 31,	2018		2017		2016
(millions)
Proceeds from sales	$	887	$	849	$	733
Realized gains(1)		60		75		63
Realized losses(1)		27		30		27

(1) Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.

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

Year Ended December 31,	2018			2017			2016
(millions)
Total other-than-temporary impairment losses(1)	$	15		$	20		$	26
Losses recorded to the nuclear decommissioning trust regulatory liability		—			(16	)		(16	)
Losses recognized in other comprehensive income (before taxes)		(15	)		(2	)		(7	)
Net impairment losses recognized in earnings	$	—		$	2		$	3

(1) Amounts include other-than-temporary impairment losses for debt securities of $2 million and $8 million at December 31, 2017 and 2016 , respectively.

Equity Method Investments

DOMINION ENERGY AND DOMINION ENERGY GAS

Investments that Dominion Energy and Dominion Energy Gas account for under the equity method of accounting are as follows:

Company	Ownership%			Investment Balance				Description
As of December 31,				2018		2017
(millions)
Dominion Energy
Atlantic Coast Pipeline		48	%	$	820	$	382		Gas transmission system
Blue Racer		50	%		—		691		Midstream gas and     related services
Iroquois		50	%(1)		302		311		Gas transmission system
Fowler Ridge		50	%		82		81		Wind-powered merchant     generation facility
Other(2)		various			74		79
Total				$	1,278	$	1,544
Dominion Energy Gas
Iroquois		24.07	%	$	91	$	95		Gas transmission system
Total				$	91	$	95

(1) Comprised of Dominion Energy Midstream’s interest of 25.93% and Dominion Energy Gas’ interest of 24.07%. See Note 15 for more information.

(2) Liability of less than $1 million and $17 million associated with NedPower recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets as of December 31, 2018 and 2017, respectively. See additional discussion of NedPower below.

Dominion Energy’s equity earnings on its investments totaled $197 million, $14 million and $111 million in 2018, 2017 and 2016, respectively, included in other income in Dominion Energy’s Consolidated Statements of Income. Dominion Energy received distributions from these investments of $209 million, $419 million and $104 million in 2018, 2017 and 2016, respectively. As of December 31, 2018 and 2017, the carrying amount of Dominion Energy’s investments exceeded its share of underlying equity in net assets by $161 million and $249 million, respectively. At December 31, 2018 these differences are comprised of $146 million of equity method goodwill that is not being amortized and $15 million related to basis differences from Dominion Energy’s investments in wind projects, which are being amortized over the useful lives of the underlying assets, and in Atlantic Coast Pipeline, which is being amortized over the term of its credit facility. At December 31, 2017 these differences are comprised of $176 million of equity method goodwill and $73 million related to basis differences from Dominion Energy’s investments in Blue Racer and wind projects, and in Atlantic Coast Pipeline.

Dominion Energy Gas’ equity earnings on its investment totaled $24 million in 2018 and $21 million in 2017 and 2016. Dominion Energy Gas received distributions from its investment of $28 million, $24 million and $22 million in 2018, 2017 and 2016, respectively. As of December 31, 2018 and 2017, the carrying amount of Dominion Energy Gas’ investment 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 Energy Gas sold 0.65% of the noncontrolling partnership interest in Iroquois to TransCanada for approximately $7 million, which resulted in a $5 million ($3 million after-tax) gain, included in other income in Dominion Energy Gas’ Consolidated Statements of Income.

DOMINION ENERGY

ATLANTIC COAST PIPELINE

In September 2014, Dominion Energy, along with Duke and Southern Company Gas, announced the formation of Atlantic Coast Pipeline. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion Energy an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. In October 2016, Dominion Energy purchased an additional 3% membership interest in Atlantic Coast Pipeline from Duke for $14 million. As of December 31, 2018, the members hold the following membership interests: Dominion Energy, 48%; Duke, 47%; and Southern Company Gas, 5%.

Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. Subsidiaries and affiliates of all three members plan to be customers of the pipeline under 20-year contracts. Atlantic Coast Pipeline is considered an equity method investment as Dominion Energy has the ability to exercise significant influence, but not control, over the investee. See Note 15 for more information.

DETI provides services to Atlantic Coast Pipeline which totaled $203 million, $129 million and $95 million in 2018, 2017 and 2016, respectively, included in operating revenue in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income. Amounts receivable related to these services were $13 million and $12 million at December 31, 2018 and 2017, respectively, composed entirely of accrued unbilled revenue, included in other receivables in Dominion Energy and Dominion Energy Gas’ Consolidated Balance Sheets.

In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under its credit facility. See Note 22 for more information.

Dominion Energy contributed $414 million, $310 million and $184 million during 2018, 2017 and 2016, respectively, to Atlantic Coast Pipeline.

Dominion Energy received distributions of $36 million and $270 million during 2018 and 2017, respectively, from Atlantic Coast Pipeline. No distributions were received in 2016.

During the third and fourth quarters of 2018, a FERC stop work order together with delays in obtaining permits necessary for construction along with construction delays due to judicial actions impacted the cost and schedule for the project. As a result project cost estimates have increased from between $6.0 billion to $6.5 billion to between $7.0 billion to $7.5 billion, excluding financing costs. Atlantic Coast Pipeline expects to achieve a late 2020 in-service date for at least key segments of the project, while the remainder may extend into early 2021. Alternatively, if it takes longer to resolve the judicial issues, such as through appeal to the Supreme Court of the U.S., full in-service could extend to the end of 2021 with total project cost estimated to increase an additional $250 million, resulting in total project cost estimates of $7.25 billion to $7.75 billion excluding financing costs. Abnormal weather, work delays (including due to judicial or regulatory action) and other conditions may result in further cost or schedule modifications in the future, which could result in a material impact to Dominion Energy’s cash flows, financial position and/or results of operations.

BLUE RACER

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

In December 2016, Dominion Energy Gas repurchased a portion of the Western System from Blue Racer for $10 million.

In December 2018, Dominion Energy sold its 50% limited partnership interest in Blue Racer for up-front cash consideration of $1.05 billion and additional consideration of $150 million, subject to increase for interest costs effective March 2019, payable upon the purchaser’s availability of cash. The additional consideration was recorded at a fair value of $150 million on the date of sale following a discounted cash flow model and is included within other receivables in the Consolidated Balance Sheets at December 31, 2018. The valuation is considered a Level 3 fair value measurement due to the use of judgment and unobservable inputs, including projected timing and amount of future cash flows and a discount rate reflecting risks inherent in the future cash flows. As a result of the sale, Dominion Energy recognized a gain of $546 million ($390 million after-tax), included in other income in its Consolidated Statements of Income. Also, the purchaser agreed to pay additional consideration contingent upon the achievement of certain financial performance milestones of Blue Racer from 2019 through 2021. Pursuant to the purchase agreement, the aggregate will not exceed $300 million, which represents a gain contingency, and, as a result, Dominion Energy will not recognize any additional gain unless such consideration is realizable.

FOWLER RIDGE & NEDPOWER

In the fourth quarter of 2017, Dominion Energy recorded a charge of $126 million ($76 million after-tax) in other income in its Consolidated Statements of Income reflecting its share of a long-lived asset impairment of property, plant and equipment recorded by NedPower, which resulted in losses in excess of Dominion Energy’s investment balance. Dominion Energy recorded the excess losses due to its commitment to provide further financial support for NedPower, resulting in a liability of $17 million at December 31, 2017, recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets.

As a result of the impairment recorded by NedPower, Dominion Energy evaluated its equity method investment in Fowler Ridge, a similar wind-powered merchant generation facility, determined its fair value was other than-temporarily impaired and recorded an impairment charge of $32 million ($20 million after-tax) in other income in its Consolidated Statements of Income. The fair value of $81 million was estimated using a discounted cash flow method and is considered a Level 3 fair value measurement due to the use of significant unobservable inputs related to the timing and amount of future equity distributions based on the investee’s future wind generation and operating costs.

OTHER – CATALYST OLD RIVER HYDROELECTRIC LIMITED PARTNERSHIP

In September 2018, Dominion Energy completed the sale of its 25% limited partnership interest in Catalyst Old River Hydroelectric Limited Partnership and received proceeds of $91 million. The sale resulted in a gain of $87 million ($63 million after-tax), which is included in other income in Dominion Energy’s Consolidated Statement of Income.

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Property Plant And Equipment

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

Property Plant And Equipment

NOTE 10. PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment and their respective balances for the Companies are as follows:

At December 31,	2018		2017
(millions)
Dominion Energy
Utility:
Generation	$	19,250	$	17,602
Transmission		16,669		15,335
Distribution		18,549		17,408
Storage		2,905		2,887
Nuclear fuel		1,626		1,599
Gas gathering and processing		307		219
Oil and gas		1,763		1,720
General and other		1,476		1,514
Plant under construction		2,385		7,765
Total utility		64,930		66,049
Nonutility:
Merchant generation-nuclear		1,550		1,452
Merchant generation-other		3,802		4,992
Nuclear fuel		1,025		968
Gas gathering and processing		185		630
LNG facility		3,977		—
Other-including plant under construction		1,109		732
Total nonutility		11,648		8,774
Total property, plant and equipment	$	76,578	$	74,823
Virginia Power
Utility:
Generation	$	19,250	$	17,602
Transmission		9,392		8,332
Distribution		11,785		11,151
Nuclear fuel		1,626		1,599
General and other		821		794
Plant under construction		1,639		2,840
Total utility		44,513		42,318
Nonutility-other		11		11
Total property, plant and equipment	$	44,524	$	42,329
Dominion Energy Gas
Utility:
Transmission	$	4,758	$	4,732
Distribution		3,527		3,267
Storage		1,691		1,688
Gas gathering and processing		210		202
General and other		233		216
Plant under construction		494		293
Total utility		10,913		10,398
Nonutility:
Gas gathering and processing		185		630
Other-including plant under construction		140		145
Total nonutility		325		775
Total property, plant and equipment	$	11,238	$	11,173

Jointly-Owned Power Stations

Dominion Energy and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2018 is as follows:

	Bath County Pumped Storage Station(1)			North Anna Units 1 and 2(1)			Clover Power Station(1)			Millstone Unit 3(2)
(millions, except percentages)
Ownership interest		60	%		88.4	%		50	%		93.5	%
Plant in service		1,058			2,560			590			1,231
Accumulated depreciation		(639	)		(1,305	)		(240	)		(400	)
Nuclear fuel		—			721			—			571
Accumulated amortization of nuclear fuel		—			(608	)		—			(423	)
Plant under construction		6			103			9			66

(1) Units jointly owned by Virginia Power.

(2) Unit jointly owned by Dominion Energy.

The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion Energy and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.

Sale of Certain Retail Energy Marketing Assets

In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy marketing operations for total consideration of $143 million, subject to customary approvals and certain adjustments. In December 2017, the first phase of the agreement closed for $79 million, which resulted in the recognition of a $78 million ($48 million after-tax) benefit, included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. In October 2018, the second phase of the agreement closed for $63 million, which resulted in the recognition of a $65 million ($49 million after-tax) benefit included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. Pursuant to the agreement, Dominion Energy entered into a commission agreement with the buyer upon the first closing in December 2017 under which the buyer will pay a commission in connection with the right to use Dominion Energy’s brand in marketing materials and other services over a ten-year term.

Sale of Certain Merchant Generation Facilities

In December 2018, Dominion Energy completed the sale of Fairless and Manchester for total consideration of $1.2 billion, subject to customary closing adjustments. Dominion Energy recognized a gain of $210 million ($198 million after-tax) included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. The after-tax gain reflects Dominion Energy’s assessment and more-likely-than-not conclusion that the utilization of state tax incentives will reduce the income tax expense associated with the sale of these facilities.

Acquisition of Solar Projects

In September 2017, Virginia Power entered into agreements to acquire two solar development projects in North Carolina. The first acquisition closed in October 2018. The facility commenced commercial operations in December 2018 at a cost of $140 million, including the initial acquisition cost. The second acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2019, and cost approximately $140 million once constructed, including the initial acquisition cost. The projects are expected to generate approximately 155 MW combined. Virginia Power anticipates claiming federal investment tax credits on these solar projects.

In February 2019, Virginia Power completed the acquisition of a solar development project in Virginia. The project is expected to commence commercial operations in the first quarter 2019, and cost approximately $37 million once constructed, including the initial acquisition cost. The project is expected to generate approximately 20 MW. Virginia Power anticipates claiming federal investment tax credits on this solar project.

In August 2018, Virginia Power entered into agreements to acquire two solar development projects in North Carolina and Virginia. The first acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2019, and cost approximately $120 million once constructed, including the initial acquisition cost. The second acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2020, and cost approximately $130 million, including the initial acquisition cost. The projects are expected to generate approximately 155 MW combined. Virginia Power anticipates claiming federal investment tax credits on these solar projects.

Assignment of Tower Rental Portfolio

Virginia Power rents space on certain of its electric transmission towers to various wireless carriers for communications antennas and other equipment. In March 2017, Virginia Power sold its rental portfolio to Vertical Bridge Towers II, LLC for $91 million in cash. The proceeds are subject to Virginia Power’s FERC-regulated tariff, under which it is required to return half of the proceeds to customers. Virginia Power recorded $6 million in operating revenue and $11 million in other income during 2018 and 2017, respectively, with $29 million remaining to be recognized ratably through 2023.

Assignments of Shale Development Rights

In December 2013, Dominion Energy Gas closed on agreements with two natural gas producers to convey over time approximately 100,000 acres of Marcellus Shale development rights underneath several of its natural gas storage fields. The agreements provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In 2013, Dominion Energy Gas received approximately $100 million in cash proceeds. In 2014, Dominion Energy Gas received $16 million in additional cash proceeds resulting from post-closing adjustments. In March 2015, Dominion Energy Gas and one of the natural gas producers 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 Energy Gas’ Consolidated Statements of Income. In April 2016, Dominion Energy 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 gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income. In August 2017, Dominion Energy Gas and the natural gas producer signed an amendment to the agreement, which included the finalization of contractual matters on previous conveyances, the conveyance of Dominion Energy Gas’ remaining 68% interest in approximately 70,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. Dominion Energy Gas received total consideration of $130 million, with $65 million received in 2017 and $65 million received in September 2018 in connection with the final conveyance. As a result of this amendment, in 2017, Dominion Energy Gas recognized a $56 million ($33 million after-tax) gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the finalization of the contractual matters on previous conveyances, a $9 million ($5 million after-tax) gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the elimination of its overriding royalty interest and in 2018, a $65 million ($47 million after-tax) gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the final conveyance of acreage.

In November 2014, Dominion Energy Gas closed 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. The agreement provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $120 million over a period of four years, and an overriding royalty interest in gas produced from the acreage. In November 2014, Dominion Energy Gas closed on the agreement and received proceeds of $60 million associated with an initial conveyance of approximately 12,000 acres. In connection with that agreement, in 2016, Dominion Energy Gas conveyed a 50% interest in approximately 4,000 acres of Marcellus Shale development rights and received proceeds of $10 million and an overriding royalty interest in gas produced from the acreage. These transactions resulted in a $10 million ($6 million after-tax) gain. In July 2017, in connection with the existing agreement, Dominion Energy Gas conveyed an additional 50% interest in 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. The gains are included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income. In January 2018, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the conveyance of Dominion Energy Gas’ remaining 50% interest in approximately 18,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. Dominion Energy Gas received proceeds of $28 million, resulting in an approximately $28 million ($20 million after-tax) gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.

In March 2018, Dominion Energy Gas closed an agreement with a natural gas producer to convey approximately 11,000 acres of Utica and Point Pleasant Shale development rights underneath one of its natural gas storage fields. The agreement provided for a payment to Dominion Energy Gas, subject to customary adjustments, of $16 million. In March 2018, Dominion Energy Gas received cash proceeds of $16 million associated with the conveyance of the acreage, resulting in a $16 million ($12 million after-tax) gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.

In June 2018, Dominion Energy Gas closed an amendment to an agreement with a natural gas producer for the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from approximately 9,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields previously conveyed in December 2013. In June 2018, Dominion Energy Gas received proceeds of $6 million associated with the transaction, resulting in a $6 million ($4 million after-tax) gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.

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Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets

NOTE 11. GOODWILL AND INTANGIBLE ASSETS

Goodwill

The changes in Dominion Energy and Dominion Energy Gas’ carrying amount and segment allocation of goodwill are presented below:

	Power Generation		Gas Infrastructure			Power Delivery		Corporate and Other(1)		Total
(millions)
Dominion Energy
Balance at December 31, 2016(2)	$	1,422	$	4,051		$	926	$	—	$	6,399
Dominion Energy Questar Combination		—		6(3	)		—		—		6
Balance at December 31, 2017(2)	$	1,422	$	4,057		$	926	$	—	$	6,405
Purchase Accounting Adjustment		—		5			—		—		5
Balance at December 31, 2018(2)	$	1,422	$	4,062		$	926	$	—	$	6,410
Dominion Energy Gas
Balance at December 31, 2016(2)	$	—	$	542		$	—	$	—	$	542
No events affecting goodwill		—		—			—		—		—
Balance at December 31, 2017(2)	$	—	$	542		$	—	$	—	$	542
Purchase Accounting Adjustment		—		5			—		—		5
Balance at December 31, 2018(2)	$	—	$	547		$	—	$	—	$	547

(1) Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.

(2) Goodwill amounts do not contain any accumulated impairment losses.

(3) See Note 3.

Other Intangible Assets

The Companies’ other intangible assets are subject to amortization over their estimated useful lives. Dominion Energy’s amortization expense for intangible assets was $82 million, $80 million and $73 million for 2018, 2017 and 2016, respectively. In 2018, Dominion Energy acquired $127 million of intangible assets, primarily representing software and right-of-use assets, with an estimated weighted-average amortization period of approximately 15 years. Amortization expense for Virginia Power’s intangible assets was $31 million for both 2018 and 2017 and $29 million for 2016. In 2018, Virginia Power acquired $49 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 11 years. Dominion Energy Gas’ amortization expense for intangible assets was $14 million for both 2018 and 2017 and $6 million for 2016. In 2018, Dominion Energy Gas acquired $14 million of intangible assets, primarily representing software and right-of-use assets, with an estimated weighted-average amortization period of approximately 10 years. The components of intangible assets are as follows:

	2018				2017
At December 31,	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Dominion Energy
Software, licenses and other	$	1,033	$	363	$	1,043	$	358
Virginia Power
Software, licenses and other	$	384	$	134	$	347	$	114
Dominion Energy Gas
Software, licenses and other	$	174	$	65	$	165	$	56

Annual amortization expense for these intangible assets is estimated to be as follows:

	2019		2020		2021		2022		2023
(millions)
Dominion Energy	$	67	$	56	$	44	$	34	$	23
Virginia Power	$	29	$	23	$	16	$	12	$	6
Dominion Energy Gas	$	14	$	13	$	12	$	8	$	7

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Regulatory Assets and Liabilities

NOTE 12. REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities include the following:

At December 31,	2018		2017
(millions)
Dominion Energy
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	174	$	23
Deferred rate adjustment clause costs(2)		96		70
Deferred nuclear refueling outage costs(3)		69		54
Unrecovered gas costs(4)		14		38
Other		143		109
Regulatory assets-current		496		294
Unrecognized pension and other postretirement benefit costs(5)		1,497		1,336
Deferred rate adjustment clause costs(2)		329		401
Utility reform legislation(6)		204		147
PJM transmission rates(7)		192		222
Derivatives(8)		184		223
Deferred cost of fuel used in electric generation(1)		83		—
Other		187		151
Regulatory assets-noncurrent		2,676		2,480
Total regulatory assets	$	3,172	$	2,774
Regulatory liabilities:
Provision for future cost of removal and AROs(9)	$	117	$	101
Cost-of-service impact of 2017 Tax Reform Act(10)		104		—
Reserve for rate credits to electric utility customers(11)		71		—
Other		64		92
Regulatory liabilities-current(12)		356		193
Income taxes refundable through future rates(13)		4,071		4,058
Provision for future cost of removal and AROs(9)		1,409		1,384
Nuclear decommissioning trust(14)		1,070		1,121
Derivatives(8)		25		69
Other		265		284
Regulatory liabilities-noncurrent		6,840		6,916
Total regulatory liabilities	$	7,196	$	7,109
Virginia Power
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	174	$	23
Deferred rate adjustment clause costs(2)		78		56
Deferred nuclear refueling outage costs(3)		69		54
Other		103		72
Regulatory assets-current		424		205
Deferred rate adjustment clause costs(2)		230		312
PJM transmission rates(7)		192		222
Derivatives(8)		151		190
Deferred cost of fuel used in electric generation(1)		83		—
Other		81		86
Regulatory assets-noncurrent		737		810
Total regulatory assets	$	1,161	$	1,015
Regulatory liabilities:
Cost-of-service impact of 2017 Tax Reform Act(10)	$	95	$	—
Provision for future cost of removal(9)		92		80
Reserve for rate credits to customers(11)		71		—
Other		41		47
Regulatory liabilities-current		299		127
Income taxes refundable through future rates(13)		2,579		2,581
Nuclear decommissioning trust(14)		1,070		1,121
Provision for future cost of removal(9)		940		915
Derivatives(8)		25		69
Other		33		74
Regulatory liabilities-noncurrent		4,647		4,760
Total regulatory liabilities	$	4,946	$	4,887
Dominion Energy Gas
Regulatory assets:
Deferred rate adjustment clause costs(2)	$	18	$	14
Unrecovered gas costs(4)		9		8
Other		2		4
Regulatory assets-current(16)		29		26
Unrecognized pension and other postretirement benefit costs(5)		392		258
Utility reform legislation(6)		204		147
Deferred rate adjustment clause costs(2)		99		89
Other		32		17
Regulatory assets-noncurrent		727		511
Total regulatory assets	$	756	$	537
Regulatory liabilities:
Provision for future cost of removal and AROs(9)	$	14	$	13
PIPP(15)		3		20
Other		4		5
Regulatory liabilities-current(12)		21		38
Income taxes refundable through future rates(13)		1,011		998
Provision for future cost of removal and AROs(9)		158		160
Cost-of-service impact of 2017 Tax Reform Act(10)		19		—
Other		97		69
Regulatory liabilities-noncurrent		1,285		1,227
Total regulatory liabilities	$	1,306	$	1,265

 (1) Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Dominion Energy and Virginia Power’s generation operations. See Note 13 for more information.

 (2) Primarily reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects net of income taxes refundable from the 2017 Tax Reform Act for Virginia Power and deferrals of costs associated with certain current and prospective rider projects for Dominion Energy Gas. See Note 13 for more information.

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

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

 (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 Energy and Dominion Energy Gas’ rate-regulated subsidiaries.

 (6) Ohio legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future.

 (7) Reflects amounts related to the PJM transmission cost allocation matter. See Note 13 for more information.

 (8) As discussed under Derivative Instruments in Note 2, 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.

 (9) 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.

(10) Balance refundable to customers related to the decrease in revenue requirements for recovery of income taxes at the Companies’ regulated electric generation and electric and natural gas distribution operations. See Note 13 for more information.

(11) Charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers. See Note 13 for more information.

(12) Current regulatory liabilities are presented in other current liabilities in Dominion Energy and Dominion Energy Gas’ Consolidated Balance Sheets.

(13) Amounts recorded to pass the effect of reduced income tax rates from the 2017 Tax Reform Act to customers in future periods, which will reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity.

(14) 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.

(15) 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 rider according to East Ohio tariff provisions. See Note 13 for more information.

(16) Current regulatory assets are presented in other current assets in Dominion Energy Gas’ Consolidated Balance Sheets.

At December 31, 2018, $396 million of Dominion Energy’s, $300 million of Virginia Power’s and $12 million of Dominion Energy Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. With the exception of the PJM transmission cost allocation matter, the majority of these expenditures are expected to be recovered within the next two years.

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Regulatory Matters

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Regulatory Matters

NOTE 13. 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 regulatory matters that the Companies cannot estimate, 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 that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.

FERC—ELECTRIC

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public util-ities. Virginia Power purchases and sells electricity in the PJM wholesale market and sells electricity to wholesale purchasers in Virginia and North Carolina. Dominion Energy’s merchant generators sell electricity in the PJM, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California, South Carolina and Utah, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. 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 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 investment in electric transmission infrastructure.

In March 2010, ODEC 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.

In October 2017, FERC issued an order determining the calculation of the incremental costs of undergrounding the transmission projects and affirming that the costs are to be recovered from the wholesale transmission customers with loads located in Virginia. FERC directed Virginia Power to rebill all wholesale transmission customers retroactively to March 2010 within 30 days of when the proceeding becomes final and no longer subject to rehearing. In November 2017, Virginia Power, North Carolina Electric Membership Corporation and the wholesale transmission customers filed petitions for rehearing. In July 2018, FERC denied the rehearing requests related to the October 2017 order determining the calculation of the undergrounding costs. Several parties have appealed FERC’s decision to the U.S. Court of Appeals for the D.C. Circuit. This matter is pending. While Virginia Power cannot predict the outcome of the matter, it is not expected to have a material effect on results of operations.

In January 2019, FERC issued an order denying PJM’s request to waive certain provisions of the PJM Tariff regarding the liquidation of a portfolio of FTRs owned by GreenHat who had defaulted on its financial obligations. As a result of FERC’s order, PJM is required to use the existing tariff provisions to liquidate GreenHat’s FTR portfolio and allocate the resulting costs to PJM members. In February 2019, PJM filed a request for clarification and rehearing with FERC. While the impacts of this order could be material to 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.

PJM Transmission Rates

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

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

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. In May 2018, FERC issued an order accepting the settlement agreement and directed PJM to make a compliance filing with revised tariff records. As a result, in August 2018, Virginia Power began to make payments to PJM, to continue for the next 10 years totaling $276 million, under the terms of revised tariff records, which was partially offset by a $265 million regulatory asset for the amount that will be recovered through retail rates in Virginia. At December 31, 2018, Virginia Power’s Consolidated Balance Sheet includes $126 million in other current liabilities and $50 million included in other deferred credits and other liabilities for amounts owed to PJM.

FERC—GAS

In July 2017, FERC audit staff communicated to DETI that it had substantially completed an audit of DETI’s compliance with the accounting and reporting requirements of FERC’s Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report which could have the potential to result in adjustments which could be material to Dominion Energy and Dominion Energy Gas’ results of operations. In December 2017, DETI provided its response to the audit report. DETI requested FERC review of contested findings and submitted its plan for compliance with the uncontested portions of the report. In connection with one uncontested issue, DETI recognized a charge of $15 million ($9 million after-tax) recorded within impairment of assets and related charges in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income during 2017 to write-off the balance of a regulatory asset, originally established in 2008, that is no longer considered probable of recovery. DETI recognized a charge of $129 million ($94 million after-tax) recorded primarily within impairment of assets and related charges in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income during 2018 for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with FERC. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the remaining finding and no amounts have been recognized.

2017 TAX REFORM ACT

Subsequent to the enactment of the 2017 Tax Reform Act, the Companies’ state regulators issued orders requesting that public utilities evaluate the total tax impact on the entity’s cost of service and accrue a regulatory liability attributable to the benefits of the reduction in the corporate income tax rate. Certain of the orders requested that the public utilities submit a response to the state regulatory commissions detailing the total tax impact on the utility’s cost of service.

The Companies began to reserve the impacts of the cost-of-service reduction as regulatory liabilities in January 2018 and will continue until rates are reset pursuant to state regulators’ approvals. The Companies have recorded a reasonable estimate of net income taxes refundable through future rates in the jurisdictions in which they operate and are currently assessing these actions and decisions, which could have a material impact on the Companies’ results of operations, financial condition and/or cash flows.

In September 2018, the Virginia Commission issued an order directing Virginia Power to submit a filing quantifying the impacts of the 2017 Tax Reform Act in advance of the April 1, 2019 implementation as required by legislation. In October 2018, Virginia Power filed testimony with the Virginia Commission to implement adjustments in its base rates reflecting actual annual reductions in corporate income taxes resulting from the 2017 Tax Reform Act, which included a proposed annual revenue reduction of approximately $151 million effective April 2019. In December 2018, the Staff of the Virginia Commission proposed an annual revenue reduction of approximately $190 million. In January 2019, Virginia Power filed updated testimony with a proposed annual revenue reduction of approximately $171 million. Additionally, Virginia Power proposed to issue a one-time bill credit to customers within 90 days of this effective date, to true-up the difference between the final revenue reduction for the period January 1, 2018 through March 31, 2019 and the $125 million interim rate reduction implemented on July 1, 2018. Based on Virginia Power’s current proposed annual revenue reduction, this one-time bill credit is expected to total approximately $120 million. The actual credit will be based on actual billing data and customer usage during that 15-month period. This matter is pending.

In August 2018, Virginia Power filed with FERC to waive protocols and begin reflecting projected tax reform benefits of approximately $100 million through the transmission formula rate prior to the normal formula rate process. FERC granted the waiver and the amounts began being reflected in customer billings in November 2018 reflecting the adjustment effective January 1, 2018.

In October 2018, the North Carolina Commission issued an order requesting companies file to reduce base rates expeditiously. Virginia Power made its compliance filing in October 2018 and submitted an annual base rate revenue decrease of approximately $14 million effective in early 2019. Virginia Power also proposed to issue a one-time bill credit in early 2019 for its 2018 tax savings collected provisionally from customers, which is estimated to be approximately $13 million. The order allowed for the disposition of excess deferred income taxes to be deferred for consideration until the utilities’ next base rate case, but no longer than 3 years, and initiated a quarterly reporting requirement for such deferred amounts. This matter is pending.

In May 2018, the Utah Commission approved a stipulation submitted by Questar Gas proposing the cost-of-service component of customer rates be reduced by $15 million annually beginning in June 2018. In July 2018, the Utah Commission approved Questar Gas’ request to return an additional $9 million to Utah customers representing the amounts related to the corporate income tax reduction that had been deferred from January 1, 2018 to May 31, 2018. This additional reduction began amortizing on August 1, 2018 and will be amortized over a one-year period. In October 2018, the Wyoming Commission approved Questar Gas’ request to return deferred amounts through a surcredit beginning November 1, 2018. The surcredit will remain in effect until rates become effective in the next Wyoming general rate case. The impact of excess deferred income taxes resulting from the 2017 Tax Reform Act on rates charged to customers will be reported to the Utah and Wyoming Commissions by the first quarter of 2019.

In October 2018, the Ohio Commission issued an order requiring rate-regulated utilities to file an application reflecting the impact of the 2017 Tax Reform Act on current rates by January 1, 2019. In December 2018, East Ohio filed its application proposing an approach to establishing rates and charges by and through which to return tax reform benefits to its customers. This case is pending.

As directed by the West Virginia Commission, Hope is utilizing regulatory accounting to track the effects of the 2017 Tax Reform Act beginning in January 2018 and submitted testimony in July 2018 detailing such effects. In August 2018, the West Virginia Commission approved a settlement implementing base rate reductions effective September 1, 2018. In November 2018, the West Virginia Commission issued an order requiring Hope to file a calculation of prospective tax reform savings based on 2017 financial statements, using federal income tax rates reduced for consolidated tax savings, and to record as a regulatory liability the difference between the amount calculated based on 2017 financial statements and the amount included in the voluntary base rate reduction effective September 1, 2018. In December 2018, Hope filed the required calculation setting forth an annual regulatory liability deferral amount of $0.4 million. The disposition of the additional regulatory liability will be determined in a future rate proceeding. These reductions are not expected to have a material impact on Hope’s financial condition.

In March 2018, FERC announced actions to address the income tax allowance component of regulated entities’ cost-of-service rates as a result of the 2017 Tax Reform Act. FERC required all interstate natural gas pipelines to make a one-time informational filing with FERC to provide financial information to allow FERC and other interested parties to analyze the impacts of the changes in tax law. The actions also included the reversal of FERC’s policy allowing master limited partnerships to recover an income tax allowance in cost-of-service rates and requiring other pass-through entities to justify the inclusion of an income tax allowance.

In July 2018, FERC issued a final rule adopting and modifying the procedures for determining whether jurisdictional natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the corporate income tax rate. Specifically, this final rule does not require master limited partnerships to eliminate their income tax allowances when completing the informational filing and allows entities that are wholly-owned by corporations to include an income tax allowance.

During 2018, Dominion Energy’s FERC-regulated pipelines, including those accounted for as equity method investments, filed the required informational reports with FERC. Dominion Energy Overthrust Pipeline, LLC, White River Hub, Dominion Energy Questar Pipeline and Cove Point have reached resolution through settlement, which did not result in a material impact to results of operations, financial condition and/or cash flows of Dominion Energy, waiver or FERC terminating the 501-G proceeding. In January 2019, Iroquois reached a settlement in principle with its customers, which if approved would not have a material impact to Dominion Energy or Dominion Energy Gas, and expects to file a settlement agreement with FERC in the first quarter of 2019. The FERC dockets for DETI and DECG remain open. While the informational filings for these two pipelines indicated that no changes to current rates charged to customers were necessary, given the associated uncertainty, Dominion Energy and Dominion Energy Gas are currently unable to predict the outcome of these matters; however, any change in rates permitted to be charged to customers could have a material impact on results of operations, financial condition and/or cash flows.

Other Regulatory Matters

VIRGINIA REGULATION

The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers.

The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, underground distribution lines, environmental compliance, conservation and energy efficiency programs, renewable energy programs and nuclear license renewals, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.

If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.

Grid Transformation and Security Act of 2018

In March 2018, the GTSA reinstated base rate reviews on a triennial basis, other than the first review which will be a quadrennial review, occurring for Virginia Power in 2021 for the four successive 12-month test periods beginning January 1, 2017 and ending December 31, 2020. This review for Virginia Power will occur one year earlier than under the Regulation Act legislation enacted in February 2015.

In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized return on equity that might have been refunded to customers and served as the basis for a reduction in future rates, may be reduced by approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include in a customer credit reinvestment offset. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a customer credit reinvestment offset. Any costs that are the subject of a customer credit reinvestment offset may not be recovered in base rates for the service life of the projects and may not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized return on equity, base rates are subject to reduction prospectively and customer refunds would be due unless the total customer credit reinvestment offset elected by the utility equals or exceeds the amount of earnings in excess of the 70 basis points. In the 2021 review, any such rate reduction is limited to $50 million.

The legislation also includes provisions requiring Virginia Power to provide current customers one-time rate credits totaling $200 million and to reduce base rates to reflect reductions in income tax expense resulting from the 2017 Tax Reform Act. As a result, Virginia Power incurred a $215 million ($160 million after-tax) charge in connection with this legislation, including the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology. In July 2018 and January 2019, Virginia Power credited $138 million and $77 million, respectively, to current customers’ bills.

In addition, Virginia Power reduced base rates on an annual basis by $125 million effective July 2018, to reflect the estimated effect of the 2017 Tax Reform Act, which is subject to adjustment effective April 2019. In May and June 2018, Virginia Power submitted filings detailing the implementation plan for interim reductions in rates for generation and distribution services pursuant to the GTSA.

In July 2018, Virginia Power filed a petition with the Virginia Commission for approval of the first three years of its ten-year plan for electric distribution grid transformation projects as authorized by the GTSA. During the first three years of the plan, Virginia Power proposes to focus on the following seven foundational components of the overall grid transformation plan: (i) smart meters; (ii) customer information platform; (iii) reliability and resilience; (iv) telecommunications infrastructure; (v) cyber and physical security; (vi) predictive analytics; and (vii) emerging technology. The total estimated capital investment during 2019-2021 is $816 million and the proposed operations and maintenance expenses are $102 million. In January 2019, the Virginia Commission issued its final order approving capital spending for the first three years of the plan-totaling $68 million on cyber and physical security and related telecommunications infrastructure. The Virginia Commission declined to approve the remainder of the proposed components for the first three years of the plan, the proposed spending for which was not found reasonable and prudent based on the record in the proceeding. Virginia Power intends to file a revised plan in mid-2019 that will address the elements needed for a comprehensive plan, as outlined by the Virginia Commission in its order.

Virginia Fuel Expenses

In May 2018, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.5 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2018. Virginia Power’s proposed fuel rate represented a fuel revenue increase of $222 million when applied to projected kilowatt-hour sales for the period July 1, 2018 to June 30, 2019. In August 2018, the Virginia Commission approved Virginia Power’s fuel rate with an increase of $209 million.

Solar Facility Projects

In July 2018, Virginia Power filed an application with the Virginia Commission for CPCNs to construct two solar facilities. Colonial Trail West and Spring Grove 1 are estimated to cost approximately $410 million, excluding financing costs. Colonial Trail West and Spring Grove 1 are expected to commence commercial operations, subject to regulatory approvals associated with the projects, in the fourth quarter of 2019 and the fourth quarter of 2020, respectively. Virginia Power also applied for approval of Rider US-3 associated with these projects with a proposed $10 million total revenue requirement for the rate year beginning March 1, 2019. In January 2019, the Virginia Commission issued a final order granting CPCNs to construct the solar facilities, subject to a 20-year performance guarantee of the facilities at a 25% solar capacity factor when normalized for force majeure events. The matter regarding Rider US-3 is pending.

Rate Adjustment Clauses

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

• The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2018, Virginia Power proposed a $755 million total revenue requirement consisting of $468 million for the transmission component of Virginia Power’s base rates and $287 million for Rider T1. This total revenue requirement represents a $146 million increase versus the revenues to be produced during the rate year under current rates. In August 2018, the Virginia Commission approved a total revenue requirement of $630 million, including Rider T1, subject to true-up, for the rate year beginning September 1, 2018. The Virginia Commission’s order required an adjustment to Rider T1 to begin providing projected benefits associated with the 2017 Tax Reform Act to customers in rates effective September 1, 2018. Such projected benefits were not included in the underlying transmission formula rates approved by FERC. Also in August 2018, Virginia Power filed a petition with the Virginia Commission seeking limited reconsideration and rehearing of this approval to adjust the total revenue requirement to $636 million. In November 2018, the Virginia Commission denied the petition for limited reconsideration and rehearing and adjusted the total revenue requirement to $628 million.

• The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by Virginia legislation. In March 2018, Virginia Power requested approval of its third phase of conversions totaling $179 million and a balance of $65 million in second phase conversions not previously approved for recovery through Rider U. Virginia Power also proposed a total $73 million revenue requirement for the rate year beginning February 1, 2019 for continuing recovery of the previously approved first and second phase conversions and the proposed second and third phase conversions. In December 2018, the Virginia Commission approved a total $70 million annual revenue requirement effective February 1, 2019, a total capital investment of $179 million for third phase conversions and a balance of $64 million for second phase conversions not previously approved for recovery through Rider U.

• The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In October 2018, Virginia Power requested approval to implement ten new energy efficiency programs and one new demand-response DSM program for five years, subject to future extensions, with a $262 million cost cap, and proposed a total $49 million revenue requirement for the rate year beginning July 1, 2019, which represents an $18 million increase over the previous year. This matter is pending.

Additional significant riders associated with various Virginia Power projects are as follows:

Rider Name	Application Date	Approval Date	Rate Year Beginning	Total Revenue Requirement (millions)		Increase (Decrease) Over Previous Year (millions)
Rider S	June 2018	February 2019	April 2019	$	215	$	(3	)
Rider GV	June 2018	February 2019	April 2019		120		38
Rider W	June 2018	February 2019	April 2019		105		(4	)
Rider R	June 2018	February 2019	April 2019		57		(9	)
Rider B	June 2018	February 2019	April 2019		38		(9	)
Rider BW	October 2018	Pending	September 2019		123		7
Rider US-2	October 2018	Pending	September 2019		16		3
Rider E	December 2018	Pending	November 2019		114		N/A

Coastal Virginia Offshore Wind Project

In November 2018, Virginia Power received approval from the Virginia Commission for its petition seeking a prudency determination as provided in the GTSA with respect to the proposed Coastal Virginia Offshore Wind project consisting of two 6 MW wind turbine generators located approximately 27 miles off the coast of Virginia Beach, Virginia in federal waters, and for a CPCN, for the generation tie line connecting the generators to shore. This project is expected to cost approximately $300 million and to be placed into service by the end of 2020.

Electric Transmission Projects

In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry switching station in Surry County to a new Skiffes Creek switching station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed new Skiffes Creek switching station to Virginia Power’s existing Whealton substation in the City of Hampton. As of July 2017, Virginia Power has received all major required permits and approvals and is proceeding with construction of the project. In connection with the receipt of the permit from the U.S. Army Corps of Engineers in July 2017, Virginia Power was required to make payments totaling approximately $90 million to fund improvements to historical and cultural resources near the project. Accordingly, in July 2017, Virginia Power recorded an increase to property, plant and equipment and a corresponding liability for these payment obligations. Through December 31, 2017, Virginia Power had made $90 million of such payments. Also in July 2017, the National Parks Conservation Association filed a lawsuit in U.S. District Court for the D.C. Circuit seeking to set aside the permit granted by the U.S. Army Corps of Engineers for the project and requested a preliminary injunction against the permit. In August 2017, the National Trust for Historic Preservation and Preservation Virginia filed a similar lawsuit in U.S. District Court for the D.C. Circuit. In October 2017, the preliminary injunction requests were denied. In May 2018, the District Court granted summary judgment in favor of the U.S. Army Corps of Engineers and Virginia Power and dismissed both lawsuits. In June 2018, the National Parks Conservation Association and the National Trust for Historic Preservation and Preservation Virginia appealed that decision to the U.S. Court of Appeals for the D.C. Circuit. The appeal is pending. Also in June 2018, the National Parks Conservation Association filed requests with the U.S. District Court for the District of Columbia and the U.S. Court of Appeals for the D.C. Circuit for an injunction against the permit pending appeal. The U.S. District Court for the District of Columbia denied the injunction request in June 2018 and the U.S. Court of Appeals for the D.C. Circuit similarly denied the request in July 2018.

In November 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to convert an existing transmission line to 230 kV in Prince William County, Virginia, and Loudoun County, Virginia, and to construct and operate a new approximately five mile overhead 230 kV double circuit transmission line between a tap point near the Gainesville substation and a new to-be-constructed Haymarket substation. The total estimated cost of the project is approximately $180 million. In April 2017, the Virginia Commission issued an interim order instructing Virginia Power to construct and operate the project along an approved route if Virginia Power could obtain all necessary rights-of-way. Otherwise, the Virginia Commission ruled that Virginia Power can construct and operate the project along an approved alternative route. In June 2017, the Virginia Commission issued a final order approving the alternative route for the project, and granted the necessary CPCN. In July 2017, the Virginia Commission retained jurisdiction over the case to evaluate two requests to reconsider its decisions. Also in July 2017, Virginia Power requested that the Virginia Commission stay the proceeding while Virginia Power discusses the proposed route with leaders of Prince William County. In December 2017, the Virginia Commission granted in part the two motions for reconsideration, retained jurisdiction for further proceedings in the case and stayed the effectiveness of its final order. In March 2018, Virginia Power and the two parties seeking reconsideration entered into a stipulation settlement filed with the Virginia Commission agreeing that the project should be placed into an underground pilot program created by the GTSA. In July 2018, Virginia Power filed a request with the Virginia Commission to allow the project to participate in the underground pilot program. Subsequently, in July 2018, the Virginia Commission issued a final order granting the CPCN for the project and allowing the project to participate in the underground pilot program.

In June 2018, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in King and Queen, King William, and New Kent Counties, Virginia four separate segments of 230 kV transmission line between Lanexa and the Northern Neck in Virginia. In February 2019, Virginia Power withdrew two of the segments from the application. As a result, the total estimated cost of the project is approximately $30 million. This matter is pending.

Additional significant Virginia Power electric transmission projects approved and applied for in 2018 are as follows:

Description and Location of Project	Application Date	Approval Date	Type of Line		Miles of Lines		Cost Estimate (millions)
Rebuild and operate existing 115 kV transmission lines between the Possum Point Switching Station and Northern Virginia Electric Cooperative’s Smoketown delivery point	June 2017	February 2018		230 kV		9	$	20
Rebuild and operate between the Dooms substation and the Valley substation, along with associated substation work	September 2017	September 2018		500 kV		18		65
Build and operate between the Idylwood and Tysons substations, along with associated substation work	November 2017	September 2018		230 kV		4		125
Rebuild and operate between the Chesterfield and Hopewell substations, along with associated substation work	May 2018	November 2018		230 kV		8		30
Rebuild and operate between the Chesterfield and Lakeside substations, along with associated substation work	May 2018	December 2018		230 kV		21		35
Rebuild and operate between the Landstown and Thrasher substations, along with associated substation work	June 2018	December 2018		230 kV		8.5		20
Partial rebuild of overhead transmission lines in Alleghany County, Virginia and Covington, Virginia	August 2018	Pending		138 kV		5		15
Build a new substation and connect three existing transmission lines thereto in Fluvanna County, Virginia	October 2018	Pending		230 kV		<1		30

NORTH CAROLINA REGULATION

In August 2018, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed a total $24 million increase to the fuel component of its electric rates for the rate year beginning February 1, 2019. As a mitigation alternative, Virginia Power proposed recovering 50% in the February 1, 2019 to the January 31, 2020 rate period and the remaining 50% in the following rate period. In January 2019, the North Carolina Commission approved Virginia Power’s full proposed fuel charge adjustment of $24 million.

OHIO REGULATION

PIR Program

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

In April 2018, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2017 costs. The filing reflects gross plant investment for 2017 of $204 million, cumulative gross plant investment of $1.4 billion and a revenue requirement of $165 million.

AMR Program

In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. The AMR program approved by the Ohio Commission was completed in 2012. Although no further capital investment will be added, East Ohio is approved to recover depreciation, property taxes, carrying charges and a return until East Ohio has another rate case.

In April 2018, the Ohio Commission approved East Ohio’s application to adjust its AMR cost recovery rate for 2017 costs. The filing reflects a revenue requirement of approximately $5 million.

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 May 2018, East Ohio filed its annual update of the PIPP rider with the Ohio Commission. In July 2018, 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 recovery over the twelve-month period from July 2018 through June 2019 of projected deferred program costs of approximately $10 million from April 2018 through June 2019, net of a refund for over-recovery of accumulated arrearages of approximately $4 million as of March 31, 2018.

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 September 2018, the Ohio Commission approved East Ohio’s application requesting approval of its UEX Rider to reflect a refund of over-recovered accumulated bad debt expense of approximately $11 million as of March 31, 2018, and recovery of prospective net bad debt expense projected to total $16 million for the twelve-month period from April 2018 to March 2019.

DSM Rider

East Ohio has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In November 2018, East Ohio filed an application with the Ohio Commission seeking approval of an adjustment to the DSM rider to recover a total of $4 million, which includes an over-recovery of costs during the preceding 12-month period. This application was approved by the Ohio Commission in January 2019.

WEST VIRGINIA REGULATION

In May 2018, Hope filed a PREP application with the West Virginia Commission requesting approval to recover PREP costs related to $31 million and $36 million of projected capital investment for 2018 and 2019, respectively. The application also includes a true-up of PREP costs related to the 2017 actual capital investment of $28 million and sets forth $8 million of annual PREP costs to be recovered in proposed rates effective November 2018. In October 2018, the West Virginia Commission approved PREP rates effective November 2018. Approved rates recover $7 million of annual PREP costs related to actual cumulative PREP investment through December 31, 2017 of $48 million and projected PREP investment for calendar years 2018 and 2019 of $31 million and $29 million, respectively.

UTAH AND WYOMING REGULATION

Fuel Deferral

In May 2018, Questar Gas submitted filings with both the Utah Commission and the Wyoming Commission for an approximately $86 million gas cost decrease reflecting forecasted decreases in commodity costs. The Utah Commission and the Wyoming Commission both approved the filings in May 2018 with rates effective June 2018.

In October 2018, Questar Gas submitted filings with both the Utah Commission and the Wyoming Commission for an approximately $48 million gas cost decrease reflecting forecasted decreases in commodity costs. The Utah Commission and the Wyoming Commission both approved the filings in October 2018 with rates effective November 2018.

In October 2018, the Utah Commission denied Questar Gas’ request for pre-approval to construct an LNG peaking storage facility with a liquefaction rate of 8.2 million cubic feet per day. Questar Gas is reviewing the order and assessing its options, which include filing supplemental information with the Utah Commission for reconsideration.

Infrastructure Replacement Tracker

During 2018, Questar Gas filed applications with the Utah Commission to increase its infrastructure replacement surcharge to collect an additional $11 million in revenue in 2019 related to $85 million in 2018 capital investment. The Utah Commission approved the applications in the fourth quarter of 2018.

FERC—GAS

Cove Point

In March 2018, Cove Point submitted its annual electric power cost adjustment to FERC requesting approval to recover $30 million. FERC approved the adjustment in March 2018.

In June 2015, Cove Point executed two binding precedent agreements for the approximately $150 million Eastern Market Access Project. In January 2018, Cove Point received FERC authorization to construct and operate the project facilities, which are expected to be placed in service in the second half of 2019. In October 2018, Cove Point announced it is evaluating alternatives to a proposed Charles County, Maryland compressor station that was initially part of this project and in December 2018, after working with project customers for alternative solutions, decided not to pursue further construction at this location resulting in a revised project estimate of approximately $45 million and a write-off of $37 million pre-tax ($28 million after-tax) recorded within impairment of assets and related charges in Dominion Energy’s Consolidated Statements of Income.

DETI

In September 2018, DETI submitted its annual transportation cost rate adjustment to FERC requesting approval to recover $37 million. Also in September 2018, DETI submitted its annual electric power cost adjustment to FERC requesting approval to recover $7 million. In October 2018, FERC approved these adjustments.

In August 2018, DETI executed a binding precedent agreement with a customer for the West Loop project. The project is expected to cost approximately $95 million and provide 150,000 Dth per day of firm transportation service from Pennsylvania to Ohio for delivery to a proposed combined-cycle, natural gas-fired electric power generation facility to be located in Columbiana County, Ohio. In December 2018, DETI filed an application to request FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service by the end of 2021.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

NOTE 14. ASSET RETIREMENT OBLIGATIONS

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

The Companies have also identified, but not recognized, AROs related to the retirement of Dominion Energy’s LNG facility, Dominion Energy and Dominion Energy Gas’ storage wells in their underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in Dominion Energy and Virginia Power’s generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs during 2017 and 2018 were as follows:

	Amount
(millions)
Dominion Energy
AROs at December 31, 2016	$	2,485
Obligations incurred during the period		37
Obligations settled during the period		(214	)
Revisions in estimated cash flows		7
Accretion		117
AROs at December 31, 2017(1)	$	2,432
Obligations incurred during the period		20
Obligations settled during the period		(159	)
Revisions in estimated cash flows(2)		120
Accretion		119
AROs at December 31, 2018(1)	$	2,532
Virginia Power
AROs at December 31, 2016	$	1,443
Obligations incurred during the period		11
Obligations settled during the period		(152	)
Revisions in estimated cash flows		(1	)
Accretion		64
AROs at December 31, 2017	$	1,365
Obligations incurred during the period		14
Obligations settled during the period		(119	)
Revisions in estimated cash flows(2)		120
Accretion		65
AROs at December 31, 2018	$	1,445
Dominion Energy Gas
AROs at December 31, 2016	$	156
Obligations incurred during the period		2
Obligations settled during the period		(7	)
Accretion		9
AROs at December 31, 2017(3)	$	160
Obligations incurred during the period		4
Obligations settled during the period		(6	)
Accretion		9
AROs at December 31, 2018(3)	$	167

(1) Includes $263 million and $282 million reported in other current liabilities at December 31, 2017, and 2018, respectively.

(2) Reflects future ash pond and landfill closure costs at certain utility generation facilities. See Note 22 for further information.

(3) Includes $146 million and $153 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities, at December 31, 2017 and 2018, respectively.

Dominion Energy and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31, 2018 and 2017, the aggregate fair value of Dominion Energy’s trusts, consisting primarily of equity and debt securities, totaled $4.9 billion and $5.1 billion, respectively. At December 31, 2018 and 2017, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $2.4 billion for both periods.

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Variable Interest Entities

12 Months Ended

Dec. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Variable Interest Entities

NOTE 15. 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 ENERGY

At December 31, 2018, Dominion Energy owned the general partner, 60.9% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owned a preferred equity interest and the general partner interest in Cove Point. In January 2019, Dominion Energy acquired all outstanding partnership interests not owned by Dominion Energy and Dominion Energy Midstream became a wholly-owned subsidiary of Dominion Energy. Dominion Energy previously concluded that Dominion Energy Midstream was a VIE due to the limited partners lacking the characteristics of a controlling financial interest. Dominion Energy was the primary beneficiary of Dominion Energy Midstream and Dominion Energy Midstream was the primary beneficiary of Cove Point as they had the power to direct the activities that most significantly impact their economic performance as well as to absorb losses and benefits which could be significant to them.

At December 31, 2018, Dominion Energy owns the manager and 67% of the membership interest in certain merchant solar facilities, as discussed in Note 2. Dominion Energy has concluded that these entities are VIEs due to the members lacking the characteristics of a controlling financial interest. In addition, in 2016 Dominion Energy created a wholly owned subsidiary, SBL Holdco, as a holding company of its interest in the VIE merchant solar facilities and accordingly SBL Holdco is a VIE. Dominion Energy is the primary beneficiary of SBL Holdco and the merchant solar facilities, as it has 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 Energy’s securities due within one year and long-term debt include $31 million and $299 million, respectively, of debt issued by SBL Holdco net of issuance costs that is nonrecourse to Dominion Energy and is secured by SBL Holdco’s interest in certain merchant solar facilities.

Dominion Energy owns a 48% membership interest in Atlantic Coast Pipeline. See Note 9 for more details regarding the nature of this entity. Dominion Energy concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion Energy 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 Energy is obligated to provide capital contributions based on its ownership percentage. Dominion Energy’s maximum exposure to loss is limited to its current and future investment as well as any obligations under a guarantee provided. See Note 22 for more information.

DOMINION ENERGY AND VIRGINIA POWER

Dominion Energy and Virginia Power’s nuclear decommissioning trust funds and Dominion Energy’s rabbi trusts hold investments in limited partnerships or similar type entities (see Note 9 for further details). Dominion Energy and Virginia Power concluded that these partnership investments are VIEs due to the limited partners lacking the characteristics of a controlling financial interest. Dominion Energy 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 Energy and Virginia Power are obligated to provide capital contributions to the partnerships as required by each partnership agreement based on their ownership percentages. Dominion Energy and Virginia Power’s maximum exposure to loss is limited to their current and future investments.

DOMINION ENERGY AND DOMINION ENERGY GAS

Dominion Energy 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 2016, such right no longer existed and, as a result, Dominion Energy concluded that Iroquois is no longer a VIE.

VIRGINIA POWER

Virginia Power had long-term power and capacity contracts with three non-utility generators, which contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. Contracts with two of these non-utility generators expired during 2017, leaving a remaining aggregate summer generation capacity of approximately 218 MW. 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 remaining entity during the remaining terms of Virginia Power’s contract and for the years the entity is expected to operate after its contractual relationship expires. The remaining contract expires in 2021. Virginia Power is not subject to any risk of loss from this potential VIE other than its remaining purchase commitments which totaled $150 million as of December 31, 2018. Virginia Power paid $50 million, $86 million, and $144 million for electric capacity to non-utility generators and $18 million, $24 million, and $31 million for electric energy to non-utility generators for the years ended December 31, 2018, 2017 and 2016, respectively.

DOMINION ENERGY GAS

DETI 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 DETI holds a membership interest in Atlantic Coast Pipeline, therefore DETI 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. DETI 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. DETI has no obligation to absorb any losses of the VIE. See Note 24 for information about associated related party receivable balances.

VIRGINIA POWER AND DOMINION ENERGY GAS

Virginia Power and Dominion Energy Gas purchased shared services from DES, an affiliated VIE, of $335 million and $126 million, $340 million and $126 million, and $346 million and $123 million for the years ended December 31, 2018, 2017 and 2016, respectively. Virginia Power and Dominion Energy Gas’ Consolidated Balance Sheets included amounts due to DES of $107 million and $46 million, respectively, at December 31, 2018, and $36 million and $14 million, respectively, at December 31, 2017, recorded in payables to affiliates in the Consolidated Balance Sheets. Virginia Power and Dominion Energy Gas determined that neither is the primary beneficiary of DES 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. DES provides accounting, legal, finance and certain administrative and technical services to all Dominion Energy subsidiaries, including Virginia Power and Dominion Energy Gas. Virginia Power and Dominion Energy Gas have no obligation to absorb more than their allocated shares of DES costs.

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Short-Term Debt And Credit Agreements

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Short-Term Debt And Credit Agreements

NOTE 16. SHORT-TERM DEBT AND CREDIT AGREEMENTS

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 Energy utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties.

DOMINION ENERGY

In March 2018, Dominion Energy replaced its two existing joint revolving credit facilities with a $6.0 billion joint revolving credit facility. Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities were as follows:

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit		Facility Capacity Available
(millions)
At December 31, 2018
Joint revolving credit facility(2)	$	6,000		$   324		$88	$	5,588
At December 31, 2017
Joint revolving credit facility(3)	$	5,000		$3,298		$—	$	1,702
Joint revolving credit facility(3)		500		—		76		424
Total	$	5,500		$3,298		$76	$	2,126

(1) The weighted-average interest rates of the outstanding commercial paper supported by Dominion Energy’s credit facilities were 2.93% and 1.61% at December 31, 2018 and 2017, respectively.

(2) This credit facility matures in March 2023 and can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

(3) These credit facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. The facilities were scheduled to mature in April 2020 and were 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.

In connection with the SCANA Combination, Dominion Energy intends to terminate SCANA, SCE&G and PSNC’s existing credit facilities, and add SCE&G as a co-borrower to its $6.0 billion joint revolving credit facility in the first quarter of 2019 once certain regulatory approvals are obtained. In January 2019, Virginia Power and SCE&G, as co-borrowers, filed with the Virginia Commission and the South Carolina Commission, respectively, for approval. In February 2019, the Virginia Commission approved the request.

Questar Gas’ short-term financing is supported through its access as co-borrower to the joint revolving credit facility discussed above with Dominion Energy, Virginia Power and Dominion Energy Gas. At December 31, 2018, the sub-limit for Questar Gas was $250 million.

In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which had an original stated maturity date of December 2017 with automatic one-year renewals through the maturity of the SBL Holdco term loan agreement in 2023. Dominion Solar Projects III, Inc. has $25 million of credit facilities which had an original stated maturity date of May 2018 with automatic one-year renewals through the maturity of the Dominion Solar Projects III, Inc. term loan agreement in 2024. At December 31, 2018, no amounts were outstanding under either of these facilities.

In February and June 2018, Dominion Energy borrowed $950 million and $500 million, respectively, under 364-Day Term Loan Agreements that bore interest at a variable rate. In September 2018, the principal outstanding plus accrued interest for both borrowings was repaid.

In March 2018, Dominion Energy Midstream entered into a $500 million revolving credit facility. The credit facility was scheduled to mature in March 2021, bore interest at a variable rate, and was used to support bank borrowings and the issuance of commercial paper, as well as to support up to $250 million of letters of credit. At December 31, 2018, Dominion Energy Midstream had $73 million outstanding under this credit facility. In February 2019, Dominion Energy Midstream terminated the facility subsequent to repaying the outstanding balance, plus accrued interest.

In October 2018, Dominion Energy entered into a credit agreement, which allows Dominion Energy to issue up to approximately $21 million in letters of credit. The facility terminates in June 2020. At December 31, 2018, Dominion Energy had $21 million in letters of credit outstanding under this agreement.

VIRGINIA POWER

In March 2018, Dominion Energy replaced its two existing joint revolving credit facilities with a $6.0 billion joint revolving credit facility. Virginia Power’s short-term financing is supported through its access as co-borrower to the joint revolving credit facility. The credit facility can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

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

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit
(millions)
At December 31, 2018
Joint revolving credit facility(2)		$6,000		$314		$16
At December 31, 2017
Joint revolving credit facility(3)		$5,000		$542		$—
Joint revolving credit facility(3)		500		—		—
Total		$5,500		$542		$—

(1) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 2.94% and 1.65% at December 31, 2018 and 2017, respectively.

(2) The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Virginia Power was $1.5 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

(3) These facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. The full amount of the facilities was available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. These facilities were scheduled to mature in April 2020 and were 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 had a $100 million credit facility with a maturity date of April 2020. In March 2018, Virginia Power redeemed its variable rate tax-exempt financings supported by this credit facility and terminated the facility.

DOMINION ENERGY GAS

In March 2018, Dominion Energy replaced its two existing joint revolving credit facilities with a $6.0 billion joint revolving credit facility. Dominion Energy Gas’ short-term financing is supported by its access as co-borrower to the joint revolving credit facility. The credit facility can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

Dominion Energy Gas’ share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion Energy, Virginia Power and Questar Gas were as follows:

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit
(millions)
At December 31, 2018
Joint revolving credit facility(2)		$1,500		$  10		$—
At December 31, 2017
Joint revolving credit facility(3)		$1,000		$629		$—
Joint revolving credit facility(3)		500		—		—
Total		$1,500		$629		$—

(1) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 2.58% and 1.57% at December 31, 2018 and 2017, respectively.

(2) A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. The sub-limit for Dominion Energy Gas is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Dominion Energy Gas was $750 million. If Dominion Energy 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

(3) These facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. A maximum of a combined $1.5 billion of the facilities was available to Dominion Energy Gas, assuming adequate capacity was available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. These credit facilities were scheduled to mature in April 2020 and were used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

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Long-Term Debt

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Long-Term Debt

NOTE 17. LONG-TERM DEBT

At December 31,	2018 Weighted- average Coupon(1)			2018			2017
(millions, except percentages)
Dominion Energy Gas Holdings, LLC:
Unsecured Senior Notes:
Variable rate, due 2021		3.39	%	$	500		$	—
2.5% to 3.55%, due 2019 to 2023		2.90	%		1,800			1,800
3.317% to 4.8%, due 2024 to 2044(2)		4.12	%		1,787			1,800
Dominion Energy Gas Holdings, LLC total principal				$	4,087		$	3,600
Securities due within one year		2.50	%		(449	)		—
Unamortized discount and debt issuance costs					(29	)		(30	)
Dominion Energy Gas Holdings, LLC total long-term debt				$	3,609		$	3,570
Virginia Electric and Power Company:
Unsecured Senior Notes:
1.2% to 5.4%, due 2018 to 2023		3.35	%	$	1,800		$	2,650
2.95% to 8.875%, due 2024 to 2048		4.61	%		9,290			7,990
Tax-Exempt Financings(3):
Variable rates, due 2024 to 2027					—			100
1.75% to 5.6%, due 2023 to 2041		2.18	%		664			678
Virginia Electric and Power Company total principal				$	11,754		$	11,418
Securities due within one year		5.00	%		(350	)		(850	)
Unamortized discount, premium and debt issuances costs, net					(83	)		(72	)
Virginia Electric and Power Company total long-term debt				$	11,321		$	10,496
Dominion Energy, Inc.:
Unsecured Senior Notes(4):
Variable rates, due 2019 and 2020		3.23	%	$	800		$	800
1.5% to 6.4%, due 2018 to 2022		2.75	%		2,550			5,800
2.85% to 7.0%, due 2024 to 2044		4.81	%		4,849			5,049
Unsecured Junior Subordinated Notes:
2.579% to 4.104%, due 2019 to 2021		3.08	%		2,100			2,100
Payable to Affiliated Trust, 8.4%, due 2031		8.40	%		10			10
Enhanced Junior Subordinated Notes:
5.25% and 5.75%, due 2054 and 2076		5.48	%		1,485			1,485
Variable rates, due 2066		5.26	%		422			422
Remarketable Subordinated Notes, 2.0%, due 2021 and 2024		2.00	%		1,400			1,400
Unsecured Debentures and Senior Notes(5):
6.8% and 6.875%, due 2026 and 2027		6.81	%		89			89
Unsecured Senior and Medium-Term Notes(6):
5.31% and 6.3%, due 2018					—			120
2.98% to 7.20%, due 2024 to 2051		4.25	%		750			600
Secured Senior Notes, 4.82%, due 2042(7)		4.82	%		362			—
Term Loans, variable rates, due 2023 and 2024(8)		4.85	%		582			638
Tax-Exempt Financing, 1.55%, due 2033(9)		1.55	%		27			27
Capital leases, 4.14% to 6.04%, due 2019 to 2029		5.99	%		39			—
Dominion Energy Midstream Partners, LP:
Term Loans, variable rates, due 2019 and 2021(10)(11)		4.13	%		3,300			300
Revolving Credit Agreement, variable rates, due 2021(11)		3.55	%		73			—
Unsecured Senior and Medium-Term Notes, 5.83% and 6.48%, due 2018(12)					—			255
Unsecured Senior Notes, 3.53% to 4.875%, due 2028 to 2041(12)		4.23	%		430			180
Dominion Energy Gas Holdings, LLC total principal (from above)					4,087			3,600
Virginia Electric and Power Company total principal (from above)					11,754			11,418
Dominion Energy, Inc. total principal				$	35,109		$	34,293
Fair value hedge valuation(13)					(20	)		(22	)
Securities due within one year(14)(15)		3.23	%		(3,624	)		(3,078	)
Credit facility borrowings(11)		3.55	%		(73	)		—
Unamortized discount, premium and debt issuance costs, net					(248	)		(245	)
Dominion Energy, Inc. total long-term debt				$	31,144		$	30,948

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2018.

(2) Amount includes foreign currency remeasurement adjustments.

(3) These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. In March 2018, Virginia Power redeemed certain variable rate tax-exempt financings supported by its $100 million credit facility and terminated the facility. In December 2018, Virginia Power redeemed its $14 million Economic Development Authority of the County of Chesterfield Solid Waste and Sewage Disposal Revenue Bonds due in 2031.

(4) In November and December 2018, Dominion Energy redeemed certain senior notes prior to their stated maturity. See below for a discussion of the senior note redemptions.

(5) Represents debt assumed by Dominion Energy from the merger of its former CNG subsidiary.

(6) Represents debt obligations of Questar Gas. See Note 3 for more information.

(7) Represents debt obligations of Eagle Solar. The debt is nonrecourse to Dominion Energy and is secured by Eagle Solar’s interest in certain merchant solar facilities.

(8) Represents debt associated with SBL Holdco and Dominion Solar Projects III, Inc. The debt is nonrecourse to Dominion Energy and is secured by SBL Holdco and Dominion Solar Projects III, Inc.’s interest in certain merchant solar facilities.

(9) Represents debt obligations of a DGI subsidiary.

(10) Includes debt obligations of Cove Point that are secured by Dominion Energy’s common equity interest in Cove Point.

(11) In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2018.

(12) Represents debt obligations of Dominion Energy Questar Pipeline. See Note 3 for more information.

(13) Represents the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt.

(14) 2017 excludes $250 million of Dominion Energy Questar Pipeline’s senior notes that matured in February 2018 using proceeds from the January 2018 issuance, through private placements, of $100 million and $150 million of senior notes that mature in 2028 and 2038, respectively.

(15) Includes $20 million of estimated mandatory prepayments due within one year based on estimated cash flows in excess of debt service at SBL Holdco and Dominion Solar Projects III, Inc.

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2018, were as follows:

	2019			2020			2021			2022			2023			Thereafter			Total
(millions, except percentages)
Dominion Energy Gas	$	450		$	700		$	500		$	—		$	650		$	1,787		$	4,087
Weighted-average Coupon		2.50	%		2.80	%		3.39	%					3.29	%		4.12	%
Virginia Power
Unsecured Senior Notes	$	350		$	—		$	—		$	750		$	700		$	9,290		$	11,090
Tax-Exempt Financings		—			—			—			—			40			624			664
Total	$	350		$	—		$	—		$	750		$	740		$	9,914		$	11,754
Weighted-average Coupon		5.00	%								3.15	%		2.87	%		4.45	%
Dominion Energy
Term Loans(1)(2)	$	336		$	35		$	3,035		$	34		$	273		$	169		$	3,882
Credit Facility Borrowings(2)		—			—			73			—			—			—			73
Unsecured Senior Notes		2,700			1,000			900			1,500			1,350			17,195			24,645
Secured Senior Notes		17			15			17			19			16			278			362
Tax-Exempt Financings		—			—			—			—			40			651			691
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts		—			—			—			—			—			10			10
Unsecured Junior Subordinated Notes		550			1,000			550			—			—			—			2,100
Enhanced Junior Subordinated Notes		—			—			—			—			—			1,907			1,907
Remarketable Subordinated Notes		—			—			700			—			—			700			1,400
Capital leases		4			4			4			3			3			21			39
Total	$	3,607		$	2,054		$	5,279		$	1,556		$	1,682		$	20,931		$	35,109
Weighted-average Coupon		3.23	%		2.80	%		3.64	%		3.02	%		3.41	%		4.51	%

(1) Excludes mandatory prepayments associated with SBL Holdco and Dominion Solar Projects III, Inc. based on cash flows in excess of debt service. At December 31, 2018, $20 million of estimated mandatory prepayments due within one year were included in securities due within one year in Dominion Energy’s Consolidated Balance Sheets.

(2) In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2018.

The Companies’ short-term credit facility and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2018, there were no events of default under these covenants.

Senior Note Redemptions

In November 2018 and December 2018, Dominion Energy redeemed the following outstanding series of senior notes: 2011 Series A 4.45% Senior Notes due 2021, 2014 Series B 2.50% Senior Notes due 2019, 2014 Series C 3.625% Senior Notes due 2024 and 2018 Series A Floating Rate Senior Notes due 2020 with an aggregate outstanding principal of $2.2 billion. The aggregate redemption price paid was $2.2 billion and represents the principal amount outstanding, accrued and unpaid interest and the applicable make-whole premium of $34 million. Total charges of $69 million, including the make-whole premium, were recognized and recorded in interest expense in Dominion Energy’s Consolidated Statements of Income.

Enhanced Junior Subordinated Notes

In June 2006 and September 2006, Dominion Energy issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids bear interest at three-month LIBOR plus 2.825%, reset quarterly. Previously, interest was fixed at 7.5% per year. The September 2006 hybrids bear interest at the three-month LIBOR plus 2.3%, reset quarterly.

In October 2014, Dominion Energy issued $685 million of October 2014 hybrids that will bear interest at 5.75% per year until October 1, 2024. Thereafter, they will bear interest at the three-month LIBOR plus 3.057%, reset quarterly.

Dominion Energy may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion Energy may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion Energy may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.

Dominion Energy executed RCCs in connection with its issuance of the June 2006 hybrids and the September 2006 hybrids. Under the terms of the RCCs, Dominion Energy covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion Energy shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion Energy has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids at that time, as more fully described in the RCCs. In September 2011, Dominion Energy amended the RCCs of the June 2006 hybrids and September 2006 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock issuances from 180 days to 365 days. The proceeds Dominion Energy receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.

In the first quarter of 2016, Dominion Energy purchased and cancelled $38 million and $4 million of the June 2006 hybrids and the September 2006 hybrids, respectively. In July 2016, Dominion Energy 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 Energy 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 RCC. Also in July 2016, Dominion Energy issued $800 million of 5.25% July 2016 hybrids. The proceeds were used for general corporate purposes, including to finance the tender offer. The July 2016 hybrids are listed on the NYSE under the symbol DRUA.

Remarketable Subordinated Notes

In June 2013, Dominion Energy issued $550 million of 2013 Series A 6.125% Equity Units and $550 million of 2013 Series B 6.0% Equity Units, initially in the form of Corporate Units. In July 2014, Dominion Energy issued $1.0 billion of 2014 Series A 6.375% Equity Units, initially in the form of Corporate Units. The Corporate Units were listed on the NYSE under the symbols DCUA, DCUB and DCUC respectively.

Each Corporate Unit consisted of a stock purchase contract and 1/20 interest in a RSN issued by Dominion Energy. The stock purchase contracts obligated the holders to purchase shares of Dominion Energy common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price paid under the stock purchase contracts was $50 per Corporate Unit and the number of shares purchased was determined under a formula based upon the average closing price of Dominion Energy common stock near the settlement date. The RSNs were pledged as collateral to secure the purchase of common stock under the related stock purchase contracts.

In May 2017, Dominion Energy successfully remarketed the $1.0 billion 2014 Series A 1.50% RSNs due 2020 pursuant to the terms of the related 2014 Equity Units. In connection with the remarketing, the interest rate on the junior subordinated notes was reset to 2.579%, payable on a semi-annual basis and Dominion Energy ceased to have the ability to redeem the notes at its option or defer interest payments. In March 2016 and May 2016, Dominion Energy 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 Energy ceased to have the ability to redeem the notes at its option or defer interest payments. At December 31, 2018, the securities are included in junior subordinated notes in Dominion Energy’s Consolidated Balance Sheets. Dominion Energy did not receive any proceeds from the remarketings. Remarketing proceeds belonged to the investors holding the related 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 Energy for issuance of 12.5 million shares of its common stock in July 2017 and 8.5 million shares of its common stock in both April 2016 and July 2016. See Issuance of Common Stock below for a description of common stock issued by Dominion Energy under the stock purchase contracts.

In August 2016, Dominion Energy issued $1.4 billion of 2016 Series A 6.75% Equity Units, initially in the form of Corporate Units. The Corporate Units are listed on the NYSE under the symbol DCUD. The net proceeds from the 2016 Equity Units were used to finance the Dominion Energy Questar Combination. See Note 3 for more information.

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

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

Dominion Energy has recorded the present value of the stock purchase contract payments as a liability offset by a charge to equity. Interest payments on the RSNs are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS, Dominion Energy applies the treasury stock method to the equity units.

Pursuant to the terms of the 2016 Equity Units, Dominion Energy expects to remarket both the 2016 Series A-1 and 2016 Series A-2 RSNs during the second or third quarter of 2019. Following a successful remarketing, the interest rate on the RSNs will be reset, interest will be payable on a semi-annual basis and Dominion Energy will cease to have the ability to redeem the RSNs at its option or defer interest payments. Proceeds of each remarketing will belong to the investors in the related equity units and will be held and applied on their behalf at the settlement date of the related stock purchase contracts to pay the purchase price to Dominion Energy for issuance of its common stock.

Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion Energy will issue between 15.1 million and 18.9 million shares in August 2019. A total of 23.1 million shares of Dominion Energy’s common stock has been reserved for issuance in connection with the stock purchase contracts.

Selected information about Dominion Energy’s equity units is presented below:

Issuance Date	Units Issued		Total Net Proceeds		Total Long-term Debt		RSN Annual Interest Rate			Stock Purchase Contract Annual Rate			Stock Purchase Contract Liability(1)		Stock Purchase Settlement Date
(millions, except interest rates)
8/15/2016(2)		28	$	1,374.8		$1,400.0		2.000	%(3)		4.750	%		$190.6		8/15/2019

(1) Payments of $64 million and $101 million were made in 2018 and 2017, respectively, including payments for the remarketed 2014 Series A notes. The stock purchase contract liability was $47 million and $111 million at December 31, 2018 and 2017, respectively.

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

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

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Preferred Stock

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Preferred Stock

NOTE 18. PREFERRED STOCK

Dominion Energy is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 2018 or 2017.

Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference; however, none were issued and outstanding at December 31, 2018 or 2017.

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Equity

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Equity

NOTE 19. EQUITY

Issuance of Common Stock

DOMINION ENERGY

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

During 2018, Dominion Energy received cash proceeds, net of fees and commissions, of $2.5 billion from the issuance of approximately 36 million shares of common stock through various programs including the forward sale agreements described below resulting in approximately 681 million shares of common stock outstanding at December 31, 2018. These proceeds include cash of $315 million received from the issuance of 4.5 million of such shares through Dominion Energy Direct^® and employee savings plans.

In July 2017, Dominion Energy issued 12.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2014 Equity Units and received proceeds of $1.0 billion.

In both April 2016 and July 2016, Dominion Energy issued 8.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2013 Equity Units and received $1.1 billion of total proceeds. Additionally, Dominion Energy completed a market issuance of equity in April 2016 of 10.2 million shares and received proceeds of $756 million through a registered underwritten public offering. A portion of the net proceeds was used to finance the Dominion Energy Questar Combination. See Note 3 for more information.

In June 2017, Dominion Energy 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 June 2017, Dominion Energy entered into three separate sales agency agreements to effect sales under the program and pursuant to which it may offer from time to time up to $500 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the NYSE at market prices or in such other transactions as are agreed upon by Dominion Energy and the sales agents in conformance with applicable securities laws. In January 2018, Dominion Energy provided sales instructions to one of the sales agents and issued 6.6 million shares through at-the-market issuances and received cash proceeds of $495 million, net of fees and commissions paid of $5 million. Following these issuances, Dominion Energy had no remaining ability to issue stock under the 2017 sales agency agreements and completed the program. In February 2018, Dominion Energy entered into six separate sales agency agreements to effect sales under a new at-the-market program pursuant to which it may offer from time to time up to $1.0 billion aggregate amount of its common stock. These agreements replaced the sales agency agreements entered into by Dominion Energy in June 2017. Sales of common stock can be made by means of private negotiated transactions, as transactions on the NYSE at market prices or in such other transactions as are agreed upon by Dominion Energy and the sales agents in conformance with applicable securities laws. In the fourth quarter of 2018, Dominion Energy provided sales instructions to two of the sales agents and issued 2.7 million shares through at-the-market issuances and received cash proceeds of $197 million, net of fees and commissions paid of $2 million. Following these issuances, Dominion Energy has $801 million of remaining ability to issue stock under the sales agency agreements.

Dominion Energy entered in March 2018, and closed in April 2018, separate forward sale agreements with Goldman Sachs & Co. LLC and Credit Suisse Capital LLC, as forward purchasers, and an underwriting agreement with Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, as representatives of the several underwriters named therein, relating to an aggregate of 20 million shares of Dominion Energy common stock. The underwriting agreement granted the underwriters a 30-day option to purchase up to an additional three million shares of Dominion Energy common stock, which the underwriters exercised with respect to approximately 2.1 million shares in April 2018. Dominion Energy entered into separate forward sale agreements with the forward purchasers with respect to the additional shares. In December 2018, Dominion Energy received proceeds of $1.4 billion (after deducting underwriting discounts, but before deducting expenses, and subject to forward price adjustments under the forward sale agreements) upon the physical settlement of 22.1 million shares.

See Note 3 to the Consolidated Financial Statements for information on the issuance of Dominion Energy common stock in January 2019 in connection with the SCANA Combination. Also in January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy through the issuance of common stock as noted below.

VIRGINIA POWER

In 2018, 2017 and 2016, Virginia Power did not issue any shares of its common stock to Dominion Energy.

Shares Reserved for Issuance

Dominion Energy has approximately 76 million shares reserved and available for issuance for Dominion Energy Direct^®, employee stock awards, employee savings plans, director stock compensation plans and issuances in connection with stock purchase contracts and the at-the-market program. See Note 17 for more information.

Repurchase of Common Stock

Dominion Energy did not repurchase any shares in 2018 or 2017 and does not plan to repurchase shares during 2019, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization.

Purchase of Dominion Energy Midstream Units

In September 2015, Dominion Energy initiated a program to purchase from the market up to $50 million of common units representing limited partner interests in Dominion Energy Midstream, which expired in September 2016. Dominion Energy purchased approximately 658,000 common units for $17 million for the year ended December 31, 2016.

In January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy through the issuance of 22.5 million shares of common stock valued at $1.6 billion. The merger was accounted for by Dominion Energy following the guidance for a change in a parent company’s ownership interest in a consolidated subsidiary. Because Dominion Energy controls Dominion Energy Midstream both before and after the merger, the changes in Dominion Energy’s ownership interest in Dominion Energy Midstream were accounted for as an equity transaction and no gain or loss will be recognized. The tax effect of the merger will be presented in common stock.

Issuance of Dominion Energy Midstream Units

In 2017, Dominion Energy Midstream received $18 million of proceeds from the issuance of common units through its at-the-market program.

In 2016, Dominion Energy Midstream received $482 million of proceeds from the issuance of common units and $490 million of proceeds from the issuance of convertible preferred units. The net proceeds were primarily used to finance a portion of the acquisition of Dominion Energy Questar Pipeline from Dominion Energy. See Note 3 for more information.

The holders of the convertible preferred units were entitled to receive cumulative quarterly distributions payable in cash or additional convertible preferred units, subject to certain conditions. The units were convertible into Dominion Energy Midstream common units on a one-for-one basis, subject to certain adjustments, (i) in whole or in part at the option of the unitholders any time after December 1, 2018 or, (ii) in whole or in part at Dominion Energy Midstream’s option, subject to certain conditions, any time after December 1, 2019. Immediately prior to the closing of Dominion Energy’s acquisition of the outstanding interest in Dominion Energy Midstream noted above, each convertible preferred unit was converted into common units representing limited partner interests in Dominion Energy Midstream in accordance with the terms of Dominion Energy Midstream’s partnership agreement.

In May 2018, all of the subordinated units of Dominion Energy Midstream held by Dominion Energy were converted into common units on a 1:1 ratio following the payment of Dominion Energy Midstream’s distribution for the first quarter of 2018. In June 2018, Dominion Energy, as general partner, exercised an incentive distribution right reset as defined in Dominion Energy Midstream’s partnership agreement and received 26.7 million common units representing limited partner interests in Dominion Energy Midstream. As a result of the increase in its ownership interest in Dominion Energy Midstream, Dominion Energy recorded a decrease in noncontrolling interest, and a correspond-ing increase in shareholders’ equity, of $375 million reflecting the change in the carrying value of the interest in the net assets of Dominion Energy Midstream held by others.

Accumulated Other Comprehensive Income (Loss)

Presented in the table below is a summary of AOCI by component:

At December 31,	2018			2017
(millions)
Dominion Energy
Net deferred losses on derivatives-hedging activities, net of $79 and $188 tax	$	(234	)	$	(301	)
Net unrealized gains on nuclear decommissioning trust funds, net of $— and $(419) tax		2			747
Net unrecognized pension and other postretirement benefit costs, net of $519 and $692 tax		(1,465	)		(1,101	)
Other comprehensive loss from equity method investees, net of $— and $2 tax		(2	)		(3	)
Total AOCI, including noncontrolling interest	$	(1,699	)	$	(658	)
Less other comprehensive income attributable to noncontrolling interest		1			1
Total AOCI, excluding noncontrolling interest	$	(1,700	)	$	(659	)
Virginia Power
Net deferred losses on derivatives-hedging activities, net of $4 and $8 tax	$	(13	)	$	(12	)
Net unrealized gains on nuclear decommissioning trust funds, net of $— and $(47) tax		1			74
Total AOCI	$	(12	)	$	62
Dominion Energy Gas
Net deferred losses on derivatives-hedging activities, net of $8 and $15 tax	$	(25	)	$	(23	)
Net unrecognized pension costs, net of $56 and $59 tax		(144	)		(75	)
Total AOCI	$	(169	)	$	(98	)

DOMINION ENERGY

The following table presents Dominion Energy’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 loss from equity method investees			Total
(millions)
Year Ended December 31, 2018
Beginning balance		$(302	)		$ 747			$(1,101	)		$(3	)		$(659	)
Other comprehensive income before reclassifications: gains (losses)		30			(18	)		(215	)		1			(202	)
Amounts reclassified from AOCI: (gains) losses(1)		102			5			78			—			185
Net current period other comprehensive income (loss)		132			(13)			(137	)		1			(17	)
Cumulative-effect of changes in accounting principle		(64	)		(732)			(227	)		—			(1,023	)
Less other comprehensive income (loss) attributable to noncontrolling interest		1			—			—			—			1
Ending balance		$(235	)		$2			$(1,465	)		$(2	)		$(1,700	)
Year Ended December 31, 2017
Beginning balance		$(280	)		$ 569			$(1,082	)		$(6	)		$  (799	)
Other comprehensive income before reclassifications: gains (losses)		8			215			(69	)		3			157
Amounts reclassified from AOCI: (gains) losses(1)		(29	)		(37	)		50			—			(16	)
Net current period other comprehensive income (loss)		(21	)		178			(19	)		3			141
Less other comprehensive income (loss) attributable to noncontrolling interest		1			—			—			—			1
Ending balance		$(302	)		$ 747			$(1,101	)		$(3	)		$  (659	)

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

The following table presents Dominion Energy’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)
Year Ended December 31, 2018
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$90			Operating revenue
		(14	)		Electric fuel and other energy-related purchases
Interest rate contracts		48			Interest and related charges
Foreign currency contracts		13			Other Income
Total		137
Tax		(35	)		Income tax expense
Total, net of tax		$102
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities		$7			Other income
Total		7
Tax		(2	)		Income tax expense
Total, net of tax		$5
Unrecognized pension and other postretirement benefit costs:
Amortization of prior-service costs (credits)		$(21	)		Other income
Amortization of actuarial losses		120			Other income
Total		99
Tax		(21	)		Income tax expense
Total, net of tax		$78
Year Ended December 31, 2017
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$(81	)		Operating revenue
		2			Purchased gas
Interest rate contracts		52			Interest and related charges
Foreign currency contracts		(20	)		Other Income
Total		(47	)
Tax		18			Income tax expense
Total, net of tax		$(29	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities		$(81	)		Other income
Impairment		23			Other income
Total		(58	)
Tax		21			Income tax expense
Total, net of tax		$(37	)
Unrecognized pension and other postretirement benefit costs:
Prior-service costs (credits)		$(21	)		Other income
Actuarial losses		103			Other income
Total		82
Tax		(32	)		Income tax expense
Total, net of tax		$50

VIRGINIA POWER

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

	Deferred gains and losses on derivatives- hedging activities			Unrealized gains and losses on investment securities			Total
(millions)
Year Ended December 31, 2018
Beginning balance	$	(12)		$	74			$ 62
Other comprehensive income before reclassifications: gains (losses)		1			—			1
Amounts reclassified from AOCI: (gains) losses(1)		1			—			1
Net current period other comprehensive income (loss)		2			—			2
Cumulative-effect of changes in accounting principle		(3	)		(73	)		(76	)
Ending balance	$	(13	)	$	1			$(12	)
Year Ended December 31, 2017
Beginning balance	$	(8	)	$	54			$ 46
Other comprehensive income before reclassifications: gains (losses)		(5	)		24			19
Amounts reclassified from AOCI: gains (losses)(1)		1			(4	)		(3	)
Net current period other comprehensive income (loss)		(4	)		20			16
Ending balance	$	(12	)	$	74			$ 62

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

The following table presents Virginia Power’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)
Year Ended December 31, 2018
(Gains) losses on cash flow hedges:
Interest rate contracts		$ 1			Interest and related charges
Total		1
Tax		—			Income tax expense
Total, net of tax		$ 1
Year Ended December 31, 2017
(Gains) losses on cash flow hedges:
Interest rate contracts		$ 1			Interest and related charges
Total		1
Tax		—			Income tax expense
Total, net of tax		$ 1
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities		$(9	)		Other income
Impairment		2			Other income
Total		(7	)
Tax		3			Income tax expense
Total, net of tax		$(4	)

DOMINION ENERGY GAS

The following table presents Dominion Energy 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)
Year Ended December 31, 2018
Beginning balance		$(23	)		$  (75	)	$	(98	)
Other comprehensive income before reclassifications: gains (losses)		(17	)		(52	)		(69	)
Amounts reclassified from AOCI: (gains) losses(1)		20			4			24
Net current period other comprehensive income (loss)		3			(48	)		(45	)
Cumulative-effect of changes in accounting principle		(5	)		(21	)		(26	)
Ending balance		$(25	)		$(144	)	$	(169	)
Year Ended December 31, 2017
Beginning balance		$(24	)		$  (99	)	$	(123	)
Other comprehensive income before reclassifications: gains (losses)		5			20			25
Amounts reclassified from AOCI: gains (losses)(1)		(4	)		4			—
Net current period other comprehensive income (loss)		1			24			25
Ending balance		$(23	)		$  (75	)	$	(98	)

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

The following table presents Dominion Energy 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)
Year Ended December 31, 2018
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$   8		Operating revenue
Interest rate contracts		6		Interest and related charges
Foreign currency contracts		13		Other income
Total		27
Tax		(7	)	Income tax expense
Total, net of tax		$ 20
Unrecognized pension costs:
Actuarial losses		$   6		Other income
Total		6
Tax		(2	)	Income tax expense
Total, net of tax		$   4
Year Ended December 31, 2017
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$   8		Operating revenue
Interest rate contracts		5		Interest and related charges
Foreign currency contracts		(20	)	Other income
Total		(7	)
Tax		3		Income tax expense
Total, net of tax		$  (4	)
Unrecognized pension costs:
Actuarial losses		$   6		Other income
Total		6
Tax		(2	)	Income tax expense
Total, net of tax		$   4

Stock-Based Awards

The 2005 and 2014 Incentive Compensation Plans permit stock-based awards that include restricted stock, performance grants, goal-based stock, stock options, and stock appreciation rights. The Non-Employee Directors Compensation Plan permits grants of restricted stock and stock options. Under provisions of these plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the CGN Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. No options are outstanding under either plan. At December 31, 2018, approximately 22 million shares were available for future grants under these plans.

Goal-based stock awards are granted in lieu of cash-based performance grants to certain officers who have not achieved a certain targeted level of share ownership. As of December 31, 2018, unrecognized compensation cost related to nonvested goal-based stock awards was immaterial.

Dominion Energy measures and recognizes compensation expense relating to share-based payment transactions over the vesting period based on the fair value of the equity or liability instruments issued. Dominion Energy’s results for the years ended December 31, 2018, 2017 and 2016 include $48 million, $45 million, and $33 million, respectively, of compensation costs and $12 million, $16 million, and $11 million, respectively of income tax benefits related to Dominion Energy’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income. Excess Tax Benefits are classified as a financing cash flow.

RESTRICTED STOCK

Restricted stock grants are made to officers under Dominion Energy’s LTIP and may also be granted to certain key non-officer employees. The fair value of Dominion Energy’s restricted stock awards is equal to the closing price of Dominion Energy’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2018, 2017 and 2016:

	Shares			Weighted —average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2015		855			$66.16
Granted		372			71.67
Vested		(301	)		56.83
Cancelled and forfeited		(40	)		71.75
Nonvested at December 31, 2016		886			$71.40
Granted		454			74.24
Vested		(287	)		68.90
Cancelled and forfeited		(10	)		72.37
Nonvested at December 31, 2017		1,043			$73.32
Granted		534			72.92
Vested		(316	)		73.59
Cancelled and forfeited		(53	)		74.25
Nonvested at December 31, 2018		1,208			$73.03

As of December 31, 2018, unrecognized compensation cost related to nonvested restricted stock awards totaled $49 million and is expected to be recognized over a weighted-average period of 2.1 years. The fair value of restricted stock awards that vested was $23 million, $21 million, and $21 million in 2018, 2017 and 2016, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion Energy stock and the applicable federal, state and local tax withholding rates.

CASH-BASED PERFORMANCE GRANTS

Cash-based performance grants are made to Dominion Energy’s officers under Dominion Energy’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.

In February 2016, a cash-based performance grant was made to officers. Payout of the performance grant occurred in January 2018 based on the achievement of two performance metrics during 2016 and 2017: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The total of the payout under the grant was $12 million.

In February 2017, two cash-based performance grants were made to officers as Dominion Energy transitioned from a two-year performance period to a three-year performance period. Payout of the two-year grant occurred in January 2019 based on the achievement of two performance metrics during 2017 and 2018: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC with an additional partial payout based on Dominion Energy’s price-earnings ratio relative to that of the members of Dominion Energy’s compensation peer group. The total of the payout under the two-year grant was $13 million and a liability of $13 million had been accrued for this award. Payout of the three-year cash-based performance grant is expected to occur by March 15, 2020 based on the achievement of two performance metrics during 2017, 2018 and 2019: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There are additional opportunities to earn a portion of the awards based on Dominion Energy’s absolute TSR or relative price-earnings ratio performance. At December 31, 2018, the targeted amount of the three-year grant was $14 million and a liability of $10 million had been accrued for the award.

In February 2018, a cash-based performance grant was made to officers. Payout of the three-year cash-based performance grant is expected to occur by March 15, 2021 based on the achievement of two performance metrics during 2018, 2019 and 2020: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There are additional opportunities to earn a portion of the awards based on Dominion Energy’s absolute TSR or relative price-earnings ratio performance. At December 31, 2018, the targeted amount of the three-year grant was $16 million and a liability of $5 million had been accrued for this award.

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Dividend Restrictions

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Dividend Restrictions

NOTE 20. DIVIDEND RESTRICTIONS

The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2018, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

The North Carolina Commission, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by Virginia Power and PSNC to (i) the amount of retained earnings at closing of the SCANA Combination plus (ii) any future earnings recorded by Virginia Power and PSNC after such date. In addition, notice to the North Carolina Commission is required if payment of dividends causes the equity component of Virginia Power and PSNC’s capital structure to fall below 45%.

The Ohio Commission may prohibit any public service company, including East Ohio, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2018, the Ohio Commission had not restricted the payment of dividends by East Ohio.

Pursuant to the SCANA Merger Approval Order, the amount of any SCE&G dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry. There is no specific restriction on the payment of dividends by SCE&G.

The Utah Commission may prohibit any public service company, including Questar Gas, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2018, the Utah Commission had not restricted the payment of dividends by Questar Gas.

Certain agreements associated with the Companies’ credit facility contains restrictions on the ratio of debt to total capitalization. These limitations did not restrict the Companies’ ability to pay dividends or receive dividends from their subsidiaries at December 31, 2018.

In connection with the SCANA Combination, under the terms of the merger agreement, Dominion Energy could not declare, set aside or pay any dividends on, or make any other distributions (whether in cash, stock or property) in respect of, any of its capital stock, other than regular quarterly cash dividends from January 2018 through January 2019.

As part of the merger agreement with Dominion Energy Midstream from November 2018 through January 2019, Dominion Energy could not declare, set aside or pay any dividends on, or make any other distributions (whether in cash, stock or property) in respect of, any of its capital stock, other than regular quarterly cash dividends.

See Note 17 for a description of potential restrictions on dividend payments by Dominion Energy in connection with the deferral of interest payments on certain junior subordinated notes and equity units, initially in the form of corporate units.

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Employee Benefit Plans

NOTE 21. EMPLOYEE BENEFIT PLANS

Dominion Energy and Dominion Energy Gas—Defined Benefit Plans

Dominion Energy provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Dominion Energy Gas participates in a number of the Dominion Energy-sponsored retirement plans. Under the terms of its benefit plans, Dominion Energy reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Dominion Energy maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the employee’s compensation. Dominion Energy’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension programs also provide benefits to certain retired executives under company-sponsored nonqualified employee benefit plans. The nonqualified plans are funded through contributions to grantor trusts. Dominion Energy also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service.

Pension benefits for Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Pension Plan, a defined benefit pension plan sponsored by Dominion Energy that provides benefits to multiple Dominion Energy subsidiaries. Pension benefits for Dominion Energy Gas employees represented by collective bargaining units are covered by separate pension plans for East Ohio and, for DETI, a plan that provides benefits to employees of both DETI and Hope. Employee compensation is the basis for allocating pension costs and obligations between DETI and Hope and determining East Ohio’s share of total pension costs.

Retiree healthcare and life insurance benefits for Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Retiree Health and Welfare Plan, a plan sponsored by Dominion Energy that provides certain retiree healthcare and life insurance benefits to multiple Dominion Energy subsidiaries. Retiree healthcare and life insurance benefits for Dominion Energy Gas employees represented by collective bargaining units are covered by separate other postretirement benefit plans for East Ohio and, for DETI, a plan that provides benefits to both DETI and Hope. Employee headcount is the basis for allocating other postretirement benefit costs and obligations between DETI and Hope and determining East Ohio’s share of total other postretirement benefit costs.

Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates, mortality rates and the rate of compensation increases.

Dominion Energy uses December 31 as the measurement date for all of its employee benefit plans, including those in which Dominion Energy Gas participates. Dominion Energy uses the market-related value of pension plan assets to determine the expected return on plan assets, a component of net periodic pension cost, for all pension plans, including those in which Dominion Energy Gas participates. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized.

Dominion Energy’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $(605) million and $1.6 billion in 2018 and 2017, respectively, versus expected returns of $806 million and $767 million, respectively. Dominion Energy Gas’ pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual returns (losses) of $(129) million and $335 million in 2018 and 2017, respectively, versus expected returns of $178 million and $165 million, respectively. 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 such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

During 2016, Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units) engaged their actuary to conduct an experience study of their employees demographics over a five-year period as compared to significant assumptions that were being used to determine pension and other postretirement benefit obligations and periodic costs. These assumptions primarily included mortality, retirement rates, termination rates, and salary increase rates. The changes in assumptions implemented as a result of the experience study resulted in increases of $290 million and $38 million in the pension and other postretirement benefits obligations, respectively, at December 31, 2016 for Dominion Energy and $24 million and $9 million in the pension and other postretirement benefits obligations, respectively, at December 31, 2016 for Dominion Energy Gas. In addition, these changes increased net periodic benefit costs $42 million for Dominion Energy during 2017. The increase in net periodic benefit costs for Dominion Energy Gas during 2017 was immaterial.

PLAN AMENDMENTS AND REMEASUREMENTS

In the fourth quarter of 2017, Dominion Energy remeasured its pension and other postretirement benefit plans as a result of voluntary and involuntary separation programs at Dominion Energy Questar. The settlement and related remeasurement resulted in a reduction in the pension benefit obligation of approximately $75 million and an increase in the accumulated postretirement benefit obligation of approximately $2 million. The discount rates used for the 2017 pension cost and related settlement were 4.46% as of December 31, 2016, 4.51% as of January 31, 2017 and 4.05% as of June 30 and September 30, 2017. All other assumptions used were consistent with the measurement as of December 31, 2016.

In the first quarter of 2017, Dominion Energy and Dominion Energy Gas remeasured an other postretirement benefit plan as a result of an amendment that changed post-65 retiree medical coverage for certain current and future Local 69 retirees effective July 1, 2017. The remeasurement resulted in a decrease in Dominion Energy and Dominion Energy Gas’ accumulated postretirement benefit obligation of $73 million and $61 million, respectively. As a result of regulatory accounting, the remeasurement had an immaterial impact on net income for both Dominion Energy and Dominion Energy Gas. The discount rate used for the remeasurement was 4.30%. All other assumptions used were consistent with the measurement as of December 31, 2016.

Also during the first quarter of 2017, Dominion Energy recorded a $7 million ($4 million after-tax) charge, including $6 million ($4 million after-tax) at Dominion Energy Gas, as a result of additional payments associated with the new collective bargaining agreement, which is reflected in other operations and maintenance expense in their Consolidated Statements of Income.

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

FUNDED STATUS

The following table summarizes the changes in pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units):

	Pension Benefits						Other Postretirement Benefits
Year Ended December 31,	2018			2017			2018			2017
(millions, except percentages)
Dominion Energy
Changes in benefit obligation:
Benefit obligation at beginning of year	$	9,052		$	8,132		$	1,529		$	1,478
Service cost		157			138			27			26
Interest cost		337			345			56			60
Benefits paid		(358	)		(323	)		(87	)		(83	)
Actuarial (gains) losses during the year		(688	)		830			(158	)		119
Plan amendments(1)		—			5			(4	)		(73	)
Settlements and curtailments(2)		—			(75	)		—			2
Benefit obligation at end of year	$	8,500		$	9,052		$	1,363		$	1,529
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	8,062		$	7,016		$	1,729		$	1,512
Actual return (loss) on plan assets		(513	)		1,327			(92	)		236
Employer contributions		6			118			12			13
Benefits paid		(358	)		(323	)		(68	)		(32	)
Settlements(2)		—			(76	)		—			—
Fair value of plan assets at end of year	$	7,197		$	8,062		$	1,581		$	1,729
Funded status at end of year	$	(1,303	)	$	(990	)	$	218		$	200
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	$	1,003		$	1,117		$	276		$	261
Other current liabilities		(34	)		(8	)		(2	)		—
Noncurrent pension and other postretirement benefit liabilities		(2,272	)		(2,099	)		(56	)		(61	)
Net amount recognized	$	(1,303	)	$	(990	)	$	218		$	200
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate		4.42%–4.43%			3.80%–3.81%			4.37%–4.38%			3.76%
Weighted average rate of increase for compensation		4.32%			4.09%			4.30%-4.55%			3.95%-4.11%
Dominion Energy Gas
Changes in benefit obligation:
Benefit obligation at beginning of year	$	773		$	683		$	290		$	320
Service cost		18			15			4			4
Interest cost		29			30			11			12
Benefits paid		(34	)		(33	)		(18	)		(19	)
Actuarial (gains) losses during the year		(56	)		78			(27	)		34
Plan amendments(1)		—			—			(4	)		(61	)
Benefit obligation at end of year	$	730		$	773		$	256		$	290
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	1,803		$	1,542		$	333		$	299
Actual return (loss) on plan assets		(113	)		294			(16	)		41
Employer contributions		—			—			12			12
Benefits paid		(34	)		(33	)		(18	)		(19	)
Fair value of plan assets at end of year	$	1,656		$	1,803		$	311		$	333
Funded status at end of year	$	926		$	1,030		$	55		$	43
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	$	926		$	1,030		$	63		$	57
Noncurrent pension and other postretirement benefit liabilities(3)		—			—			(8	)		(14	)
Net amount recognized	$	926		$	1,030		$	55		$	43
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate		4.42	%		3.81	%		4.37	%		3.76	%
Weighted average rate of increase for compensation		4.55	%		4.11	%		n/a			n/a

(1) 2017 amounts relate primarily to a plan amendment that changed post-65 retiree medical coverage for certain current and future Local 69 retirees effective July 1, 2017.

(2) 2017 amount relates primarily to settlement and curtailment as a result of the voluntary and involuntary separation programs at Dominion Energy Questar.

(3) Reflected in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.

The ABO for all of Dominion Energy’s defined benefit pension plans was $7.8 billion and $8.2 billion at December 31, 2018 and 2017, respectively. The ABO for the defined benefit pension plans covering Dominion Energy Gas employees represented by collective bargaining units was $689 million and $724 million at December 31, 2018 and 2017, respectively.

Under its funding policies, Dominion Energy evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion Energy determines the amount of contributions for the current year, if any, at that time. During 2018, Dominion Energy and Dominion Energy Gas made no contributions to the qualified defined benefit pension plans. Dominion Energy expects to make $21 million of the minimum required contributions in 2019, and no contributions are currently expected in 2019 for Dominion Energy Gas.

Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion Energy’s subsidiaries, including Dominion Energy Gas, fund other postretirement benefit costs through VEBAs. Dominion Energy’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion Energy’s contributions to VEBAs, all of which pertained to Dominion Energy Gas employees, totaled $12 million for both 2018 and 2017, and Dominion Energy expects to contribute approximately $12 million to the Dominion Energy VEBAs in 2019, all of which pertains to Dominion Energy Gas employees.

Dominion Energy and Dominion Energy Gas do not expect any pension or other postretirement plan assets to be returned during 2019.

The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units):

	Pension Benefits				Other Postretirement Benefits
As of December 31,	2018		2017		2018		2017
(millions)
Dominion Energy
Benefit obligation	$	7,705	$	8,209		$164		$191
Fair value of plan assets		5,398		6,103		136		156
Dominion Energy Gas
Benefit obligation	$	—	$	—		$134		$157
Fair value of plan assets		—		—		126		143

The following table provides information on the ABO and fair value of plan assets for Dominion Energy’s pension plans with an ABO in excess of plan assets:

As of December 31,	2018		2017
(millions)
Accumulated benefit obligation	$	7,056	$	7,392
Fair value of plan assets		5,398		6,103

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans:

	Estimated Future Benefit Payments
	Pension Benefits		Other Postretirement Benefits
(millions)
Dominion Energy
2019		$407		$98
2020		405		99
2021		426		99
2022		442		99
2023		465		98
2024-2028	2,548		461
Dominion Energy Gas
2019		$37		$19
2020		39		19
2021		40		19
2022		42		19
2023		43		19
2024-2028		223		90

PLAN ASSETS

Dominion Energy’s overall objective for investing its pension and other postretirement plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. As a participating employer in various pension plans sponsored by Dominion Energy, Dominion Energy Gas is subject to Dominion Energy’s investment policies for such plans. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for Dominion Energy’s pension funds are 28% U.S. equity, 18% non-U.S. equity, 35% fixed income, 3% real estate and 16% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the U.S. Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the U.S. including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity real estate investment trusts and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.

Dominion Energy also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies.

Strategic investment policies are established for Dominion Energy’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion Energy’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.

For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6.

The fair values of Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) pension plan assets by asset category are as follows:

At December 31,	2018								2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Dominion Energy
Cash and cash equivalents	$	17	$	1		$—	$	18	$	18	$	—		$—	$	18
Common and preferred stocks:
U.S.		1,645		—		—		1,645		1,902		—		—		1,902
International		1,061		—		—		1,061		1,151		—		—		1,151
Insurance contracts		—		318		—		318		—		352		—		352
Corporate debt instruments		23		729		—		752		41		729		—		770
Government securities		25		605		—		630		9		676		—		685
Total recorded at fair value	$	2,771	$	1,653		$—	$	4,424	$	3,121	$	1,757		$—	$	4,878
Assets recorded at NAV(1):
Common/collective trust funds								1,849								2,272
Alternative investments:
Real estate funds								108								111
Private equity funds								633								606
Debt funds								155								161
Hedge funds								17								19
Total recorded at NAV							$	2,762							$	3,169
Total investments(2)							$	7,186							$	8,047
Dominion Energy Gas
Cash and cash equivalents	$	4	$	—		$—	$	4	$	4	$	—		$—	$	4
Common and preferred stocks:
U.S.		378		—		—		378		425		—		—		425
International		244		—		—		244		257		—		—		257
Insurance contracts		—		73		—		73		—		79		—		79
Corporate debt instruments		5		168		—		173		9		163		—		172
Government securities		6		139		—		145		2		151		—		153
Total recorded at fair value	$	637	$	380		$—	$	1,017	$	697	$	393		$—	$	1,090
Assets recorded at NAV(1):
Common/collective trust funds								425								509
Alternative investments:
Real estate funds								25								25
Private equity funds								146								135
Debt funds								36								36
Hedge funds								4								4
Total recorded at NAV							$	636							$	709
Total investments(3)							$	1,653							$	1,799

(1) These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

(2) Excludes net assets related to pending sales of securities of $12 million, net accrued income of $21 million, and includes net assets related to pending purchases of securities of $22 million at December 31, 2018. Excludes net assets related to pending sales of securities of $11 million, net accrued income of $19 million, and includes net assets related to pending purchases of securities of $15 million at December 31, 2017.

(3) Excludes net assets related to pending sales of securities of $3 million, net accrued income of $5 million, and includes net assets related to pending purchases of securities of $5 million at December 31, 2018. Excludes net assets related to pending sales of securities of $3 million, net accrued income of $4 million, and includes net assets related to pending purchases of securities of $3 million at December 31, 2017.

The fair values of Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) other postretirement plan assets by asset category are as follows:

At December 31,	2018								2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Dominion Energy
Cash and cash equivalents		$1		$1		$—	$	2		$1		$2		$—		$3
Common and preferred stocks:
U.S.		554		—		—		554		636		—		—		636
International		170		—		—		170		196		—		—		196
Insurance contracts		—		19		—		19		—		21		—		21
Corporate debt instruments		1		44		—		45		2		44		—		46
Government securities		2		37		—		39		1		41		—		42
Total recorded at fair value		$728		$101		$—	$	829		$836		$108		$—		$944
Assets recorded at NAV(1):
Common/collective trust funds								650								689
Alternative investments:
Real estate funds								10								9
Private equity funds								80								73
Debt funds								10								11
Hedge funds								1								1
Total recorded at NAV							$	751								$783
Total investments(2)							$	1,580								$1,727
Dominion Energy Gas
Common and preferred stocks:
U.S.		$113		$—		$—	$	113		$130		$—		$—		$130
International		30		—		—		30		33		—		—		33
Total recorded at fair value		$143		$—		$—	$	143		$163		$—		$—		$163
Assets recorded at NAV(1):
Common/collective trust funds								148								154
Alternative investments:
Real estate funds								2								1
Private equity funds								18								15
Debt funds								—								—
Total recorded at NAV							$	168								$170
Total investments							$	311								$333

(1) These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

(2) Excludes net assets related to pending sales of securities of $1 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $2 million at December 31, 2018. Excludes net assets related to pending sales of securities of $1 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $1 million at December 31, 2017.

The Plan’s investments are determined based on the fair values of the investments and the underlying investments, which have been determined as follows:

• Cash and Cash Equivalents—Investments are held primarily in short-term notes and treasury bills, which are valued at cost plus accrued interest.

• Common and Preferred Stocks—Investments are valued at the closing price reported on the active market on which the individual securities are traded.

• Insurance Contracts—Investments in Group Annuity Contracts with John Hancock were entered into after 1992 and are stated at fair value based on the fair value of the underlying securities as provided by the managers and include investments in U.S. government securities, corporate debt instruments, state and municipal debt securities.

• Corporate Debt Instruments—Investments are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar instruments, the instrument is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks or a broker quote, if available.

• Government Securities—Investments are valued using pricing models maximizing the use of observable inputs for similar securities.

• Common/Collective Trust Funds—Common/collective trust funds invest in debt and equity securities and other instruments with characteristics similar to those of the funds’ benchmarks. The primary objectives of the funds are to seek investment returns that approximate the overall performance of their benchmark indexes. These benchmarks are major equity indices, fixed income indices, and money market indices that focus on growth, income, and liquidity strategies, as applicable. Investments in common/collective trust funds are stated at the NAV as determined by the issuer of the common/collective trust funds and are based on the fair value of the underlying investments held by the fund less its liabilities. The NAV is used as a practical expedient to estimate fair value. The common/collective trust funds do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held. The majority of the common/collective trust funds have limited withdrawal or redemption rights during the term of the investment.

• Alternative Investments—Investments in real estate funds, private equity funds, debt funds and hedge funds are stated at fair value based on the NAV of the Plan’s proportionate share of the partnership, joint venture or other alternative investment’s fair value as determined by reference to audited financial statements or NAV statements provided by the investment manager. The NAV is used as a practical expedient to estimate fair value.

NET PERIODIC BENEFIT (CREDIT) COST

The service cost component and non-service cost components of net periodic benefit (credit) cost are reflected in other operations and maintenance expense and other income, respectively, in the Consolidated Statements of Income. The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans are as follows:

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2018			2017			2016			2018			2017			2016
(millions, except percentages)
Dominion Energy
Service cost	$	157		$	138		$	118		$	27		$	26		$	31
Interest cost		337			345			317			56			60			65
Expected return on plan assets		(663	)		(639	)		(573	)		(143	)		(128	)		(118	)
Amortization of prior service (credit) cost		1			1			1			(52	)		(51	)		(35	)
Amortization of net actuarial loss		193			162			111			11			13			8
Settlements and curtailments		—			—			1			—			—			—
Net periodic benefit (credit) cost	$	25		$	7		$	(25	)	$	(101	)	$	(80	)	$	(49	)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	490		$	142		$	931		$	78		$	12		$	178
Prior service (credit) cost		—			5			—			(4	)		(73	)		(216	)
Settlements and curtailments		—			1			(1	)		—			2			—
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss		(193	)		(162	)		(111	)		(11	)		(13	)		(8	)
Amortization of prior service credit (cost)		(1	)		(1	)		(1	)		52			51			35
Total recognized in other comprehensive income and regulatory assets and liabilities	$	296		$	(15	)	$	818		$	115		$	(21	)	$	(11	)
Significant assumptions used to determine periodic cost:
Discount rate		3.80%-3.8	1%		3.31%-4.5	0%		2.87%-4.9	9%		3.76%			3.92%-4.4	7%		3.56%-4.9	4%
Expected long-term rate of return on plan assets		8.75	%		8.75	%		8.75	%		8.50	%		8.50	%		8.50	%
Weighted average rate of increase for compensation		4.09	%		4.09	%		4.22	%		3.95%-4.1	1%		3.29	%		4.22	%
Healthcare cost trend rate(1)											7.00	%		7.00	%		7.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(1)											5.00	%		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate(1)(2)											2022			2021			2020
Dominion Energy Gas
Service cost	$	18		$	15		$	13		$	4		$	4		$	5
Interest cost		29			30			30			11			12			14
Expected return on plan assets		(150	)		(141	)		(134	)		(28	)		(24	)		(23	)
Amortization of prior service (credit) cost		—			—			—			(4	)		(3	)		1
Amortization of net actuarial loss		19			16			13			3			2			1
Net periodic benefit (credit) cost	$	(84	)	$	(80	)	$	(78	)	$	(14	)	$	(9	)	$	(2	)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	207		$	(75	)	$	91		$	16		$	18		$	28
Prior service cost		—			—			—			(4	)		(61	)		—
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss		(19	)		(16	)		(13	)		(3	)		(2	)		(1	)
Amortization of prior service credit (cost)		—			—			—			4			3			(1	)
Total recognized in other comprehensive income and regulatory assets and liabilities	$	188		$	(91	)	$	78		$	13		$	(42	)	$	26
Significant assumptions used to determine periodic cost:
Discount rate		3.81	%		4.50	%		4.99	%		3.81	%		4.47	%		4.93	%
Expected long-term rate of return on plan assets		8.75	%		8.75	%		8.75	%		8.50	%		8.50	%		8.50	%
Weighted average rate of increase for compensation		4.11	%		4.11	%		3.93	%		4.55	%		4.11	%		3.93	%
Healthcare cost trend rate(1)											7.00	%		7.00	%		7.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(1)											5.00	%		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate(1)											2022			2021			2020

(1) Assumptions used to determine net periodic cost for the following year.

(2) The Society of Actuaries model used to determine healthcare cost trend rates was updated in 2014. The new model converges to the ultimate trend rate much more quickly than previous models.

The components of AOCI and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans that have not been recognized as components of net periodic benefit (credit) cost are as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2018		2017		2018			2017
(millions)
Dominion Energy
Net actuarial loss	$	3,477	$	3,181	$	350		$	283
Prior service (credit) cost		7		8		(393	)		(440	)
Total(1)	$	3,484	$	3,189	$	(43	)	$	(157	)
Dominion Energy Gas
Net actuarial loss	$	555	$	367	$	89		$	76
Prior service (credit) cost		—		—		(52	)		(52	)
Total(2)	$	555	$	367	$	37		$	24

(1) As of December 31, 2018, of the $3.5 billion and $(43) million related to pension benefits and other postretirement benefits, $2.0 billion and $(41) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2017, of the $3.2 billion and $(157) million related to pension benefits and other postretirement benefits, $1.9 billion and $(87) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.

(2) As of December 31, 2018, of the $555 million related to pension benefits, $200 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $37 million related to other postretirement benefits is included entirely in regulatory assets and liabilities. As of December 31, 2017, of the $367 million related to pension benefits, $134 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $24 million related to other postretirement benefits is included entirely in regulatory assets and liabilities.

The following table provides the components of AOCI and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans as of December 31, 2018 that are expected to be amortized as components of net periodic benefit (credit) cost in 2019:

	Pension Benefits		Other Postretirement Benefits
(millions)
Dominion Energy
Net actuarial loss		$155	$	18
Prior service (credit) cost		1		(52)
Dominion Energy Gas
Net actuarial loss		$  19	$	4
Prior service (credit) cost		—		(4	)

The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality are critical assumptions in determining net periodic benefit (credit) cost. Dominion Energy develops non-investment related assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions used for Dominion Energy’s pension and other postretirement plans, including those in which Dominion Energy Gas participates, including discount rates, expected long-term rates of return, healthcare cost trend rates and mortality rates.

Dominion Energy determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans, including those in which Dominion Energy Gas participates, by using a combination of:

• Expected inflation and risk-free interest rate assumptions;

• Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;

• Expected future risk premiums, asset classes’ volatilities and correlations;

• Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and

• Investment allocation of plan assets.

Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans, including those in which Dominion Energy Gas participates.

Mortality rates are developed from actual and projected plan experience for postretirement benefit plans. Dominion Energy’s actuary conducts an experience study periodically as part of the process to select its best estimate of mortality. Dominion Energy considers both standard mortality tables and improvement factors as well as the plans’ actual experience when selecting a best estimate. During 2016, Dominion Energy conducted a new experience study as scheduled and, as a result, updated its mortality assumptions for all its plans, including those in which Dominion Energy Gas participates.

Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion Energy’s retiree healthcare plans, including those in which Dominion Energy Gas participates. A one percentage point change in assumed healthcare cost trend rates would have had the following effects for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) other postretirement benefit plans:

	Other Postretirement Benefits
	One percentage point increase		One percentage point decrease
(millions)
Dominion Energy
Effect on net periodic cost for 2019		$  20		$  (16)
Effect on other postretirement benefit obligation at December 31, 2018		130		(110)
Dominion Energy Gas
Effect on net periodic cost for 2019		$    4		$    (3)
Effect on other postretirement benefit obligation at December 31, 2018		25		(22)

Dominion Energy Gas (Employees Not Represented by Collective Bargaining Units) and Virginia Power—Participation in Defined Benefit Plans

Virginia Power employees and Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Pension Plan described above. As participating employers, Virginia Power and Dominion Energy Gas are subject to Dominion Energy’s funding policy, which is to contribute annually an amount that is in accordance with ERISA. During 2018, Virginia Power and Dominion Energy Gas made no contributions to the Dominion Energy Pension Plan, and no contributions to this plan are currently expected in 2019. Virginia Power’s net periodic pension cost related to this plan was $126 million, $110 million and $79 million in 2018, 2017 and 2016, respectively. Dominion Energy Gas’ net periodic pension credit related to this plan was $(38) million, $(37) million and $(45) million in 2018, 2017 and 2016, respectively. Net periodic pension (credit) cost is reflected in other operations and maintenance expense in their respective Consolidated Statements of Income. The funded status of various Dominion Energy subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating Dominion Energy subsidiaries. See Note 24 for Virginia Power and Dominion Energy Gas amounts due to/from Dominion Energy related to this plan.

Retiree healthcare and life insurance benefits, for Virginia Power employees and for Dominion Energy Gas employees not represented by collective bargaining units, are covered by the Dominion Energy Retiree Health and Welfare Plan described above. Virginia Power’s net periodic benefit (credit) cost related to this plan was $(51) million, $(42) million and $(29) million in 2018, 2017 and 2016, respectively. Dominion Energy Gas’ net periodic benefit (credit) cost related to this plan was $(7) million, $(5) million and $(4) million for 2018, 2017 and 2016, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expenses in their respective Consolidated Statements of Income. Employee headcount is the basis for determining the share of total other postretirement benefit costs for participating Dominion Energy subsidiaries. See Note 24 for Virginia Power and Dominion Energy Gas amounts due to/from Dominion Energy related to this plan.

Dominion Energy holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power and Dominion Energy Gas’ employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power and Dominion Energy Gas will provide to Dominion Energy for their shares of employee benefit plan contributions.

Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, Virginia Power and Dominion Energy Gas fund other postretirement benefit costs through VEBAs. During 2018 and 2017, Virginia Power made no contributions to the VEBA and does not expect to contribute to the VEBA in 2019. Dominion Energy Gas made no contributions to the VEBAs for employees not represented by collective bargaining units during 2018 and 2017 and does not expect to contribute in 2019.

Defined Contribution Plans

Dominion Energy also sponsors defined contribution employee savings plans that cover substantially all employees. During 2018, 2017 and 2016, Dominion Energy recognized $51 million, $45 million and $44 million, respectively, as employer matching contributions to these plans. Dominion Energy Gas participates in these employee savings plans, both specific to Dominion Energy Gas and that cover multiple Dominion Energy subsidiaries. During 2018, 2017 and 2016, Dominion Energy Gas recognized $8 million, $7 million and $7 million, respectively, as employer matching contributions to these plans. Virginia Power also participates in these employee savings plans. During 2018, 2017 and 2016, Virginia Power recognized $20 million, $19 million and $19 million, respectively, as employer matching contributions to these plans.

Organizational Design Initiative

In the first quarter of 2016, the Companies announced an organizational design initiative that reduced 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. For the year ended December 31, 2016, Dominion Energy 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 Energy 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.

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

NOTE 22. 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 that the Companies cannot estimate, 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 that 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 Companies’ financial position, liquidity or results of operations.

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

The MATS rule requires coal- and oil-fired electric utility steam generating units to meet strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. Virginia Power ceased operating the coal units at Yorktown power station in April 2017 to comply with the rule.

In June 2017, the DOE issued an order to PJM to direct Virginia Power to operate Yorktown power station’s Units 1 and 2 as needed to avoid reliability issues on the Virginia Peninsula. The order was effective for 90 days and can be reissued upon PJM’s request, if necessary, until required electricity transmission upgrades are completed. Beginning in August 2017, PJM filed requests for 90-day renewals of the DOE order which the DOE has granted. The current renewal is effective until March 2019. The Sierra Club has challenged the DOE order and certain renewal requests, all of which have been denied by the DOE.

In December 2018, the EPA issued a proposed rule to reverse its previous finding that it is appropriate and necessary to regulate toxic emissions from power plants. However, the emissions standards and other requirements of the MATS rule would remain in place as the EPA is not proposing to remove coal and oil fired power plants from the list of sources that are regulated under MATS. Although litigation of the MATS rule and the outcome of the EPA’s rulemaking are still pending, the regulation remains in effect and Virginia Power is complying with the applicable requirements of the rule and does not expect any adverse impacts to its operations at this time.

Ozone Standards

In October 2015, the EPA issued a final rule tightening the ozone standard from 75-ppb to 70-ppb. To comply with this standard, in April 2016 Virginia Power submitted the NO_X Reasonable Available Control Technology analysis for Unit 5 at Possum Point power station. In December 2016, the VDEQ determined that NO_X reductions are required on Unit 5. In October 2017, Virginia Power proposed to install NO_X controls by mid-2019 with an expected cost in the range of $25 million to $35 million. In April 2018, Virginia Power submitted an application with the VDEQ containing an alternative plan for compliance in lieu of installing NO_X controls on Unit 5 at Possum Point. The alter-native plan includes operating restrictions during the ozone season through 2021 while allowing for continued operation to meet PJM capacity commitments and calls for the permanent retirement of the unit by 2021. In January 2019, the VDEQ issued a state operating permit that requires either the installation and operation of selective non-catalytic NO_X reduction technology by June 2019 or for Virginia Power to enter into an agreement with the VDEQ by June 2019 committing to retiring the unit by June 2021 with ozone season operating restrictions in the interim. In addition, Virginia Power placed two natural gas-fired units at the facility into cold reserve in December 2018. Virginia Power is currently evaluating its options. Dominion Energy and Virginia Power are unable to estimate the expenditures associated with this matter, however, they could be material to Dominion Energy and Virginia Power’s results of operations, financial condition and/or cash flows.

The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018. States have until August 2021 to develop plans to address the new standard. Until the states have developed implementation plans for the standard, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact on the Companies’ results of operations and cash flows.

NO_x and VOC Emissions

In April 2016, the Pennsylvania Department of Environmental Protection issued final regulations, with an effective date of January 2017, to reduce NO_X and VOC emissions from combustion sources. To comply with the regulations, Dominion Energy Gas installed emission control systems on existing engines at several compressor stations in Pennsylvania, which was completed in December 2018. The compliance costs associated with engineering and installation of controls and compliance demonstration with the regulation was approximately $35 million.

Oil and Gas NSPS

In August 2012, the EPA issued an 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 June 2016, the EPA issued a new NSPS regulation, 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. All projects which commenced construction after September 2015 are required to comply with this regulation. In October 2018, the EPA published a proposed rule reconsidering and amending portions of the 2016 rule, including but not limited to, the fugitive emissions requirements at well sites and compressor stations. Until the proposed rule is final, Dominion Energy and Dominion Energy Gas are implementing the 2016 regulation. Dominion Energy and Dominion Energy Gas are still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.

GHG REGULATION

Carbon Regulations

In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and to set a significant emissions rate at 75,000 tons per year of CO₂ equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, the Companies cannot predict the impact to their financial statements.

In addition, the EPA continues to evaluate its policy regarding 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. It is unclear how the final policy will affect Virginia Power’s Altavista, Hopewell and Southampton power stations which were converted from coal to biomass under the prior biomass deferral policy; however, the expenditures to comply with any new requirements could be material to Dominion Energy and Virginia Power’s financial statements.

Methane Emissions

In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR Program, the Natural Gas STAR Methane Challenge Program. The 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, East Ohio, Hope, DETI and Questar Gas joined the EPA as founding partners in the new Methane Challenge program and submitted implementation plans in September 2016. Wexpro, DECG and Dominion Energy Questar Pipeline joined the Methane Challenge in 2018. DECG joined the EPA’s voluntary Natural Gas STAR Program in July 2016 and submitted an implementation plan in September 2016 with Questar Gas and Dominion Energy Questar Pipeline joining in 2018. Dominion Energy and Dominion Energy Gas do not expect the costs related to these programs to have a material impact on their results of operations, financial condition and/or cash flows.

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 Energy and Virginia Power have 13 and 11 facilities, respectively, that may be subject to the final regulations. Nine units at Virginia Power’s facilities that are subject to regulations under Section 316(b) of the CWA have been or will be placed into cold reserve. While in cold reserve, applicable requirements under Section 316(b) of the CWA continue to apply to these units. Dominion Energy anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion Energy 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 Energy 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. In April 2017, the EPA granted two separate petitions for reconsideration of the Effluent Limitations Guidelines final rule and stayed future compliance dates in the rule. Also in April 2017, the U.S. Court of Appeals for the Fifth Circuit granted the U.S.’s request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. In September 2017, the EPA signed a rule to postpone the earliest compliance dates for certain waste streams regulations in the Effluent Limitations Guidelines final rule from November 2018 to November 2020; however, the latest date for compliance for these regulations remains December 2023. The EPA is proposing to complete new rulemaking for these waste streams. While the impacts of this rule could be material to Dominion Energy and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for Dominion Energy and Virginia Power.

WASTE MANAGEMENT AND REMEDIATION

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

From time to time, Dominion Energy, Virginia Power, or Dominion Energy 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. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion Energy, Virginia Power, or Dominion Energy Gas may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. The Companies do not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.

Dominion Energy has determined that it is associated with 22 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of which pertain to Dominion Energy 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 Energy is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. In addition, a Virginia Power site has been accepted into a state-based voluntary remediation program. In June 2018, Virginia Power submitted a proposed remedial action plan to remove material from this site at an estimated cost of $18 million. Pending VDEQ approval, Virginia Power expects to begin remedial work at this site in mid-2019. As a result, in June 2018, Virginia recorded a charge of $16 million ($12 million after-tax) in other operations and maintenance expense in the Consolidated Statements of Income. The four sites Dominion Energy acquired in the SCANA Combination associated with SCE&G are in various states of investigation, remediation and monitoring under work plans approved by, or under review by, the SCDHEC or the EPA. Dominion Energy anticipates that activities at these sites will continue through 2020 at an estimated cost of $10 million. In September 2018, SCE&G submitted an updated remediation work plan at one site to SCDHEC, which if approved, would increase costs by approximately $8 million. SCE&G expects to recover costs arising from the remediation work at all four sites through rate recovery mechanisms. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.

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

Other Legal Matters

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

APPALACHIAN GATEWAY

Pipeline Contractor Litigation

Following the completion of the Appalachian Gateway project in 2012, DETI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2015, the contractor filed a complaint against DETI in U.S. District Court for the Western District of Pennsylvania. In March 2016, the Pennsylvania court granted DETI’s motion to transfer the case to the U.S. District Court for the Eastern District of Virginia. In July 2016, DETI filed a motion to dismiss. In March 2017, the court dismissed three of eight counts in the complaint. In May 2017, the contractor withdrew one of the counts in the complaint. In November 2017, DETI and the contractor entered into a partial settlement agreement for a release of certain claims. In August 2018, DETI paid $14 million in accordance with the terms of a settlement agreement reached between the parties, resolving this matter.

Gas Producers Litigation

In connection with the Appalachian Gateway project, Dominion Energy Field Services, Inc. entered into contracts for firm purchase rights with a group of small gas producers. In June 2016, the gas producers filed a complaint in the Circuit Court of Marshall County, West Virginia against Dominion Energy, DETI and Dominion Energy Field Services, Inc., among other defendants, claiming that the contracts are unenforceable and seeking compensatory and punitive damages. During the third quarter of 2016, Dominion Energy, DETI and Dominion Energy Field Services, Inc. were served with the complaint. Also in the third quarter of 2016, Dominion Energy and DETI, with the consent of the other defendants, removed the case to the U.S. District Court for the Northern District of West Virginia. In October 2016, the defendants filed a motion to dismiss and the plaintiffs filed a motion to remand. In February 2017, the U.S. District Court entered an order remanding the matter to the Circuit Court of Marshall County, West Virginia. In March 2017, Dominion Energy was voluntarily dismissed from the case; however, DETI and Dominion Energy Field Services, Inc. remain parties to the matter. In April 2017, the case was transferred to the Business Court Division of West Virginia. In January 2018, the court granted the motion to dismiss filed by the defendants on two counts. Claims are pending in the Business Court Division of West Virginia. Dominion Energy and Dominion Energy Gas cannot currently estimate financial statement impacts, but there could be a material impact to their financial condition and/or cash flows.

ASH POND AND LANDFILL CLOSURE COSTS

In March 2015, the Sierra Club filed a lawsuit alleging CWA violations at Chesapeake power station. In March 2017, the U.S. District Court for the Eastern District of Virginia ruled that impacted groundwater associated with the on-site coal ash storage units was migrating to adjacent surface water, which constituted an unpermitted point source discharge in violation of the CWA. The court, however, rejected Sierra Club’s claims that Virginia Power had violated specific conditions of its water discharge permit. Finding no harm to the environment, the court further declined to impose civil penalties or require excavation of the ash from the site as Sierra Club had sought. In July 2017, the court issued a final order requiring Virginia Power to perform additional specific sediment, water and aquatic life monitoring at and around the Chesapeake power station for a period of at least two years. The court further directed Virginia Power to apply for a solid waste permit from VDEQ that includes corrective measures to address on-site groundwater impacts. In July 2017, Virginia Power appealed the court’s July 2017 final order to the U.S. Court of Appeals for the Fourth Circuit. In August 2017, the Sierra Club filed a cross appeal. In September 2018, the U.S. Court of Appeals for the Fourth Circuit ruled that impacted groundwater associated with coal ash storage at the Chesapeake power station did not constitute point source pollution in violation of the CWA or the station’s water discharge permit. The Sierra Club subsequently filed a petition for rehearing with the U.S. Court of Appeals for the Fourth Circuit, which was denied.

In April 2015, the EPA enacted a final rule regulating CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store, CCRs. Dominion Energy currently operates inactive ash ponds, existing ash ponds and CCR landfills subject to the final rule at 11 different facilities, eight of which are at Virginia Power. This rule created a legal obligation for Dominion Energy and 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 2015, Virginia Power recorded a $386 million ARO related to future ash pond and landfill closure costs. In 2016, Virginia Power recorded an increase to this ARO of $238 million, which resulted in a $197 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $17 million increase in property, plant and equipment and a $24 million increase in regulatory assets.

In December 2016, legislation was enacted that creates a framework for EPA- approved state CCR permit programs. In August 2017, the EPA issued interim guidance outlining the framework for state CCR program approval. The EPA has enforcement authority until state programs are approved. The EPA and states with approved programs both will have authority to enforce CCR requirements under their respective rules and programs. In September 2017, the EPA agreed to reconsider portions of the CCR rule in response to two petitions for reconsideration. In March 2018, the EPA proposed certain changes to the CCR rule related to issues remanded as part of the pending litigation and other issues the EPA is reconsidering. Several of the proposed changes would allow states with approved CCR permit programs additional flexibilities in implementing their programs. In July 2018, the EPA promulgated the first phase of changes to the CCR rule. Until all phases of the CCR rule are promulgated, Dominion Energy and Virginia Power cannot forecast potential incremental impacts or costs related to existing coal ash sites in connection with future implementation of the 2016 CCR legislation and reconsideration of the CCR rule. In August 2018, the U.S. Court of Appeals for the D.C. Circuit issued its decision in the pending challenges of the CCR rule, vacating and remanding to the EPA three provisions of the rule. Dominion Energy and Virginia Power do not expect the scope of the U.S. Court of Appeals for the D.C. Circuit’s decision to impact their closure plans, but cannot forecast incremental impacts associated with any future changes to the CCR rule in connection with the court’s remand.

In April 2017, the Governor of Virginia signed legislation into law that places a moratorium on the VDEQ issuing solid waste permits for closure of ash ponds at Virginia Power’s Bremo, Chesapeake, Chesterfield and Possum Point power stations until May 2018. The law also required Virginia Power to conduct an assessment of closure alternatives for the ash ponds at these four stations, to include an evaluation of excavation for recycling or off-site disposal, surface and groundwater conditions and safety. Virginia Power completed the assessments and provided the report on December 1, 2017. In April 2018, the Governor of Virginia signed legislation into law extending the existing permit moratorium until July 2019. The legislation also requires Virginia Power to solicit and compile by November 2018, information from third parties on the suitability, cost and market demand for beneficiation or recycling of coal ash from these units. The coal ash recycling business plan was submitted to the legislature in November 2018. The extended moratorium does not apply to a permit required for an impoundment where CCRs have already been removed and placed in another impoundment on-site, are being removed from an impoundment, or are being processed in connection with a recycling or beneficial use project. In connection with this legislation, in the second quarter of 2018 Virginia Power recorded an increase to its ARO and a related environmental liability related to future ash pond and landfill closure costs of $131 million, which resulted in an $81 million ($60 million after-tax) charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $46 million increase in property, plant and equipment associated with asset retirement costs and a $4 million increase in regulatory assets. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the obligation.

COVE POINT

In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project at the Cove Point facility, which enables the facility to liquefy domestically-produced natural gas and export it as LNG. In March 2018, Cove Point received authorization from FERC to commence service of the Liquefaction Project, which commenced commercial operations in April 2018.

Two parties have separately filed petitions for review of the FERC order in the U.S. Court of Appeals for the D.C. Circuit, which petitions were consolidated. 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. In September 2017, FERC issued its order on remand from the U.S. Court of Appeals for the D.C. Circuit, and reaffirmed its ruling in its prior orders that Cove Point did not violate the prohibition against undue discrimination by agreeing to a capacity reduction and early contract termination with the existing import shipper. In October 2017, the party filed a request for rehearing of the FERC order on remand. In August 2018, FERC issued its rehearing order affirming and clarifying its previous orders. No appeals were filed and FERC’s orders are final and no longer subject to further review.

FERC

FERC staff in the Office of Enforcement, Division of Investigations, conducted a non-public investigation of Virginia Power’s offers of combustion turbines generators into the PJM day-ahead markets from April 2010 through September 2014. FERC staff notified Virginia Power of its preliminary findings relating to Virginia Power’s alleged violation of FERC’s rules in connection with these activities. Virginia Power provided its response to FERC staff’s preliminary findings letter explaining why Virginia Power’s conduct was lawful and refuting any allegation of wrongdoing. This matter is pending. Virginia Power has recorded a liability of $14 million in its Consolidated Balance Sheet at December 31, 2018.

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 U.S. nuclear operators, Dominion Energy 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 Energy requiring implementation of safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation have been implemented. The information requests issued by the NRC request each reactor to reevaluate the seismic and external flooding hazards at their site using present-day methods and information, conduct walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. The walkdowns of each unit have been completed, audited by the NRC and found to be adequate. Reevaluation of the emergency communications systems and staffing levels was completed as part of the effort to comply with the orders. Reevalua-tion of the seismic hazards was completed or in review with the NRC in 2018. Reevaluation of the external flooding hazards is expected to continue through 2019. Dominion Energy 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 Energy and Virginia Power do not expect material financial impacts related to compliance with Tier 2 and Tier 3 recommendations.

Nuclear Operations

NUCLEAR DECOMMISSIONING—MINIMUM FINANCIAL ASSURANCE

The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 2018 calculation for the NRC minimum financial assurance amount, aggregated for Dominion Energy and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.7 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 2018 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2018 U.S. Bureau of Labor Statistics indices. Dominion Energy believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. Dominion Energy and Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. See Note 9 for additional information on nuclear decommissioning trust investments.

NUCLEAR INSURANCE

The Price-Anderson Amendments Act of 1988 provides the public with liability protection on a per site, per nuclear incident basis, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. During the second quarter of 2018, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program decreased from $13.4 billion to $13.1 billion. During the fourth quarter of 2018, this amount increased from $13.1 billion to $14.1 billion. Dominion Energy and Virginia Power have purchased $450 million of coverage from commercial insurance pools for Millstone, Surry and North Anna with the remainder provided through the mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., Dominion Energy and Virginia Power could be assessed up to $138 million for each of their licensed reactors not to exceed $21 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. The NRC granted an exemption in March 2015 to remove Kewaunee from the Secondary Financial Protection program. This same exemption permitted Dominion Energy to reduce Kewaunee’s required level of liability coverage to $100 million. This reduction was implemented in January 2018, following the removal and storage of the spent nuclear fuel from the spent fuel pool. The current levels of nuclear property insurance coverage for Dominion Energy and Virginia Power’s nuclear units are as follows:

	Coverage
(billions)
Dominion Energy
Millstone	$	1.70
Kewaunee		0.05
Virginia Power(1)
Surry	$	1.70
North Anna		1.70

(1) Surry and North Anna share a blanket property limit of $200 million.

Dominion Energy and Virginia Power’s nuclear property insurance coverage for Millstone, Surry and North Anna exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site. In March 2015, the NRC granted an exemption which allowed Kewaunee to reduce its property insurance limit to $50 million. This reduction was implemented in January 2018, following the removal and storage of the spent nuclear fuel from the spent fuel pool. This includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion Energy and Virginia Power’s maximum retrospective premium assessment for the current policy period is $83 million and $51 million, respectively. Based on the severity of the incident, the Board of Directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion Energy and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

Millstone and Virginia Power also purchase accidental outage insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, Dominion Energy and Virginia Power are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion Energy and Virginia Power’s maximum retrospective premium assessment for the current policy period is $21 million and $10 million, respectively.

ODEC, a part owner of North Anna, and Massachusetts Municipal and Green Mountain, part owners of Millstone’s Unit 3, are responsible to Dominion Energy and Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.

SPENT NUCLEAR FUEL

Dominion Energy and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by Dominion Energy and Virginia Power’s contracts with the DOE. Dominion Energy and Virginia Power have previously received damages award payments and settlement payments related to these contracts.

By mutual agreement of the parties, the settlement agreements are extendable to provide for resolution of damages incurred after 2013. The settlement agreements for the Surry, North Anna and Millstone nuclear power stations have been extended to provide for periodic payments for damages incurred through December 31, 2019. In June 2018, a lawsuit for Kewaunee was filed in the U.S. Court of Federal Claims for recovery of spent nuclear fuel storage costs incurred for the period January 1, 2014 through December 31, 2017. This matter is pending.

In 2018, Virginia Power and Dominion Energy received payments of $16 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2016 through December 31, 2016, and $13 million for resolution of claims incurred at Millstone for the period of July 1, 2016 through June 30, 2017.

In 2017, Virginia Power and Dominion Energy received payments of $22 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2015 through December 31, 2015, and $14 million for resolution of claims incurred at Millstone for the period of July 1, 2015 through June 30, 2016.

In 2016, Virginia Power and Dominion Energy received payments of $30 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2014 through December 31, 2014, and $22 million for resolution of claims incurred at Millstone for the period of July 1, 2014 through June 30, 2015.

Dominion Energy and Virginia Power continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion Energy’s receivables for spent nuclear fuel-related costs totaled $49 million and $46 million at December 31, 2018 and 2017, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $30 million at both December 31, 2018 and 2017.

Dominion Energy and Virginia Power will continue to manage their spent fuel until it is accepted by the DOE.

Long-Term Purchase Agreements

At December 31, 2018, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that a third party has used to secure financing for the facility that will provide the contracted goods or services:

	2019			2020			2021			2022			2023			Thereafter			Total
(millions)
Purchased electric capacity(1)		$	60		$	52		$	46		$	—		$	—		$	—		$	158

(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with independent power producers, which end in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad based economic indices. At December 31, 2018, the present value of Virginia Power’s total commitment for capacity payments is $142 million. Capacity payments totaled $50 million, $114 million and $248 million, and energy payments totaled $42 million, $72 million and $126 million for the years ended 2018, 2017 and 2016, respectively.

Lease Commitments

The Companies lease real estate, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating leases that have initial or remaining lease terms in excess of one year as of December 31, 2018 are as follows:

	2019			2020			2021			2022			2023			Thereafter			Total
(millions)
Dominion Energy		$	64		$	61		$	55		$	47		$	38		$	384		$	649
Virginia Power			34			32			28			22			16			106			238
Dominion Energy Gas			12			11			9			7			4			3			46

Rental expense for Dominion Energy totaled $109 million, $113 million, and $104 million for 2018, 2017 and 2016, respectively. Rental expense for Virginia Power totaled $63 million, $57 million, and $52 million for 2018, 2017 and 2016, respectively. Rental expense for Dominion Energy Gas totaled $22 million, $34 million, and $37 million for 2018, 2017 and 2016, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.

In July 2016, Dominion Energy 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, totaling $365 million, to fund the estimated project costs. The project is expected to be completed by mid-2019. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $281 million as of December 31, 2018. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 89.9% of the then funded amount. For specific full recourse events, Dominion Energy 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 Energy 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 on behalf of the lessor 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 Energy 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.

Guarantees, Surety Bonds and Letters of Credit

In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility, also entered in October 2017, with a stated maturity date of October 2021. Dominion Energy’s maximum potential loss exposure under the terms of the guarantee is limited to 48% of the outstanding borrowings under the revolving credit facility, an equal percentage to Dominion Energy’s ownership in Atlantic Coast Pipeline. As of December 31, 2018, Atlantic Coast Pipeline has borrowed $1.4 billion against the revolving credit facility and borrowed an additional $113 million in January and February 2019. Dominion Energy’s Consolidated Balance Sheet includes a liability of $21 million and $28 million associated with this guarantee agreement at December 31, 2018 and 2017, respectively.

In addition, at December 31, 2018, Dominion Energy had issued an additional $48 million of guarantees, primarily to support other equity method investees. No amounts related to the other guarantees have been recorded.

Dominion Energy also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion Energy would be obligated to satisfy such obligation. To the extent that a liability subject to a guarantee has been incurred by one of Dominion Energy’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion Energy 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 Energy 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 December 31, 2018, Dominion Energy had issued the following subsidiary guarantees:

	Maximum Exposure
(millions)
Commodity transactions(1)		$	2,186
Nuclear obligations(2)			179
Cove Point(3)			1,900
Solar(4)			659
Other(5)			420
Total(6)		$	5,344

(1) Guarantees related to commodity commitments of certain subsidiaries. These guarantees were provided to counterparties in order to facilitate physical and financial transaction related commodities and services.

(2) Guarantees related to certain DGI subsidiaries’ regarding all aspects of running a nuclear facility.

(3) Guarantees related to Cove Point, in support of terminal services, transportation and construction. Cove Point has two guarantees that have no maximum limit and, therefore, are not included in this amount.

(4) Includes guarantees to facilitate the development of solar projects. Also includes guarantees entered into by DGI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.

(5) Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations, construction projects and insurance programs. Due to the uncertainty of worker’s compensation claims, the parental guarantee has no stated limit. Also included are guarantees related to certain DGI subsidiaries’ obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of December 31, 2018, Dominion Energy’s maximum remaining cumulative exposure under these equity funding agreements is $4 million through 2019 and its maximum annual future contribution is approximately $4 million.

(6) Excludes Dominion Energy’s guarantee for the construction of the new corporate office property discussed further within Lease Commitments above.

Additionally, at December 31, 2018, Dominion Energy had purchased $171 million of surety bonds, including $72 million at Virginia Power and $26 million at Dominion Energy Gas, and authorized the issuance of letters of credit by financial institutions of $88 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.

Indemnifications

As part of commercial contract negotiations in the normal course of business, the Companies may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Companies are unable to develop an estimate of the maximum potential amount of any other future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2018, the Companies believe any other future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.

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Credit Risk

12 Months Ended

Dec. 31, 2018

Risks and Uncertainties [Abstract]

Credit Risk

NOTE 23. CREDIT RISK

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

The Companies maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Management believes, based on credit policies and the December 31, 2018 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

General

DOMINION ENERGY

As a diversified energy company, Dominion Energy transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic, Midwest and Rocky Mountain and Southeast regions of the U.S. Dominion Energy does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.

Dominion Energy’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion Energy transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of any collateral. At December 31, 2018, Dominion Energy’s credit exposure totaled $145 million. Of this amount, investment grade counterparties, including those internally rated, represented 69%, and no single counterparty, whether investment grade or non-investment grade, exceeded $47 million of exposure.

VIRGINIA POWER

Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2018, Virginia Power’s credit exposure totaled $10 million, of which no amounts were investment grade counterparties, and no single counterparty exceeded $9 million of exposure.

DOMINION ENERGY GAS

Dominion Energy Gas transacts mainly with major companies in the energy industry and with residential and commercial energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. Dominion Energy Gas does not believe that this geographic concentration contributes to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy Gas is not exposed to a significant concentration of credit risk for receivables arising from gas utility operations. Dominion Energy Gas’ gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2018, Dominion Energy Gas’ credit exposure totaled $8 million. Of this amount, investment grade counterparties, including those internally rated, represented 93%, and no single counterparty, whether investment grade or non-investment grade, exceeded $5 million of exposure.

In 2018, DETI provided service to 307 customers with approximately 96% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 38% of the total storage and transportation revenue and the thirty largest provided approximately 71% of the total storage and transportation revenue.

East Ohio distributes natural gas to residential, commercial and industrial customers in Ohio using rates established by the Ohio Commission. Approximately 99% of East Ohio revenues are derived from its regulated gas distribution services. East Ohio’s bad debt risk is mitigated by the regulatory framework established by the Ohio Commission. See Note 13 for further information about Ohio’s PIPP and UEX Riders that mitigate East Ohio’s overall credit risk.

Credit-Related Contingent Provisions

The majority of Dominion Energy’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion Energy 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 December 31, 2018 and 2017, Dominion Energy would have been required to post an additional $1 million and $62 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 Energy had posted no collateral at December 31, 2018 and 2017, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. 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 December 31, 2018 and 2017 was $1 million and $65 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power and Dominion Energy Gas were not material as of December 31, 2018 and 2017. See Note 7 for further information about derivative instruments.

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Related-Party Transactions

12 Months Ended

Dec. 31, 2018

Related Party Transactions [Abstract]

Related-Party Transactions

NOTE 24. RELATED-PARTY TRANSACTIONS

Virginia Power and Dominion Energy Gas engage in related party transactions primarily with other Dominion Energy subsidiaries (affiliates). Virginia Power and Dominion Energy 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 Energy Gas are included in Dominion Energy’s consolidated federal income tax return and, where applicable, combined income tax returns for Dominion Energy are filed in various states. See Note 2 for further information. Dominion Energy’s transactions with equity method investments are described in Note 9. 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 forward commodity purchases, to manage commodity price risks associated with purchases of natural gas. See Notes 7 and 19 for more information. As of December 31, 2018, Virginia Power’s derivative assets and liabilities with affiliates were $26 million and $10 million, respectively. As of December 31, 2017, Virginia Power’s derivative assets and liabilities with affiliates were $11 million and $5 million, respectively.

Virginia Power participates in certain Dominion Energy benefit plans as described in Note 21. At December 31, 2018 and 2017, Virginia Power’s amounts due to Dominion Energy associated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets were $632 million and $505 million, respectively. At December 31, 2018 and 2017, Virginia Power’s amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $254 million and $199 million, respectively.

DES 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.

The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES to Virginia Power on the basis of direct and allocated methods in accordance with Virginia Power’s services agreements with DES. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.

Presented below are significant transactions with DES and other affiliates:

Year Ended December 31,	2018			2017			2016
(millions)
Commodity purchases from affiliates		$	930		$	674		$	571
Services provided by affiliates(1)			450			453			454
Services provided to affiliates			24			25			22

(1) Includes capitalized expenditures of $145 million, $144 million and $144 million for the year ended December 31, 2018, 2017 and 2016, respectively.

Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. There were $224 million and $33 million in short-term demand note borrowings from Dominion Energy as of December 31, 2018 and 2017, respectively. The weighted-average interest rate of these borrowings was 2.94% and 1.65% at December 31, 2018 and 2017, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion Energy money pool for its nonregulated subsidiaries as of December 31, 2018 and 2017. Interest charges related to Virginia Power’s borrowings from Dominion Energy were immaterial for the years ended December 31, 2018, 2017 and 2016.

There were no issuances of Virginia Power’s common stock to Dominion Energy in 2018, 2017 or 2016.

DOMINION ENERGY GAS

Transactions with Related Parties

Dominion Energy Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Energy Gas provides transportation and storage services to affiliates. Dominion Energy Gas also enters into certain other contracts with affiliates, and related parties, including construction services, which are presented separately from contracts involving commodities or services. As of December 31, 2018 and 2017, all of Dominion Energy Gas’ commodity derivatives were with affiliates. See Notes 7 and 19 for more information. See Note 9 for information regarding transactions with an affiliate.

Dominion Energy Gas participates in certain Dominion Energy benefit plans as described in Note 21. At December 31, 2018 and 2017, Dominion Energy Gas’ amounts due from Dominion Energy associated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $772 million and $734 million, respectively. Dominion Energy Gas’ amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $14 million and $7 million at December 31, 2018 and 2017, respectively.

DES and other affiliates provide accounting, legal, finance and certain administrative and technical services to Dominion Energy Gas. Dominion Energy Gas provides certain services to related parties, including technical services.

The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES to Dominion Energy Gas on the basis of direct and allocated methods in accordance with Dominion Energy Gas’ services agreements with DES. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable. The costs of these services follow:

Year Ended December 31,	2018			2017			2016
(millions)
Sales of natural gas and transportation and storage services to affiliates		$	58		$	70		$	69
Purchases of natural gas from affiliates			6			5			9
Services provided by related parties(1)			131			143			141
Services provided to related parties(2)			216			156			128

(1) Includes capitalized expenditures of $37 million, $45 million and $49 million for the year ended December 31, 2018, 2017 and 2016, respectively.

(2) Amounts primarily attributable to Atlantic Coast Pipeline, a related party VIE.

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

At December 31,	2018			2017
(millions)
Other receivables(1)		$	13		$	12
Customer receivables from related parties			1			1
Imbalances receivable from affiliates			1			1
Imbalances payable to affiliates(2)			13			—
Affiliated notes receivable(3)			16			20

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

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

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

Dominion Energy Gas’ borrowings under the IRCA with Dominion Energy totaled $218 million and $18 million as of December 31, 2018 and 2017, respectively. The weighted-average interest rate of these borrowings was 2.78% and 1.60% at December 31, 2018 and 2017, respectively. Interest charges related to Dominion Energy Gas’ total borrowings from Dominion Energy were immaterial for 2018, 2017 and 2016.

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Operating Segments

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

Operating Segments

NOTE 25. OPERATING SEGMENTS

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

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

(1) Includes remaining producer services activities.

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

DOMINION ENERGY

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

In 2018, Dominion Energy reported after-tax net expenses of $608 million in the Corporate and Other segment, with $88 million of the net expenses attributable to specific items related to its operating segments.

The net expenses for specific items in 2018 primarily related to the impact of the following items:

• A $219 million ($164 million after-tax) charge related to the impairment of certain gathering and processing assets attributable to Gas Infrastructure;

• A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers, attributable to:

• Power Generation ($109 million after-tax); and

• Power Delivery ($51 million after-tax);

• A $170 million ($134 million after-tax) net loss related to our investments in nuclear decommissioning trust funds attributable to Power Generation;

• A $124 million ($88 million after-tax) charge for disallowance of FERC-regulated plant attributable to Gas Infrastructure;

• An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Power Generation; and

• A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration attributable to Power Delivery; partially offset by

• An $828 million ($619 million after-tax) benefit associated with the sale of certain merchant generation facilities and equity method investments attributable to:

• Power Generation ($229 million after-tax); and

• Gas Infrastructure ($390 million after-tax).

In 2017, Dominion Energy reported after-tax net benefits of $389 million in the Corporate and Other segment, with $861 million of the net benefits attributable to specific items related to its operating segments.

The net benefits for specific items in 2017 primarily related to the impact of the following items:

• A $979 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, primarily attributable to:

• Gas Infrastructure ($324 million);

• Power Generation ($655 million); partially offset by

• $158 million ($96 million after-tax) of charges associated with equity method investments in wind-powered generation facilities, attributable to Power Generation.

In 2016, Dominion Energy reported after-tax net expenses of $484 million in the Corporate and Other segment, with $180 million of these net expenses attributable to specific items related to its operating segments.

The net expenses for specific items in 2016 primarily related to the impact of the following items:

• A $197 million ($122 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Power Generation; and

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

• Power Delivery ($5 million after-tax);

• Gas Infrastructure ($12 million after-tax); and

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

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

Year Ended December 31,	Power Delivery		Power Generation			Gas Infrastructure			Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2018
Total revenue from external customers	$	2,206	$	7,104		$	4,221		$	(208	)	$	43		$	13,366
Intersegment revenue		23		11			27			674			(735	)		—
Total operating revenue		2,229		7,115			4,248			466			(692	)		13,366
Depreciation, depletion and amortization		625		746			615			14			—			2,000
Impairment of assets and related charges		—		1			8			394			—			403
Gains on sales of assets		—		6			(186	)		(200	)		—			(380	)
Equity in earnings of equity method investees		—		18			178			1			—			197
Interest income		—		90			64			126			(196	)		84
Interest and related charges		265		374			268			782			(196	)		1,493
Income tax expense (benefit)		160		294			330			(204	)		—			580
Net income (loss) attributable to Dominion Energy		587		1,254			1,214			(608	)		—			2,447
Investment in equity method investees		—		82			1,159			37			—			1,278
Capital expenditures		1,564		1,321			1,415			105			—			4,405
Total assets (billions)		17.8		28.2			31.5			11.2			(10.8	)		77.9
2017
Total revenue from external customers	$	2,206	$	6,676		$	2,832		$	16		$	856		$	12,586
Intersegment revenue		22		10			834			610			(1,476	)		—
Total operating revenue		2,228		6,686			3,666			626			(620	)		12,586
Depreciation, depletion and amortization		593		747			522			43			—			1,905
Impairment of assets and related charges		—		—			—			15			—			15
Gains on sales of assets		—		—			(147	)		—			—			(147	)
Equity in earnings of equity method investees		—		(181	)		159			4			—			(18	)
Interest income		4		92			45			96			(155	)		82
Interest and related charges		265		342			109			644			(155	)		1,205
Income tax expense (benefit)		334		373			487			(1,224	)		—			(30	)
Net income (loss) attributable to Dominion Energy		531		1,181			898			389			—			2,999
Investment in equity method investees		—		81			1,422			41			—			1,544
Capital expenditures		1,433		2,275			2,149			52			—			5,909
Total assets (billions)		16.7		29.0			28.0			12.0			(9.1	)		76.6
2016
Total revenue from external customers	$	2,210	$	6,747		$	2,069		$	(7	)	$	718		$	11,737
Intersegment revenue		23		10			697			609			(1,339	)		—
Total operating revenue		2,233		6,757			2,766			602			(621	)		11,737
Depreciation, depletion and amortization		537		662			330			30			—			1,559
Impairment of assets and related charges		—		—			—			4			—			4
Gains on sales of assets		—		4			(44	)		—			—			(40	)
Equity in earnings of equity method investees		—		(16	)		105			22			—			111
Interest income		—		74			34			36			(78	)		66
Interest and related charges		244		290			38			516			(78	)		1,010
Income tax expense (benefit)		308		279			431			(363	)		—			655
Net income (loss) attributable to Dominion Energy		484		1,397			726			(484	)		—			2,123
Capital expenditures		1,320		2,440			2,322			43			—			6,125

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

VIRGINIA POWER

The majority of Virginia Power’s revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia Power’s Power Delivery and Power Generation segments.

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 2018, Virginia Power reported an after-tax net expense of $312 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net expenses for specific items in 2018 primarily related to the impact of the following items:

• A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers, attributable to:

• Power Generation ($109 million after-tax); and

• Power Delivery ($51 million after-tax).

• An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Power Generation.

• A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration attributable to Power Delivery.

In 2017, Virginia Power reported an after-tax net benefit of $74 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net benefit for specific items in 2017 primarily related to the impact of the following item:

• A $93 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, attributable to Power Generation.

In 2016, Virginia Power reported after-tax net expenses of $173 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net expenses for specific items in 2016 primarily related to the impact of the following item:

• A $197 million ($121 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Power Generation.

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

Year Ended December 31,	Power Delivery		Power Generation		Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2018
Operating revenue	$	2,204	$	5,630	$	(215	)	$	—		$	7,619
Depreciation and amortization		624		533		(25	)		—			1,132
Interest income		—		9		5			(4	)		10
Interest and related charges		265		250		—			(4	)		511
Income tax expense (benefit)		158		220		(78	)		—			300
Net income (loss)		586		1,008		(312	)		—			1,282
Capital expenditures		1,539		1,003		—			—			2,542
Total assets (billions)		17.6		19.4		—			(0.1	)		36.9
2017
Operating revenue	$	2,212	$	5,344	$	—		$	—		$	7,556
Depreciation and amortization		594		547		—			—			1,141
Interest income		4		15		3			(3	)		19
Interest and related charges		265		232		—			(3	)		494
Income tax expense (benefit)		334		534		(94	)		—			774
Net income		527		939		74			—			1,540
Capital expenditures		1,439		1,290		—			—			2,729
Total assets (billions)		16.6		18.6		—			(0.1	)		35.1
2016
Operating revenue	$	2,217	$	5,390	$	(19	)	$	—		$	7,588
Depreciation and amortization		537		488		—			—			1,025
Interest income		—		—		—			—			—
Interest and related charges		244		219		—			(2	)		461
Income tax expense (benefit)		307		524		(104	)		—			727
Net income (loss)		482		909		(173	)		—			1,218
Capital expenditures		1,313		1,336		—			—			2,649

DOMINION ENERGY GAS

The Corporate and Other Segment of Dominion Energy Gas primarily includes specific items attributable to Dominion Energy 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 Energy Gas as a result of Dominion Energy’s basis in the net assets contributed.

In 2018, Dominion Energy Gas reported after-tax net expenses of $251 million in its Corporate and Other segment, with $244 million of these net expenses attributable to its operating segment.

The net expenses for specific items in 2018 primarily related to the impact of the following items:

• A $219 million ($165 million after-tax) charge related to the impairment of gathering and processing assets; and

• A $124 million ($88 million after-tax) charge for disallowance of FERC-regulated plant.

In 2017, Dominion Energy Gas reported after-tax net benefit of $179 million in its Corporate and Other segment, with $174 million of these net expenses attributable to its operating segment.

The net benefit for specific items in 2017 primarily related to the impact of the following item:

• A $185 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.

In 2016, Dominion Energy Gas reported after-tax net expenses of $3 million in its Corporate and Other segment, with $7 million of these net expenses attributable to its operating segment.

The net expense for specific items in 2016 primarily related to the impact of the following item:

• An $8 million ($5 million after-tax) charge related to an organizational design initiative.

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

Year Ended December 31,	Gas Infrastructure			Corporate and Other			Consolidated Total
(millions)
2018
Operating revenue	$	1,940		$	—		$	1,940
Depreciation and amortization		244			—			244
Impairment of assets and related charges		5			341			346
Gains on sales of assets		(119	)		—			(119	)
Equity in earnings of equity method investees		24			—			24
Interest income		2			—			2
Interest and related charges		104			1			105
Income tax expense (benefit)		188			(102	)		86
Net income (loss)		552			(251	)		301
Investment in equity method investees		91			—			91
Capital expenditures		772			—			772
Total assets (billions)		11.8			0.6			12.4
2017
Operating revenue	$	1,814		$	—		$	1,814
Depreciation and amortization		227			—			227
Impairment of assets and related charges		15			1			16
Gains on sales of assets		(70	)		—			(70	)
Equity in earnings of equity method investees		21			—			21
Interest income		2			—			2
Interest and related charges		97			—			97
Income tax expense (benefit)		256			(205	)		51
Net income		436			179			615
Investment in equity method investees		95			—			95
Capital expenditures		778			—			778
Total assets (billions)		11.3			0.6			11.9
2016
Operating revenue	$	1,638		$	—		$	1,638
Depreciation and amortization		214			(10	)		204
Gains on sales of assets		(45	)		—			(45	)
Equity in earnings of equity method investees		21			—			21
Interest income		1			—			1
Interest and related charges		92			2			94
Income tax expense (benefit)		237			(22	)		215
Net income (loss)		395			(3	)		392
Capital expenditures		854			—			854

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

NOTE 26. QUARTERLY FINANCIAL DATA (UNAUDITED)

A summary of the Companies’ quarterly results of operations for the years ended December 31, 2018 and 2017 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

DOMINION ENERGY

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(millions)
2018
Operating revenue	$	3,466	$	3,088	$	3,451	$	3,361
Income from operations		875		742		1,150		834
Net income including noncontrolling interests		526		478		883		662
Net income attributable to Dominion Energy		503		449		854		641
Basic EPS:
Net income attributable to Dominion Energy		0.77		0.69		1.31		0.97
Diluted EPS:
Net income attributable to Dominion Energy		0.77		0.69		1.30		0.97
Dividends declared per common share		0.835		0.835		0.835		0.835
2017
Operating revenue	$	3,384	$	2,813	$	3,179	$	3,210
Income from operations		1,079		753		1,152		953
Net income including noncontrolling interests		674		417		696		1,333
Net income attributable to Dominion Energy		632		390		665		1,312
Basic EPS:
Net income attributable to Dominion Energy		1.01		0.62		1.03		2.04
Diluted EPS:
Net income attributable to Dominion Energy		1.01		0.62		1.03		2.04
Dividends declared per common share		0.755		0.755		0.770		0.770

Dominion Energy’s 2018 results include the impact of the following significant items:

• Fourth quarter results include $536 million of after-tax gains from the sale of certain merchant generation facilities and equity method investments partially offset by a $164 million after-tax impairment charge for certain gathering and processing assets.

• Second quarter results include an $89 million after-tax charge for disallowance of FERC-regulated plant.

• First quarter results include a $160 million after-tax charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers.

Dominion Energy’s 2017 results include the impact of the following significant item:

• Fourth quarter results include $851 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, partially offset by $96 million of after-tax charges associated with our equity method investments in wind-powered generation facilities.

VIRGINIA POWER

Virginia Power’s quarterly results of operations were as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(millions)
2018
Operating revenue	$	1,748	$	1,829	$	2,232	$	1,810
Income from operations		364		533		756		418
Net income		184		339		520		239
2017
Operating revenue	$	1,831	$	1,747	$	2,154	$	1,824
Income from operations		653		613		847		619
Net income		356		318		459		407

Virginia Power’s 2018 results include the impact of the following significant item:

• First quarter results include a $160 million after-tax charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers.

Virginia Power’s 2017 results include the impact of the following significant item:

• Fourth quarter results include a $93 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.

DOMINION ENERGY GAS

Dominion Energy Gas’ quarterly results of operations were as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(millions)
2018
Operating revenue		$526		$459		$423		$532
Income (loss) from operations		201		7		182		(55	)
Net income (loss)	166		15		136		(16)
2017
Operating revenue		$490		$422		$401		$501
Income from operations		156		116		185		181
Net income		108		77		117		313

Dominion Energy Gas’s 2018 results include the impact of the following significant items:

• Fourth quarter results include a $165 million after-tax impairment charge for certain gathering and processing assets.

• Second quarter results include an $89 million after-tax charge for disallowance of FERC-regulated plant.

Dominion Energy Gas’s 2017 results include the impact of the following significant item:

• Fourth quarter results include a $197 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Estimates

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

Consolidation

The Companies’ Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries and non-wholly-owned entities in which they have a controlling financial interest.

Consolidation, consolidated entities and noncontrolling interest

For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. At December 31, 2018, Dominion Energy 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. In August 2018, NRG’s ownership interest in Four Brothers and Three Cedars was transferred to GIP. GIP’s ownership interest in Four Brothers and Three Cedars, Terra Nova Renewable Partners’ 33% interest in certain of Dominion Energy’s merchant solar projects and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019), is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements.

Operating Revenue

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Dominion Energy and Virginia Power collect sales, consumption and consumer utility taxes and Dominion Energy Gas collects sales taxes; however, these amounts are excluded from revenue. Dominion Energy’s customer receivables at December 31, 2018 and 2017 included $626 million and $661 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 2018 and 2017 included $392 million and $400 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers. Dominion Energy Gas’ customer receivables at December 31, 2018 and 2017 included $131 million and $121 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas delivered but not yet billed to its customers. See Note 24 for amounts attributable to related parties.

The primary types of sales and service activities reported as operating revenue for Dominion Energy, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:

REVENUE FROM CONTRACTS WITH CUSTOMERS

• Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

• Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated hedging activity;

• Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;

• Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties and associated hedging activity;

• Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

• Nonregulated gas transportation and storage sales consist primarily of LNG terminalling services;

• Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities; and

• Other nonregulated revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity. Other nonregulated revenue also includes services performed for Atlantic Coast Pipeline, sales of energy-related products and services from Dominion Energy’s retail energy marketing operations, service concession arrangements and gas processing and handling revenue.

OTHER REVENUE

• Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

The primary types of sales and service activities reported as operating revenue for Dominion Energy, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:

• Regulated electric sales consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

• Nonregulated electric sales consisted primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;

• Regulated gas sales consisted primarily of state- and FERC-regulated natural gas sales and related distribution services and associated derivative activity;

• Nonregulated gas sales consisted primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity;

• Gas transportation and storage sales consisted primarily of FERC-regulated sales of transmission and storage services. Also included were state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services; and

• Other revenue consisted primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also included miscellaneous service revenue from electric and gas distribution operations, sales of energy-related products and services from Dominion Energy’s retail energy marketing operations and gas processing and handling revenue.

The primary types of sales and service activities reported as operating revenue for Virginia Power, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:

REVENUE FROM CONTRACTS WITH CUSTOMERS

• Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services;

• Other regulated revenue consists primarily of sales of excess capacity and other commodities and miscellaneous service revenue from electric distribution operations; and

• Other nonregulated revenue consists primarily of sales to non-jurisdictional customers from certain solar facilities, revenue from renting space on certain electric transmission poles and distribution towers and service concession arrangements.

OTHER REVENUE

• Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

The primary types of sales and service activities reported as operating revenue for Virginia Power, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:

• Regulated electric sales consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; and

• Other revenue consisted primarily of miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities.

The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:

REVENUE FROM CONTRACTS WITH CUSTOMERS

• Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;

• Nonregulated gas sales consist primarily of sales of gas purchased from third parties and royalty revenues;

• Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

• NGL revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity;

• Management service revenue consists primarily of services performed for Atlantic Coast Pipeline;

• Other regulated revenue consists primarily of miscellaneous regulated revenues; and

• Other nonregulated revenue consists primarily of miscellaneous service revenue.

OTHER REVENUE

• Other revenue consists primarily of gains and losses from derivative instruments not subject to hedge accounting.

The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:

• Regulated gas sales consisted primarily of state- and FERC-regulated natural gas sales and related distribution services;

• Nonregulated gas sales consisted primarily of sales of natural gas production at market-based rates and contracted fixed prices and sales of gas purchased from third parties. Revenue from sales of gas production was recognized based on actual volumes of gas sold to purchasers and was reported net of royalties;

• Gas transportation and storage sales consisted primarily of FERC-regulated sales of transmission and storage services. Also included were state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

• NGL revenue consisted primarily of sales of NGL production and condensate, extracted products and associated derivative activity; and

• Other revenue consisted primarily of miscellaneous service revenue, gas processing and handling revenue.

Dominion Energy and Virginia Power record refunds to customers as required by state commissions as a reduction to regulated electric sales or regulated gas sales, as applicable. Dominion Energy and Virginia Power’s revenue accounted for under the alternative revenue program guidance primarily consists of the equity return for under-recovery of certain riders. Alternative revenue programs compensate Dominion Energy and Virginia Power for certain projects and initiatives. Revenues arising from these programs are presented separately from revenue arising from contracts with customers in the categories above.

Revenues from electric and gas sales are recognized over time, as the customers of the Companies consume gas and electricity as it is delivered. Transportation and storage contracts are primarily stand-ready service contracts that include fixed reservation and variable usage fees. LNG terminalling services are also stand-ready service contracts, primarily consisting of fixed fees, offset by service credits associated with the start-up phase of the Liquefaction Project. Fixed fees are recognized ratably over the life of the contract as the stand-ready performance obligation is satisfied, while variable usage fees are recognized when Dominion Energy and Dominion Energy Gas have a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the performance obligation completed to date. Sales of products and services, including NGLs, typically transfer control and are recognized as revenue upon delivery of the product or service. The customer is able to direct the use of, and obtain substantially all of the benefits from, the product at the time the product is delivered. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. Payment for most sales and services varies by contract type, but is typically due within a month of billing.

Dominion Energy and Dominion Energy Gas typically receive or retain NGLs and natural gas from customers when providing natural gas processing, transportation or storage services. The revised guidance for revenue from contracts with customers requires entities to include the fair value of the noncash consideration in the transaction price. Therefore, subsequent to the adoption of the revised guidance for revenue recognition from contracts with customers, Dominion Energy and Dominion Energy Gas record the fair value of NGLs received during natural gas processing as service revenue recognized over time, and continue to recognize revenue from the subsequent sale of the NGLs to customers upon delivery. Dominion Energy and Dominion Energy Gas typically retain natural gas under certain transportation service arrangements that are intended to facilitate performance of the service and allow for natural losses that occur. As the intent of the allowance is to enable fulfillment of the contract rather than to provide compensation for services, the fuel allowance is not included in revenue.

Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs

Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs

Where permitted by regulatory authorities, the differences between Dominion Energy and Virginia Power’s actual electric fuel and purchased energy expenses and Dominion Energy and Dominion Energy Gas’ purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.

Of the cost of fuel used in electric generation and energy purchases to serve utility customers, at December 31, 2018, approximately 84% is subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.

Virtually all of Dominion Energy Gas, Cove Point, Questar Gas, Hope and SCE&G and PSNC’s, following the SCANA Combination, natural gas purchases are either subject to deferral accounting or are recovered from the customer in the same accounting period as the sale.

Income Taxes

Income Taxes

A consolidated federal income tax return is filed for Dominion Energy and its subsidiaries, including Virginia Power and Dominion Energy Gas’ subsidiaries. In addition, where applicable, combined income tax returns for Dominion Energy and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed.

Although Dominion Energy Gas is disregarded for income tax purposes, a provision for income taxes is recognized to reflect the inclusion of its business activities in the tax returns of its parent, Dominion Energy. Virginia Power and Dominion Energy Gas participate in intercompany tax sharing agreements with Dominion Energy and its subsidiaries. Current income taxes are based on taxable income or loss and credits determined on a separate company basis.

Under the agreements, if a subsidiary incurs a tax loss or earns a credit, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or credit or to the extent the tax loss or credit is absorbed by the taxable income of other Dominion Energy consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax asset until realized.

The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies, including changes in corporate tax rates and business deductions. The 2017 Tax Reform Act reduces the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. Deferred tax assets and liabilities are classified as noncurrent in the Consolidated Balance Sheets and measured at the enacted tax rate expected to apply when temporary differences are realized or settled. Thus, at the date of enactment, federal deferred taxes were remeasured based upon the new 21% tax rate. The total effect of tax rate changes on deferred tax balances was recorded as a component of the income tax provision related to continuing operations for the period in which the law is enacted, even if the assets and liabilities relate to other components of the financial statements, such as items of accumulated other comprehensive income. For Dominion Energy subsidiaries that are not rate-regulated utilities, existing deferred income tax assets or liabilities were adjusted for the reduction in the corporate income tax rate and allocated to continuing operations. Dominion Energy’s rate-regulated utility subsidiaries likewise were required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, if it is probable that the effect of the change in income tax rates will be recovered or refunded in future rates, the regulated utility recorded a regulatory asset or liability instead of an increase or decrease to deferred income tax expense.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. The Companies establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

The Companies recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the Consolidated Balance Sheets and current payables are included in accrued interest, payroll and taxes on the Consolidated Balance Sheets.

The Companies recognize interest on underpayments and overpayments of income taxes in interest expense and other income, respectively. Penalties are also recognized in other income.

Interest for the Companies was immaterial in 2018 and 2016. Dominion Energy and Virginia Power both recognized interest income of $11 million in 2017. Dominion Energy Gas’ interest was immaterial in 2017. Dominion Energy, Virginia Power and Dominion Energy Gas’ penalties were immaterial in 2018, 2017 and 2016.

At December 31, 2018, Virginia Power had an income tax-related affiliated receivable of $36 million, comprised of $34 million of federal income taxes and $2 million of state income taxes due from Dominion Energy. Dominion Energy Gas also had a net affiliated receivable of $2 million due from Dominion Energy, representing $8 million of federal income taxes receivable and $6 million of state income taxes payable to Dominion Energy. The net affiliated receivables are expected to be received from Dominion Energy.

In addition, Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2018 included $13 million of state income taxes receivable. State income taxes receivable at Virginia Power were immaterial at December 31, 2018.

At December 31, 2017, Virginia Power had an income tax-related affiliated payable of $16 million, comprised of $16 million of federal income taxes due to Dominion Energy. Dominion Energy Gas also had an affiliated payable of $25 million due to Dominion Energy, representing $21 million of federal income taxes and $4 million of state income taxes. The net affiliated payables were paid to Dominion Energy.

In addition, Virginia Power’s Consolidated Balance Sheet at December 31, 2017 included $1 million of noncurrent federal income taxes receivable, less than $1 million of state income taxes receivable and $1 million of noncurrent state income taxes receivable. Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2017 included $14 million of state income taxes receivable.

Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.

Cash, Restricted Cash and Equivalents

Cash, Restricted Cash and Equivalents

Cash, restricted cash and equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Current banking arrangements generally do not require checks to be funded until they are presented for payment. The following table illustrates the checks outstanding but not yet presented for payment and recorded in accounts payable for the Companies:

At December 31,	2018		2017
(millions)
Dominion Energy	$	35	$	30
Virginia Power		16		17
Dominion Energy Gas		7		7

RESTRICTED CASH AND EQUIVALENTS

The Companies hold restricted cash and equivalent balances that primarily consist of amounts held for customer deposits, future debt payments on SBL Holdco and Dominion Solar Projects III, Inc.’s term loan agreements and on Eagle Solar’s senior note agreement.

The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within the Companies’ Consolidated Balance Sheets to the corresponding amounts reported within the Companies’ Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016:

	Cash, Restricted Cash and Equivalents at End/Beginning of Year
	December 31, 2018		December 31, 2017		December 31, 2016		December 31, 2015
(millions)
Dominion Energy
Cash and cash equivalents	$	268	$	120	$	261	$	607
Restricted cash and equivalents(1)		123		65		61		25
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	391	$	185	$	322	$	632
Virginia Power
Cash and cash equivalents	$	29	$	14	$	11	$	18
Restricted cash and equivalents(1)		9		10		—		—
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	38	$	24	$	11	$	18
Dominion Energy Gas
Cash and cash equivalents	$	10	$	4	$	23	$	13
Restricted cash and equivalents(1)		24		26		20		14
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	34	$	30	$	43	$	27

(1) Restricted cash and equivalent balances are presented within other current assets in the Companies’ Consolidated Balance Sheets.

DISTRIBUTIONS FROM EQUITY METHOD INVESTEES

Dominion Energy and Dominion Energy Gas each hold investments that are accounted for under the equity method of accounting. Dominion Energy and Dominion Energy Gas classify distributions from equity method investees as either cash flows from operating activities or cash flows from investing activities in the Consolidated Statements of Cash Flows according to the nature of the distribution. Distributions received are classified on the basis of the nature of the activity of the investee that generated the distribution as either a return on investment (classified as cash flows from operating activities) or a return of an investment (classified as cash flows from investing activities) when such information is available to Dominion Energy and Dominion Energy Gas.

Derivative Instruments

Derivative Instruments

The Companies are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as interest rate and foreign currency exchange rate risks of their business operations. Dominion Energy uses derivative instruments such as physical and financial forwards, futures, swaps, options and FTRs to manage the commodity, interest rate and foreign currency exchange rate risks of its business operations. Virginia Power uses derivative instruments such as physical and financial forwards, futures, swaps, options and FTRs to manage commodity and interest rate risks. Dominion Energy Gas uses derivative instruments such as physical and financial forwards, futures and swaps to manage commodity, interest rate and foreign currency exchange rate risks.

All derivatives, except those for which an exception applies, are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.

The Companies do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion Energy had margin assets of $95 million and $92 million associated with cash collateral at December 31, 2018 and 2017, respectively. Dominion Energy’s margin liabilities associated with cash collateral were less than $1 million at December 31, 2018 and 2017. Virginia Power had margin assets of $23 million associated with cash collateral at December 31, 2017. Virginia Power had no margin assets associated with cash collateral at December 31, 2018 and no margin liabilities associated with cash collateral at December 31, 2018 and 2017. Dominion Energy Gas had no margin assets or liabilities associated with cash collateral at December 31, 2018 and 2017. See Note 7 for further information about derivatives.

To manage price risk, the Companies hold certain derivative instruments that are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices. All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses, interest and related charges or other income based on the nature of the underlying risk.

Changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.

DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS

In accordance with accounting guidance pertaining to derivatives and hedge accounting, the Companies designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For derivative instruments that are accounted for as fair value hedges or cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.

Cash Flow Hedges-A majority of the Companies’ hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas and NGLs. The Companies also use interest rate swaps to hedge their exposure to variable interest rates on long-term debt as well as foreign currency swaps to hedge their exposure to interest payments denominated in Euros. For transactions in which the Companies are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Dominion Energy entered into interest rate derivative instruments to hedge its forecasted interest payments related to planned debt issuances in 2014. These interest rate derivatives were designated by Dominion Energy as cash flow hedges prior to the formation of Dominion Energy Gas. For the purposes of the Dominion Energy Gas financial statements, the derivative balances, AOCI balance, and any income statement impact related to these interest rate derivative instruments entered into by Dominion Energy have been, and will continue to be, included in the Dominion Energy Gas’ Consolidated Financial Statements as the forecasted interest payments related to the debt issuances now occur at Dominion Energy Gas.

Fair Value Hedges-Dominion Energy has also designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. In addition, Dominion Energy has used fair value hedges to mitigate the fixed price exposure inherent in commodity inventory. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7 for further information on derivatives.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is generally charged to expense as it is incurred.

In 2018, 2017 and 2016, Dominion Energy capitalized interest costs and AFUDC to property, plant and equipment of $134 million, $236 million and $159 million, respectively. In 2018, 2017 and 2016, Virginia Power capitalized AFUDC to property, plant and equipment of $56 million, $37 million and $21 million, respectively. In 2018, 2017 and 2016, Dominion Energy Gas capitalized AFUDC to property, plant and equipment of $18 million, $25 million and $8 million, respectively.

Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2018, 2017 and 2016, Virginia Power recorded $4 million, $22 million and $31 million of AFUDC related to these projects, respectively.

For property subject to cost-of-service rate regulation, including Dominion Energy and Virginia Power electric distribution, electric transmission and generation property, Dominion Energy Gas natural gas distribution and transmission property, and for certain Dominion Energy natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be abandoned. In January 2019, Virginia Power committed to a plan to retire certain automated meter reading infrastructure associated with its electric operations before the end of its useful life and replace such equipment with more current AMI technology. As a result, Virginia Power expects to incur a charge of approximately $190 million ($141 million after-tax) in 2019.

For property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. The Companies’ average composite depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,	2018		2017		2016
(percent)
Dominion Energy
Generation		2.71		2.94		2.83
Transmission		2.54		2.55		2.47
Distribution		2.97		3.00		3.02
Storage		2.40		2.48		2.29
Gas gathering and processing		2.62		2.21		2.66
General and other		4.56		4.89		4.12
Virginia Power
Generation		2.71		2.94		2.83
Transmission		2.52		2.54		2.36
Distribution		3.31		3.32		3.32
General and other		4.52		4.68		3.49
Dominion Energy Gas
Transmission		2.45		2.40		2.43
Distribution		2.41		2.42		2.55
Storage		2.46		2.45		2.19
Gas gathering and processing		3.07		2.42		2.58
General and other		5.59		4.96		4.54

In the second quarter of 2018, Virginia Power recorded an adjustment for the retroactive application of depreciation rates for regulated nuclear plants to comply with Virginia Commission requirements. This adjustment resulted in a decrease of $60 million ($44 million after-tax) in depreciation expense in Virginia Power’s Consolidated Statements of Income for the year ended December 31, 2018. This resulted in an increase to Dominion Energy’s EPS of $0.07 per share for the year ended December 31, 2018. This revision is expected to decrease annual depreciation expense by approximately $30 million ($23 million after-tax).

In the first quarter of 2017, Virginia Power revised the depreciation rates for its assets to reflect the results of a new depreciation study. This change resulted in an increase in annual depreciation expense of $40 million ($25 million after-tax) for 2017. Additionally, Dominion Energy revised the depreciable lives for its merchant generation assets, excluding Millstone, which resulted in a decrease in annual depreciation expense of $26 million ($16 million after-tax) for 2017.

Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved gas and oil reserves, at a rate of $1.89 and $2.11 per mcfe in 2018 and 2017, respectively.

Dominion Energy’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:

Asset	Estimated Useful Lives
Merchant generation-nuclear		44 years
Merchant generation-other		15-30 years
Nonutility gas gathering and processing		3-50 years
LNG facility		40 years
General and other		5-59 years

Depreciation and amortization related to Virginia Power and Dominion Energy Gas’ nonutility property, plant and equipment and exploration and production properties was immaterial for the years ended December 31, 2018, 2017 and 2016, except for Dominion Energy Gas’ nonutility gas gathering and processing properties which are depreciated using the straight-line method over estimated useful lives between 10 and 50 years.

Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion Energy and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.

Long-Lived and Intangible Assets

Long-Lived and Intangible Assets

The Companies perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives.

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

The accounting for Dominion Energy and Dominion Energy Gas’ regulated gas and Dominion Energy and Virginia Power’s regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.

The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions, legislation or historical experience, as well as discussions with applicable regulatory authorities and legal counsel. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made.

Asset Retirement Obligations

Asset Retirement Obligations

The Companies recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. Quarterly, the Companies assess their AROs to determine if circumstances indicate that estimates of the amounts or timing of future cash flows associated with retirement activities have changed. AROs are adjusted when significant changes in the amounts or timing of future cash flows are identified. Dominion Energy and Dominion Energy Gas report accretion of AROs and depreciation on asset retirement costs associated with their natural gas pipeline and storage well assets as an adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Dominion Energy, following the SCANA Combination, and Virginia Power report accretion of AROs and depreciation on asset retirement costs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions. Additionally, Dominion Energy and Virginia Power report accretion of AROs and depreciation on asset retirement costs associated with certain rider and prospective rider projects as an adjustment to the regulatory asset for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs are reported in other operations and maintenance expense and depreciation expense, respectively, in the Consolidated Statements of Income.

Debt Issuance Costs

Debt Issuance Costs

The Companies defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as a reduction in long-term debt in the Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest expense. Unamortized costs associated with redemptions of debt securities prior to stated maturity dates are generally recognized and recorded in interest expense immediately. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation are deferred and amortized.

Investments

Investments

DEBT AND EQUITY SECURITIES WITH READILY DETERMINABLE FAIR VALUES

Dominion Energy accounts for and classifies investments in debt securities as trading or available-for-sale securities. Virginia Power classifies investments in debt securities as available-for-sale securities.

• Debt securities classified as trading securities include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.

• Debt securities classified as available-for-sale securities include all other debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other available-for-sale debt securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.

In determining realized gains and losses for debt securities, the cost basis of the security is based on the specific identification method.

Equity securities with readily determinable fair values include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans and securities held by Dominion Energy and Virginia Power in the nuclear decommissioning trusts. Dominion Energy and Virginia Power record all equity securities with a readily determinable fair value, or for which they are permitted to estimate fair value using NAV (or its equivalent), at fair value in nuclear decommissioning trust funds and other investments in the Consolidated Balance Sheets. However, Dominion Energy and Virginia Power may elect a measurement alternative for equity securities without a readily determinable fair value. Under the measurement alternative, equity securities are reported at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. Dominion Energy and Virginia Power qualitatively assess equity securities reported using the measurement alternative to determine whether an investment is impaired on an ongoing basis. Net realized and unrealized gains and losses on equity securities held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other equity securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts and rabbi trusts, net realized and unrealized gains and losses are included in other income in the Consolidated Statements of Income.

EQUITY SECURITIES WITHOUT READILY DETERMINABLE FAIR VALUES

The Companies account for illiquid and privately held securities without readily determinable fair values under either the equity method or cost method. Equity securities without readily determinable fair values include:

• Equity method investments when the Companies have the ability to exercise significant influence, but not control, over the investee. Dominion Energy’s investments are included in investments in equity method affiliates and Dominion Energy Gas’ investments are included in investments in their Consolidated Balance Sheets. Dominion Energy and Dominion Energy Gas record equity method adjustments in other income and earnings from equity method investee, respectively, in their Consolidated Statements of Income, including their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.

• Cost method investments when Dominion Energy and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion Energy and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds. Cost method investments are reported at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same issuer.

OTHER-THAN-TEMPORARY IMPAIRMENT

The Companies periodically review their investments in debt securities and equity method investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in the fair value of any security is determined to be other-than-temporary, the security is written down to its fair value at the end of the reporting period.

Decommissioning Trust Investments —Special Considerations for Debt Securities

• The recognition provisions of other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity.

• Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion Energy and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, Dominion Energy and Virginia Power record the credit loss in earnings and any remaining portion of the unrealized loss in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.

Inventories

Inventories

Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory is valued using the weighted-average cost method, except for East Ohio gas distribution operations, which are valued using the LIFO method. Under the LIFO method, current stored gas inventory was valued at $12 million and $9 million at December 31, 2018 and December 31, 2017, respectively. Based on the average price of gas purchased during 2018 and 2017, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $87 million and $79 million, respectively.

Gas Imbalances

Gas Imbalances

Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion Energy and Dominion Energy Gas value these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion Energy from other parties are reported in other current assets and imbalances that Dominion Energy and Dominion Energy Gas owe to other parties are reported in other current liabilities in the Consolidated Balance Sheets.

Goodwill

Goodwill

Dominion Energy and Dominion Energy Gas evaluate goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount.

New Accounting Standards

New Accounting Standards

REVENUE RECOGNITION

In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. The Companies adopted this revised accounting guidance for interim and annual reporting periods beginning January 1, 2018 using the modified retrospective method. Upon the adoption of the standard, Dominion Energy and Dominion Energy Gas recorded the cumulative-effect of a change in accounting principle of $3 million to retained earnings and membership interests, respectively, and to establish a contract asset related to changes in the timing of revenue recognition for three existing contracts with customers at DETI.

As a result of adopting this revised accounting guidance, Dominion Energy and Dominion Energy Gas record offsetting operating revenue and other energy-related purchases for non-cash consideration of performing processing and fractionation services related to NGLs. Such amounts at Dominion Energy were $107 million and at Dominion Energy Gas were $103 million, recorded in the Consolidated Statements of Income for the year ended December 31, 2018. No such amounts were recorded during the year ended December 31, 2017. Dominion Energy and Dominion Energy Gas no longer record offsetting operating revenue and purchased gas for fuel retained to offset costs on certain transportation and storage arrangements. Such amounts at Dominion Energy were $111 million and at Dominion Energy Gas were $79 million, recorded in the Consolidated Statements of Income for the year ended December 31, 2017.

FINANCIAL INSTRUMENTS

In January 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of financial instruments. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018 and the Companies adopted the standard using the modified retrospective method. Upon adoption of this guidance for equity securities held at January 1, 2018, Dominion Energy and Virginia Power recorded the cumulative-effect of a change in accounting principle to reclassify net unrealized gains from AOCI to retained earnings and to recognize equity securities previously categorized as cost method investments at fair value (using NAV) in nuclear decommissioning trust funds in the Consolidated Balance Sheets and a cumulative-effect adjustment to retained earnings. Dominion Energy and Virginia Power reclassified approximately $1.1 billion ($734 million after-tax) and $119 million ($73 million after-tax), respectively, of net unrealized gains from AOCI to retained earnings. Dominion Energy and Virginia Power also recorded approximately $36 million ($22 million after-tax) in net unrealized gains on equity securities previously classified as cost method investments, of which $3 million was recorded to retained earnings and $33 million was recorded to regulatory liabilities for net unrealized gains subject to cost-based regulation. As a result of adopting this revised accounting guidance, Dominion Energy recorded unrealized losses on equity securities, net of regulatory deferrals, of $190 million ($142 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018, resulting in an $0.22 loss per share for the year ended December 31, 2018. Virginia Power recorded unrealized losses on equity securities, net of regulatory deferrals, of $24 million ($18 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018.

LEASES

In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases currently classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.

The guidance is effective for the Companies’ interim and annual reporting periods beginning January 1, 2019. The Companies will adopt this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Companies are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Companies will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. Dominion Energy, Virginia Power and Dominion Energy Gas anticipate that the adoption of this guidance will result in approximately $450 million to $500 million, $200 million to $250 million and $60 million to $70 million, respectively, of offsetting right-of-use assets and liabilities added to their Consolidated Balance Sheets for operating leases in effect at the adoption date. Dominion Energy’s anticipated right-of-use asset and liability associated with operating leases includes those acquired as part of the SCANA Combination of approximately $30 million to $35 million. No material changes are expected to the Companies’ results of operations.

DERECOGNITION AND PARTIAL SALES OF NONFINANCIAL ASSETS

In February 2017, the FASB issued revised accounting guidance clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, and the Companies adopted the standard using the modified retrospective method. Upon adoption of the standard, Dominion Energy recorded the cumulative-effect of a change in accounting principle to reclassify $127 million from noncontrolling interests to common stock related to the sale of a noncontrolling interest in certain merchant solar projects completed in December 2015 and January 2016.

NET PERIODIC PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

In March 2017, the FASB issued revised accounting guidance for the presentation of net periodic pension and other postretirement benefit costs. This guidance became effective for the Companies beginning January 1, 2018 and requires that the service cost component of net periodic pension and other postretirement benefit costs be classified in the same line item as other compensation costs arising from services rendered by employees, while all other components of net periodic pension and other postretirement costs are classified outside of income from operations. In addition, only the service cost component remains eligible for capitalization during construction. These changes do not impact the accounting by participants in a multi-employer plan. The standard also recognizes that in the event that a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in recognition of a regulatory asset or liability. For costs not capitalized for which regulators are expected to provide recovery, a regulatory asset will be established. As such, the amounts eligible for capitalization in the Consolidated Financial Statements of Virginia Power and Dominion Energy Gas, as subsidiary participants in Dominion Energy’s multi-employer plans, will differ from the amounts eligible for capitalization in the Consolidated Financial Statements of Dominion Energy, the plan administrator. These differences will result in a regulatory asset or liability recorded in the Consolidated Financial Statements of Dominion Energy.

TAX REFORM

In December 2017, the staff of the SEC issued guidance which clarifies accounting for income taxes if information is not yet available or complete and provided for up to a one-year measurement period in which to complete the required analyses and accounting. The guidance described three scenarios associated with a company’s status of accounting for income tax reform: (1) a company is complete with its accounting for certain effects of tax reform, (2) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply accounting for income taxes based on the provisions of the tax laws that were in effect immediately prior to the 2017 Tax Reform Act being enacted. The Companies have accounted for the effects of the 2017 Tax Reform Act, although additional changes could occur as guidance is issued and finalized as described below. In addition, certain states in which the Companies operate may or may not conform to some or all of the provisions of the 2017 Tax Reform Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to results of operations and cash flows, and adjustments to tax-related assets and liabilities, and could be material.

In August 2018, the U.S. Department of Treasury issued proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017 through December 31, 2017. The application of these changes decreased Dominion Energy’s net operating loss carryforward utilization on its 2017 tax return as discussed in Note 5.

In November 2018, the U.S. Department of Treasury issued proposed regulations defining interest as any amounts associated with the time value of money or use of funds. These proposed regulations provide guidance for purposes of the exception to the interest limitation for regulated public utilities, the application of the interest limitation to consolidated groups, such as Dominion Energy, and the interest limitation with respect to partnerships and partners in those partnerships. It is unclear when the guidance may be finalized, or whether that guidance could result in a disallowance of a portion of the Companies’ interest deductions in the future.

In February 2018, the FASB issued revised accounting guidance to provide clarification on the application of the 2017 Tax Reform Act for balances recorded within AOCI. The revised guidance provides for stranded amounts within AOCI from the impacts of the 2017 Tax Reform Act to be reclassified to retained earnings. The Companies adopted this guidance for interim and annual reporting periods beginning January 1, 2018 on a prospective basis. In connection with the adoption of this guidance, Dominion Energy reclassified a benefit of $289 million from AOCI to retained earnings, Virginia Power reclassified a benefit of $3 million from AOCI to retained earnings and Dominion Energy Gas reclassified a benefit of $26 million from AOCI to membership interests. The amounts reclassified reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of the Companies’ AOCI.

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of the Companies’ own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion Energy applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments, and other investments including those held in nuclear decommissioning, Dominion Energy’s rabbi, and pension and other postretirement benefit plan trusts, in accordance with the requirements discussed above. Virginia Power applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments and other investments including those held in the nuclear decommissioning trust, in accordance with the requirements discussed above. Dominion Energy Gas applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments and other investments including those held in pension and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above.

Inputs and Assumptions

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including industry publications, and to a lesser extent, broker quotes. When evaluating pricing information provided by Designated Contract Market settlement pricing, other pricing services, or brokers, the Companies consider the ability to transact at the quoted price, i.e. if the quotes are based on an active market or an inactive market and to the extent which pricing models are used, if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases 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 sources.

For options and contracts with option-like characteristics where observable pricing information is not available from external sources, Dominion Energy and Virginia Power generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. Dominion Energy and Virginia Power use other option models under special circumstances, including but not limited to Spread Approximation Model and a Swing Option Model. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.

The inputs and assumptions used in measuring fair value include the following:

For commodity derivative contracts:

• Forward commodity prices

• Transaction prices

• Price volatility

• Price correlation

• Volumes

• Commodity location

• Interest rates

• Credit quality of counterparties and the Companies

• Credit enhancements

• Time value

For interest rate derivative contracts:

• Interest rate curves

• Credit quality of counterparties and the Companies

• Notional value

• Credit enhancements

• Time value

For foreign currency derivative contracts:

• Foreign currency forward exchange rates

• Interest rates

• Credit quality of counterparties and the Companies

• Notional value

• Credit enhancements

• Time value

For investments:

• Quoted securities prices and indices

• Securities trading information including volume and restrictions

• Maturity

• Interest rates

• Credit quality

Levels

The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

• Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as certain exchange-traded derivatives, and exchange-listed equities, U.S. and international equity securities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion Energy and Virginia Power, benefit plan trust funds for Dominion Energy and Dominion Energy Gas, and rabbi trust funds for Dominion Energy.

• Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include commodity forwards and swaps, interest rate swaps, foreign currency swaps and cash and cash equivalents, corporate debt instruments, government securities and other fixed income investments held in nuclear decommissioning trust funds for Dominion Energy and Virginia Power, benefit plan trust funds for Dominion Energy and Dominion Energy Gas and rabbi trust funds for Dominion Energy.

• Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for the Companies consist of long-dated commodity derivatives, FTRs, certain natural gas and power options and other modeled commodity derivatives.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. Alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments held in nuclear decommissioning and benefit plan trust funds, are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date. Alternative investments recorded at NAV are not classified in the fair value hierarchy.

Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.

Level 3 Valuations

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, certain forward market prices and implied price volatilities are considered unobservable.

Regulatory Matters Involving Potential Loss Contingencies

Regulatory Matters Involving Potential Loss Contingencies

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

Dominion Energy and Dominion Energy Gas-Defined Benefit Plans

Dominion Energy and Dominion Energy Gas—Defined Benefit Plans

Dominion Energy provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Dominion Energy Gas participates in a number of the Dominion Energy-sponsored retirement plans. Under the terms of its benefit plans, Dominion Energy reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Dominion Energy maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the employee’s compensation. Dominion Energy’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension programs also provide benefits to certain retired executives under company-sponsored nonqualified employee benefit plans. The nonqualified plans are funded through contributions to grantor trusts. Dominion Energy also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service.

Pension benefits for Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Pension Plan, a defined benefit pension plan sponsored by Dominion Energy that provides benefits to multiple Dominion Energy subsidiaries. Pension benefits for Dominion Energy Gas employees represented by collective bargaining units are covered by separate pension plans for East Ohio and, for DETI, a plan that provides benefits to employees of both DETI and Hope. Employee compensation is the basis for allocating pension costs and obligations between DETI and Hope and determining East Ohio’s share of total pension costs.

Retiree healthcare and life insurance benefits for Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Retiree Health and Welfare Plan, a plan sponsored by Dominion Energy that provides certain retiree healthcare and life insurance benefits to multiple Dominion Energy subsidiaries. Retiree healthcare and life insurance benefits for Dominion Energy Gas employees represented by collective bargaining units are covered by separate other postretirement benefit plans for East Ohio and, for DETI, a plan that provides benefits to both DETI and Hope. Employee headcount is the basis for allocating other postretirement benefit costs and obligations between DETI and Hope and determining East Ohio’s share of total other postretirement benefit costs.

Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates, mortality rates and the rate of compensation increases.

Dominion Energy uses December 31 as the measurement date for all of its employee benefit plans, including those in which Dominion Energy Gas participates.

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 that the Companies cannot estimate, 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 that 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 Companies’ financial position, liquidity or results of operations.

Guarantees, Surety Bonds and Letters of Credit

Dominion Energy also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion Energy would be obligated to satisfy such obligation. To the extent that a liability subject to a guarantee has been incurred by one of Dominion Energy’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion Energy 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 Energy currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.

Indemnifications

Indemnifications

As part of commercial contract negotiations in the normal course of business, the Companies may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Companies are unable to develop an estimate of the maximum potential amount of any other future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2018, the Companies believe any other future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.

Credit Risk

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

The Companies maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Management believes, based on credit policies and the December 31, 2018 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Schedule of Checks Outstanding but Not Yet Presented for Payment

The following table illustrates the checks outstanding but not yet presented for payment and recorded in accounts payable for the Companies:

At December 31,	2018		2017
(millions)
Dominion Energy	$	35	$	30
Virginia Power		16		17
Dominion Energy Gas		7		7

Reconciliation of Total Cash, Restricted Cash and Equivalents

The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within the Companies’ Consolidated Balance Sheets to the corresponding amounts reported within the Companies’ Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016:

	Cash, Restricted Cash and Equivalents at End/Beginning of Year
	December 31, 2018		December 31, 2017		December 31, 2016		December 31, 2015
(millions)
Dominion Energy
Cash and cash equivalents	$	268	$	120	$	261	$	607
Restricted cash and equivalents(1)		123		65		61		25
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	391	$	185	$	322	$	632
Virginia Power
Cash and cash equivalents	$	29	$	14	$	11	$	18
Restricted cash and equivalents(1)		9		10		—		—
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	38	$	24	$	11	$	18
Dominion Energy Gas
Cash and cash equivalents	$	10	$	4	$	23	$	13
Restricted cash and equivalents(1)		24		26		20		14
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	34	$	30	$	43	$	27

(1) Restricted cash and equivalent balances are presented within other current assets in the Companies’ Consolidated Balance Sheets.

Schedule of Depreciation Rates

The Companies’ average composite depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,	2018		2017		2016
(percent)
Dominion Energy
Generation		2.71		2.94		2.83
Transmission		2.54		2.55		2.47
Distribution		2.97		3.00		3.02
Storage		2.40		2.48		2.29
Gas gathering and processing		2.62		2.21		2.66
General and other		4.56		4.89		4.12
Virginia Power
Generation		2.71		2.94		2.83
Transmission		2.52		2.54		2.36
Distribution		3.31		3.32		3.32
General and other		4.52		4.68		3.49
Dominion Energy Gas
Transmission		2.45		2.40		2.43
Distribution		2.41		2.42		2.55
Storage		2.46		2.45		2.19
Gas gathering and processing		3.07		2.42		2.58
General and other		5.59		4.96		4.54

Property, Plant and Equipment

Dominion Energy’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:

Asset	Estimated Useful Lives
Merchant generation-nuclear		44 years
Merchant generation-other		15-30 years
Nonutility gas gathering and processing		3-50 years
LNG facility		40 years
General and other		5-59 years

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Acquisitions And Dispositions (Tables)

12 Months Ended

Dec. 31, 2018

Business Acquisition, Pro Forma Information

The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the SCANA Combination had taken place on January 1, 2018. The unaudited pro forma financial information has been presented for illustrative purposes only and may change as Dominion Energy finalizes its valuation of certain assets acquired and liabilities assumed at the acquisition date. The unaudited pro forma financial information is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.

	Twelve Months Ended December 31,
	2018(1)
(millions, except EPS)
Operating Revenue	$	17,505
Net income attributable to Dominion Energy		2,081
Earnings Per Common Share – Basic	$	2.78
Earnings Per Common Share – Diluted	$	2.77

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

Schedule of Business Acquisitions, by Acquisition

The following table presents significant completed acquisitions of wholly-owned merchant solar projects by Dominion Energy.

Completed Acquisition Date	Seller	Number of Projects			Project Location	Project Name(s)	Initial Acquisition (millions)(1)		Project Cost (millions)(2)		Date of Commercial Operations	MW Capacity
February 2017	Community Energy Solar, LLC		1		Virginia	Amazon Solar Farm Virginia—Southhampton	$	29	$	205	December 2017		100
March 2017	Solar Frontier Americas Holding LLC		1	(3)	California	Midway II		77		78	June 2017		30
May 2017	Cypress Creek Renewables, LLC		1		North Carolina	IS37		154		160	June 2017		79
June 2017	Hecate Energy Virginia C&C LLC		1		Virginia	Clarke County		16		16	August 2017		10
June 2017	Strata Solar Development, LLC/Moorings Farm 2 Holdco, LLC		2		North Carolina	Fremont, Moorings 2		20		20	November 2017		10
September 2017	Hecate Energy Virginia C&C LLC		1		Virginia	Cherrydale		40		41	November 2017		20
October 2017	Strata Solar Development, LLC		2		North Carolina	Clipperton, Pikeville		20		21	November 2017		10

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

(2) Includes acquisition cost.

(3) In April 2017, Dominion Energy discontinued efforts on the acquisition of the additional 20 MW solar project from Solar Frontier Americas Holding LLC.

SCANA

Schedule of Preliminary Allocation of Purchase Price to Assets Acquired and Liabilities Assumed

The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at closing to be reflected in Dominion Energy’s Consolidated Balance Sheet in the first quarter of 2019. The allocation is subject to change during the measurement period as additional information is obtained about the facts and circumstances that existed at closing. The allocation of the purchase price excludes certain contracts and intangible assets related to nonregulated operations, including SEMI, equity method investments and certain income tax-related amounts, which will be included as Dominion Energy completes its valuation analysis. As a result, the amount of goodwill included below may change by a material amount as Dominion Energy finalizes the allocation of the purchase price during the first quarter of 2019.

	Amount
(millions)
Total current assets	$	1,756
Investments		213
Property, plant and equipment, net		10,982
Goodwill		2,438
Regulatory assets		4,219
Other deferred charges and other assets, including intangible assets		314
Total Assets		19,922
Total current liabilities		1,506
Long-term debt		6,707
Deferred income taxes		1,097
Regulatory liabilities		2,664
Other deferred credits and other liabilities		1,109
Total Liabilities		13,083
Total purchase price	$	6,839

Business Acquisition, Pro Forma Information

The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the Dominion Energy Questar Combination had taken place on January 1, 2016. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.

	Twelve Months Ended December 31,
	2016(1)
(millions, except EPS)
Operating Revenue	$	12,497
Net income attributable to Dominion Energy		2,300
Earnings Per Common Share – Basic	$	3.73
Earnings Per Common Share – Diluted	$	3.73

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

Dominion Energy Questar Corporation

Schedule of Preliminary Allocation of Purchase Price to Assets Acquired and Liabilities Assumed

The modifications relate primarily to the finalization of Dominion Energy Questar’s 2016 tax return for the period January 1, 2016 through the Dominion Energy Questar Combination, as well as certain regulatory adjustments.

	Amount
(millions)
Total current assets	$	224
Investments(1)		58
Property, plant and equipment, net(2)		4,131
Goodwill		3,111
Total deferred charges and other assets, excluding goodwill		75
Total Assets		7,599
Total current liabilities(3)		793
Long-term debt(4)		963
Deferred income taxes		807
Regulatory liabilities		259
Asset retirement obligations		160
Other deferred credits and other liabilities		220
Total Liabilities		3,202
Total purchase price		4,397

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

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

(3) Includes $301 million of short-term debt, of which no amounts remain outstanding at December 31, 2018, as well as a $250 million variable interest rate term loan due in August 2017 that was paid in July 2017.

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

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Property Plant And Equipment (Tables)

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment

Major classes of property, plant and equipment and their respective balances for the Companies are as follows:

At December 31,	2018		2017
(millions)
Dominion Energy
Utility:
Generation	$	19,250	$	17,602
Transmission		16,669		15,335
Distribution		18,549		17,408
Storage		2,905		2,887
Nuclear fuel		1,626		1,599
Gas gathering and processing		307		219
Oil and gas		1,763		1,720
General and other		1,476		1,514
Plant under construction		2,385		7,765
Total utility		64,930		66,049
Nonutility:
Merchant generation-nuclear		1,550		1,452
Merchant generation-other		3,802		4,992
Nuclear fuel		1,025		968
Gas gathering and processing		185		630
LNG facility		3,977		—
Other-including plant under construction		1,109		732
Total nonutility		11,648		8,774
Total property, plant and equipment	$	76,578	$	74,823
Virginia Power
Utility:
Generation	$	19,250	$	17,602
Transmission		9,392		8,332
Distribution		11,785		11,151
Nuclear fuel		1,626		1,599
General and other		821		794
Plant under construction		1,639		2,840
Total utility		44,513		42,318
Nonutility-other		11		11
Total property, plant and equipment	$	44,524	$	42,329
Dominion Energy Gas
Utility:
Transmission	$	4,758	$	4,732
Distribution		3,527		3,267
Storage		1,691		1,688
Gas gathering and processing		210		202
General and other		233		216
Plant under construction		494		293
Total utility		10,913		10,398
Nonutility:
Gas gathering and processing		185		630
Other-including plant under construction		140		145
Total nonutility		325		775
Total property, plant and equipment	$	11,238	$	11,173

Schedule of Jointly Owned Utility Plants

Dominion Energy and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2018 is as follows:

	Bath County Pumped Storage Station(1)			North Anna Units 1 and 2(1)			Clover Power Station(1)			Millstone Unit 3(2)
(millions, except percentages)
Ownership interest		60	%		88.4	%		50	%		93.5	%
Plant in service		1,058			2,560			590			1,231
Accumulated depreciation		(639	)		(1,305	)		(240	)		(400	)
Nuclear fuel		—			721			—			571
Accumulated amortization of nuclear fuel		—			(608	)		—			(423	)
Plant under construction		6			103			9			66

(1) Units jointly owned by Virginia Power.

(2) Unit jointly owned by Dominion Energy.

SCANA

Property, Plant and Equipment

At the date of the SCANA Combination, major classes of property, plant and equipment and their respective balances for SCANA are as follows:

	2018
(millions)
Utility:
Generation	$	5,720
Transmission		2,416
Distribution		6,044
Storage		99
Nuclear fuel		611
General and other		631
Plant under construction		527
Total utility		16,048
Nonutility, including plant under construction		283
Total property, plant and equipment	$	16,331

Schedule of Jointly Owned Utility Plants

Actual average composite depreciation rates for SCANA’s utility property, plant and equipment were as follows:

	2018
(millions)
Generation		2.61	%
Transmission		2.47
Distribution		2.48
Storage		2.48
General and other		5.64

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Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2018

Annual amortization expense of intangible assets

Annual amortization expense for these intangible assets is estimated to be as follows:

	2019		2020		2021		2022		2023
(millions)
Dominion Energy	$	67	$	56	$	44	$	34	$	23
Virginia Power	$	29	$	23	$	16	$	12	$	6
Dominion Energy Gas	$	14	$	13	$	12	$	8	$	7

Segment allocation of goodwill

The changes in Dominion Energy and Dominion Energy Gas’ carrying amount and segment allocation of goodwill are presented below:

	Power Generation		Gas Infrastructure			Power Delivery		Corporate and Other(1)		Total
(millions)
Dominion Energy
Balance at December 31, 2016(2)	$	1,422	$	4,051		$	926	$	—	$	6,399
Dominion Energy Questar Combination		—		6(3	)		—		—		6
Balance at December 31, 2017(2)	$	1,422	$	4,057		$	926	$	—	$	6,405
Purchase Accounting Adjustment		—		5			—		—		5
Balance at December 31, 2018(2)	$	1,422	$	4,062		$	926	$	—	$	6,410
Dominion Energy Gas
Balance at December 31, 2016(2)	$	—	$	542		$	—	$	—	$	542
No events affecting goodwill		—		—			—		—		—
Balance at December 31, 2017(2)	$	—	$	542		$	—	$	—	$	542
Purchase Accounting Adjustment		—		5			—		—		5
Balance at December 31, 2018(2)	$	—	$	547		$	—	$	—	$	547

(1) Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.

(2) Goodwill amounts do not contain any accumulated impairment losses.

(3) See Note 3.

Components of intangible assets

years. The components of intangible assets are as follows:

	2018				2017
At December 31,	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Dominion Energy
Software, licenses and other	$	1,033	$	363	$	1,043	$	358
Virginia Power
Software, licenses and other	$	384	$	134	$	347	$	114
Dominion Energy Gas
Software, licenses and other	$	174	$	65	$	165	$	56

SCANA

Annual amortization expense of intangible assets

Annual amortization expense for these intangible assets is estimated to be as follows:

	2019		2020		2021		2022		2023
(millions)
SCANA	$	95	$	90	$	80	$	74	$	71

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Short-Term Debt And Credit Agreements (Tables)

12 Months Ended

Dec. 31, 2018

Schedule of Line of Credit Facilities

Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities were as follows:

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit		Facility Capacity Available
(millions)
At December 31, 2018
Joint revolving credit facility(2)	$	6,000		$   324		$88	$	5,588
At December 31, 2017
Joint revolving credit facility(3)	$	5,000		$3,298		$—	$	1,702
Joint revolving credit facility(3)		500		—		76		424
Total	$	5,500		$3,298		$76	$	2,126

(1) The weighted-average interest rates of the outstanding commercial paper supported by Dominion Energy’s credit facilities were 2.93% and 1.61% at December 31, 2018 and 2017, respectively.

(2) This credit facility matures in March 2023 and can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

(3) These credit facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. The facilities were scheduled to mature in April 2020 and were 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 Electric and Power Company

Schedule of Line of Credit Facilities

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

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit
(millions)
At December 31, 2018
Joint revolving credit facility(2)		$6,000		$314		$16
At December 31, 2017
Joint revolving credit facility(3)		$5,000		$542		$—
Joint revolving credit facility(3)		500		—		—
Total		$5,500		$542		$—

(1) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 2.94% and 1.65% at December 31, 2018 and 2017, respectively.

(2) The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Virginia Power was $1.5 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

(3) These facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. The full amount of the facilities was available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. These facilities were scheduled to mature in April 2020 and were used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

Dominion Energy Gas Holdings, LLC

Schedule of Line of Credit Facilities

Dominion Energy Gas’ share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion Energy, Virginia Power and Questar Gas were as follows:

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit
(millions)
At December 31, 2018
Joint revolving credit facility(2)		$1,500		$  10		$—
At December 31, 2017
Joint revolving credit facility(3)		$1,000		$629		$—
Joint revolving credit facility(3)		500		—		—
Total		$1,500		$629		$—

(1) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 2.58% and 1.57% at December 31, 2018 and 2017, respectively.

(2) A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. The sub-limit for Dominion Energy Gas is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Dominion Energy Gas was $750 million. If Dominion Energy 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

(3) These facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. A maximum of a combined $1.5 billion of the facilities was available to Dominion Energy Gas, assuming adequate capacity was available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. These credit facilities were scheduled to mature in April 2020 and were 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.

SCANA

Schedule of Line of Credit Facilities

At closing of the SCANA Combination, commercial paper and letters of credit outstanding, as well as capacity available under SCANA’s existing credit facilities were as follows:

	SCANA Corporation			SCE&G			PSNC			Total
(millions, except percentages)
Total facility limit	$	400		$	1,200	(1)	$	200		$	1,800
Letters of credit advances		40	(2)		—			—			40
Weighted-average interest rate		3.87	%		n/a			n/a			3.87	%
Outstanding commercial paper		2			73			98			173
Weighted-average interest rate		3.65	%		3.82	%		3.49	%		3.63	%
Outstanding letters of credit		37			—			—			37
Facility capacity available	$	321		$	1,127		$	102		$	1,550

(1) Includes South Carolina Fuel Company, Inc.’s $500 million credit facility.

(2) In January 2019, SCANA repaid $40 million in letter of credit advances.

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2018

Long term Debt

At December 31,	2018 Weighted- average Coupon(1)			2018			2017
(millions, except percentages)
Dominion Energy Gas Holdings, LLC:
Unsecured Senior Notes:
Variable rate, due 2021		3.39	%	$	500		$	—
2.5% to 3.55%, due 2019 to 2023		2.90	%		1,800			1,800
3.317% to 4.8%, due 2024 to 2044(2)		4.12	%		1,787			1,800
Dominion Energy Gas Holdings, LLC total principal				$	4,087		$	3,600
Securities due within one year		2.50	%		(449	)		—
Unamortized discount and debt issuance costs					(29	)		(30	)
Dominion Energy Gas Holdings, LLC total long-term debt				$	3,609		$	3,570
Virginia Electric and Power Company:
Unsecured Senior Notes:
1.2% to 5.4%, due 2018 to 2023		3.35	%	$	1,800		$	2,650
2.95% to 8.875%, due 2024 to 2048		4.61	%		9,290			7,990
Tax-Exempt Financings(3):
Variable rates, due 2024 to 2027					—			100
1.75% to 5.6%, due 2023 to 2041		2.18	%		664			678
Virginia Electric and Power Company total principal				$	11,754		$	11,418
Securities due within one year		5.00	%		(350	)		(850	)
Unamortized discount, premium and debt issuances costs, net					(83	)		(72	)
Virginia Electric and Power Company total long-term debt				$	11,321		$	10,496
Dominion Energy, Inc.:
Unsecured Senior Notes(4):
Variable rates, due 2019 and 2020		3.23	%	$	800		$	800
1.5% to 6.4%, due 2018 to 2022		2.75	%		2,550			5,800
2.85% to 7.0%, due 2024 to 2044		4.81	%		4,849			5,049
Unsecured Junior Subordinated Notes:
2.579% to 4.104%, due 2019 to 2021		3.08	%		2,100			2,100
Payable to Affiliated Trust, 8.4%, due 2031		8.40	%		10			10
Enhanced Junior Subordinated Notes:
5.25% and 5.75%, due 2054 and 2076		5.48	%		1,485			1,485
Variable rates, due 2066		5.26	%		422			422
Remarketable Subordinated Notes, 2.0%, due 2021 and 2024		2.00	%		1,400			1,400
Unsecured Debentures and Senior Notes(5):
6.8% and 6.875%, due 2026 and 2027		6.81	%		89			89
Unsecured Senior and Medium-Term Notes(6):
5.31% and 6.3%, due 2018					—			120
2.98% to 7.20%, due 2024 to 2051		4.25	%		750			600
Secured Senior Notes, 4.82%, due 2042(7)		4.82	%		362			—
Term Loans, variable rates, due 2023 and 2024(8)		4.85	%		582			638
Tax-Exempt Financing, 1.55%, due 2033(9)		1.55	%		27			27
Capital leases, 4.14% to 6.04%, due 2019 to 2029		5.99	%		39			—
Dominion Energy Midstream Partners, LP:
Term Loans, variable rates, due 2019 and 2021(10)(11)		4.13	%		3,300			300
Revolving Credit Agreement, variable rates, due 2021(11)		3.55	%		73			—
Unsecured Senior and Medium-Term Notes, 5.83% and 6.48%, due 2018(12)					—			255
Unsecured Senior Notes, 3.53% to 4.875%, due 2028 to 2041(12)		4.23	%		430			180
Dominion Energy Gas Holdings, LLC total principal (from above)					4,087			3,600
Virginia Electric and Power Company total principal (from above)					11,754			11,418
Dominion Energy, Inc. total principal				$	35,109		$	34,293
Fair value hedge valuation(13)					(20	)		(22	)
Securities due within one year(14)(15)		3.23	%		(3,624	)		(3,078	)
Credit facility borrowings(11)		3.55	%		(73	)		—
Unamortized discount, premium and debt issuance costs, net					(248	)		(245	)
Dominion Energy, Inc. total long-term debt				$	31,144		$	30,948

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2018.

(2) Amount includes foreign currency remeasurement adjustments.

(3) These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. In March 2018, Virginia Power redeemed certain variable rate tax-exempt financings supported by its $100 million credit facility and terminated the facility. In December 2018, Virginia Power redeemed its $14 million Economic Development Authority of the County of Chesterfield Solid Waste and Sewage Disposal Revenue Bonds due in 2031.

(4) In November and December 2018, Dominion Energy redeemed certain senior notes prior to their stated maturity. See below for a discussion of the senior note redemptions.

(5) Represents debt assumed by Dominion Energy from the merger of its former CNG subsidiary.

(6) Represents debt obligations of Questar Gas. See Note 3 for more information.

(7) Represents debt obligations of Eagle Solar. The debt is nonrecourse to Dominion Energy and is secured by Eagle Solar’s interest in certain merchant solar facilities.

(8) Represents debt associated with SBL Holdco and Dominion Solar Projects III, Inc. The debt is nonrecourse to Dominion Energy and is secured by SBL Holdco and Dominion Solar Projects III, Inc.’s interest in certain merchant solar facilities.

(9) Represents debt obligations of a DGI subsidiary.

(10) Includes debt obligations of Cove Point that are secured by Dominion Energy’s common equity interest in Cove Point.

(11) In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2018.

(12) Represents debt obligations of Dominion Energy Questar Pipeline. See Note 3 for more information.

(13) Represents the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt.

(14) 2017 excludes $250 million of Dominion Energy Questar Pipeline’s senior notes that matured in February 2018 using proceeds from the January 2018 issuance, through private placements, of $100 million and $150 million of senior notes that mature in 2028 and 2038, respectively.

(15) Includes $20 million of estimated mandatory prepayments due within one year based on estimated cash flows in excess of debt service at SBL Holdco and Dominion Solar Projects III, Inc.

Scheduled Principal Payments of Long-Term Debt

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2018, were as follows:

	2019			2020			2021			2022			2023			Thereafter			Total
(millions, except percentages)
Dominion Energy Gas	$	450		$	700		$	500		$	—		$	650		$	1,787		$	4,087
Weighted-average Coupon		2.50	%		2.80	%		3.39	%					3.29	%		4.12	%
Virginia Power
Unsecured Senior Notes	$	350		$	—		$	—		$	750		$	700		$	9,290		$	11,090
Tax-Exempt Financings		—			—			—			—			40			624			664
Total	$	350		$	—		$	—		$	750		$	740		$	9,914		$	11,754
Weighted-average Coupon		5.00	%								3.15	%		2.87	%		4.45	%
Dominion Energy
Term Loans(1)(2)	$	336		$	35		$	3,035		$	34		$	273		$	169		$	3,882
Credit Facility Borrowings(2)		—			—			73			—			—			—			73
Unsecured Senior Notes		2,700			1,000			900			1,500			1,350			17,195			24,645
Secured Senior Notes		17			15			17			19			16			278			362
Tax-Exempt Financings		—			—			—			—			40			651			691
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts		—			—			—			—			—			10			10
Unsecured Junior Subordinated Notes		550			1,000			550			—			—			—			2,100
Enhanced Junior Subordinated Notes		—			—			—			—			—			1,907			1,907
Remarketable Subordinated Notes		—			—			700			—			—			700			1,400
Capital leases		4			4			4			3			3			21			39
Total	$	3,607		$	2,054		$	5,279		$	1,556		$	1,682		$	20,931		$	35,109
Weighted-average Coupon		3.23	%		2.80	%		3.64	%		3.02	%		3.41	%		4.51	%

(1) Excludes mandatory prepayments associated with SBL Holdco and Dominion Solar Projects III, Inc. based on cash flows in excess of debt service. At December 31, 2018, $20 million of estimated mandatory prepayments due within one year were included in securities due within one year in Dominion Energy’s Consolidated Balance Sheets.

(2) In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2018.

Schedule of Capital Units

Selected information about Dominion Energy’s equity units is presented below:

Issuance Date	Units Issued		Total Net Proceeds		Total Long-term Debt		RSN Annual Interest Rate			Stock Purchase Contract Annual Rate			Stock Purchase Contract Liability(1)		Stock Purchase Settlement Date
(millions, except interest rates)
8/15/2016(2)		28	$	1,374.8		$1,400.0		2.000	%(3)		4.750	%		$190.6		8/15/2019

(1) Payments of $64 million and $101 million were made in 2018 and 2017, respectively, including payments for the remarketed 2014 Series A notes. The stock purchase contract liability was $47 million and $111 million at December 31, 2018 and 2017, respectively.

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

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

SCANA

Long term Debt

At closing of the SCANA Combination, SCANA had the following long-term debt outstanding which is part of the total consideration provided for the transaction.

	Weighted- average Coupon(1)			Amount
(millions, except percentages)
Unsecured medium term notes, due 2020 to 2022		5.42	%	$	800
Unsecured senior notes, due 2019 to 2034		3.44			70
First mortgage bonds, due 2021 to 2065		5.52			4,990
GENCO notes, due 2019 to 2024		5.49			40
Industrial and pollution control bonds, due 2028 to 2038(2)		3.52			122
PSNC senior debentures and notes, due 2020 to 2047		5.07			700
Other, due 2019 to 2027		3.46			73
Total principal				$	6,795
Current maturities of long-term debt					(59	)
Unamortized discount, premium and debt issuance costs, net					(29	)
SCANA total long-term debt				$	6,707

(1) Represents weighted-average coupon rates for debt outstanding at closing of the SCANA Combination.

(2) Includes variable rate debt of $68 million, with a weighted-average interest rate of 1.72%, which is hedged by fixed swaps.

Scheduled Principal Payments of Long-Term Debt

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at closing of the SCANA Combination, were as follows:

	2019			2020			2021			2022			2023			Thereafter			Total
(millions, except percentages)
Unsecured senior notes	$	4		$	4		$	4		$	4		$	4		$	50		$	70
Unsecured medium term notes		—			250			300			250			—			—			800
First mortgage bonds		—			—			330			—			—			4,660			4,990
PSNC senior debentures and notes		—			100			150			—			—			450			700
GENCO notes		7			7			7			7			7			5			40
Industrial and pollution control bonds		—			—			—			—			—			122			122
Other		48			7			6			5			3			4			73
Total	$	59		$	368		$	797		$	266		$	14		$	5,291		$	6,795
Weighted-average coupon		3.91	%		6.26	%		4.20	%		5.22	%		3.29	%		5.51	%		5.36	%

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Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Lease Commitments

 Future minimum lease payments under noncancelable operating leases that have initial or remaining lease terms in excess of one year as of December 31, 2018 are as follows:

	2019			2020			2021			2022			2023			Thereafter			Total
(millions)
Dominion Energy		$	64		$	61		$	55		$	47		$	38		$	384		$	649
Virginia Power			34			32			28			22			16			106			238
Dominion Energy Gas			12			11			9			7			4			3			46

Nuclear Insurance

The current levels of nuclear property insurance coverage for Dominion Energy and Virginia Power’s nuclear units are as follows:

	Coverage
(billions)
Dominion Energy
Millstone	$	1.70
Kewaunee		0.05
Virginia Power(1)
Surry	$	1.70
North Anna		1.70

(1) Surry and North Anna share a blanket property limit of $200 million.

Schedule Of Subsidiary Guarantees

At December 31, 2018, Dominion Energy had issued the following subsidiary guarantees:

	Maximum Exposure
(millions)
Commodity transactions(1)		$	2,186
Nuclear obligations(2)			179
Cove Point(3)			1,900
Solar(4)			659
Other(5)			420
Total(6)		$	5,344

(1) Guarantees related to commodity commitments of certain subsidiaries. These guarantees were provided to counterparties in order to facilitate physical and financial transaction related commodities and services.

(2) Guarantees related to certain DGI subsidiaries’ regarding all aspects of running a nuclear facility.

(3) Guarantees related to Cove Point, in support of terminal services, transportation and construction. Cove Point has two guarantees that have no maximum limit and, therefore, are not included in this amount.

(4) Includes guarantees to facilitate the development of solar projects. Also includes guarantees entered into by DGI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.

(5) Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations, construction projects and insurance programs. Due to the uncertainty of worker’s compensation claims, the parental guarantee has no stated limit. Also included are guarantees related to certain DGI subsidiaries’ obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of December 31, 2018, Dominion Energy’s maximum remaining cumulative exposure under these equity funding agreements is $4 million through 2019 and its maximum annual future contribution is approximately $4 million.

(6) Excludes Dominion Energy’s guarantee for the construction of the new corporate office property discussed further within Lease Commitments above.

Virginia Electric and Power Company

Long-term Purchase Commitment

At December 31, 2018, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that a third party has used to secure financing for the facility that will provide the contracted goods or services:

	2019			2020			2021			2022			2023			Thereafter			Total
(millions)
Purchased electric capacity(1)		$	60		$	52		$	46		$	—		$	—		$	—		$	158

(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with independent power producers, which end in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad based economic indices. At December 31, 2018, the present value of Virginia Power’s total commitment for capacity payments is $142 million. Capacity payments totaled $50 million, $114 million and $248 million, and energy payments totaled $42 million, $72 million and $126 million for the years ended 2018, 2017 and 2016, respectively.

SCANA

Long-term Purchase Commitment

SCANA has the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that a third party has used to secure financing for the facility that will provide the contracted goods or services:

	2019		2020		2021		2022		2023		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	31	$	30	$	30	$	30	$	30	$	310	$	461

(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities which expire at various dates through 2046. Capacity payments under the contracts are generally based on fixed dollar amounts per month.

Lease Commitments

SCANA is obligated under various operating leases for land, office space, furniture, equipment, rail cars and airplanes. Such leases expire at various dates through 2057.

	2019		2020		2021		2022		2023		Thereafter		Total
(millions)
Operating leases	$	10	$	8	$	7	$	6	$	4	$	30	$	65

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Operating Revenue (Tables)

12 Months Ended

Dec. 31, 2018

Operating Revenue For Revised Guidance of Revenue Recognition From Contracts with Customers

The Companies’ operating revenue, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, consists of the following:

Year Ended December 31,	2018
(millions)
Dominion Energy
Regulated electric sales:
Residential	$	3,413
Commercial		2,503
Industrial		490
Government and other retail		854
Wholesale		137
Nonregulated electric sales		1,294
Regulated gas sales:
Residential		818
Commercial		221
Other		36
Nonregulated gas sales		214
Regulated gas transportation and storage:
FERC-regulated		1,091
State-regulated		640
Nonregulated gas transportation and storage		442
Other regulated revenues		179
Other nonregulated revenues(1)(2)		563
Total operating revenue from contracts with customers		12,895
Other revenues(2)(3)		471
Total operating revenue	$	13,366
Virginia Power
Regulated electric sales:
Residential	$	3,413
Commercial		2,503
Industrial		490
Government and other retail		854
Wholesale		137
Other regulated revenues		132
Other nonregulated revenues(1)(2)		55
Total operating revenue from contracts with customers		7,584
Other revenues(1)(3)		35
Total operating revenue	$	7,619
Dominion Energy Gas
Regulated gas sales:
Residential	$	81
Other		27
Nonregulated gas sales(1)		13
Regulated gas transportation and storage:
FERC-regulated(1)		763
State-regulated(1)		605
NGL revenue(1)(2)		223
Management service revenue(1)		205
Other regulated revenues(1)		22
Other nonregulated revenues(1)		10
Total operating revenue from contracts with customers		1,949
Other revenues		(9	)
Total operating revenue	$	1,940

(1) See Notes 9 and 24 for amounts attributable to related parties and affiliates.

(2) Amounts above include $241 million and $206 million for the year ended December 31, 2018 primarily consisting of NGL sales at Dominion Energy and Dominion Energy Gas, respectively, which are considered to be goods transferred at a point in time. In addition, the amounts include $17 million and $11 million of sales of renewable energy credits at both Dominion Energy and Virginia Power for the year ended December 31, 2018, respectively, which are considered to be goods transferred at a point in time.

(3) Amounts above include $15 million of alternative revenue at Dominion Energy and Virginia Power for the year ended December 31, 2018.

Schedule of Aggregate Amount of Transaction Price Allocated To Fixed-price Performance Obligations That Unsatisfied At End of Reporting Period And Expected To be Recognized

The table below discloses the aggregate amount of the transaction price allocated to fixed-price performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and when the Companies expect to recognize this revenue. These revenues relate to contracts containing fixed prices where the Companies will earn the associated revenue over time as they stand ready to perform services provided. This disclosure does not include revenue related to performance obligations that are part of a contract with original durations of one year or less. In addition, this disclosure does not include expected consideration related to performance obligations for which the Companies elect to recognize revenue in the amount they have a right to invoice.

Revenue expected to be recognized on multi-year contracts in place at December 31, 2018	2019		2020		2021		2022		2023		Thereafter		Total
(millions)
Dominion Energy	$	1,643	$	1,563	$	1,448	$	1,319	$	1,154	$	13,693	$	20,820
Virginia Power		21		3		1		—		—		—		25
Dominion Energy Gas		600		560		475		384		268		1,612		3,899

Subsequent To Adoption of Revised Guidance

Operating Revenue For Revised Guidance of Revenue Recognition From Contracts with Customers

The Companies’ operating revenue, prior to the adoption of revised guidance for revenue recognition from contracts with customers, consisted of the following:

Year Ended December 31,	2017		2016
(millions)
Dominion Energy
Electric sales:
Regulated	$	7,383	$	7,348
Nonregulated		1,429		1,519
Gas sales:
Regulated		1,067		500
Nonregulated		457		354
Gas transportation and storage		1,786		1,636
Other		464		380
Total operating revenue	$	12,586	$	11,737
Virginia Power
Regulated electric sales	$	7,383	$	7,348
Other		173		240
Total operating revenue	$	7,556	$	7,588
Dominion Energy Gas
Gas sales:
Regulated	$	87	$	119
Nonregulated		20		13
Gas transportation and storage		1,435		1,307
NGL revenue		91		62
Other		181		137
Total operating revenue	$	1,814	$	1,638

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income tax expense for continuing operations including noncontrolling interests

Details of income tax expense for continuing operations including noncontrolling interests were as follows:

	Dominion Energy									Virginia Power									Dominion Energy Gas
Year Ended December 31,	2018			2017			2016			2018			2017			2016			2018			2017			2016
(millions)
Current:
Federal	$	(45	)	$	(1	)	$	(155	)	$	36		$	432		$	168		$	23		$	16		$	(27	)
State		108			(26	)		85			40			73			90			30			8			4
Total current expense (benefit)		63			(27	)		(70	)		76			505			258			53			24			(23	)
Deferred:
Federal
2017 Tax Reform Act impact		46			(851	)		—			21			(93	)		—			(11	)		(197	)		—
Taxes before operating loss carryforwards and investment tax credits		436			739			1,050			199			319			435			48			199			239
Tax utilization expense (benefit) of operating loss carryforwards		92			174			(161	)		—			4			(2	)		—			5			(2	)
Investment tax credits		(56	)		(200	)		(248	)		(51	)		(23	)		(25	)		—			—			—
State		(1	)		132			50			55			59			27			(4	)		20			1
Total deferred expense (benefit)		517			(6	)		691			224			266			435			33			27			238
Investment tax credit-gross deferral		2			5			35			2			5			35			—			—			—
Investment tax credit-amortization		(2	)		(2	)		(1	)		(2	)		(2	)		(1	)		—			—			—
Total income tax expense (benefit)	$	580		$	(30	)	$	655		$	300		$	774		$	727		$	86		$	51		$	215

Effective Income Tax

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

	Dominion Energy									Virginia Power									Dominion Energy Gas
Year Ended December 31,	2018			2017			2016			2018			2017			2016			2018			2017			2016
U.S. statutory rate		21.0	%		35.0	%		35.0	%		21.0	%		35.0	%		35.0	%		21.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		3.0			2.0			2.4			4.7			3.7			3.8			3.2			2.4			0.5
Investment tax credits		(1.9	)		(6.3	)		(11.7	)		(3.5	)		(0.8	)		—			—			—			—
Production tax credits		(0.7	)		(0.7	)		(0.8	)		(0.7	)		(0.4	)		(0.5	)		—			—			—
Valuation allowances		0.3			0.2			1.2			—			—			0.1			1.8			0.3			—
Reversal of excess deferred income taxes		(2.0	)		—			—			(3.2	)		—			—			(1.7	)		—			—
Federal legislative change		1.5			(27.5	)		—			1.3			(4.0	)		—			(2.8	)		(29.5	)		—
State legislative change		(0.6	)		—			(0.6	)		—			—			—			0.2			—			—
AFUDC—equity		(0.8	)		(1.4	)		(0.6	)		(0.5	)		(0.6	)		(0.6	)		(0.6	)		(0.9	)		(0.2	)
Employee stock ownership plan deduction		(0.4	)		(0.6	)		(0.6	)		—			—			—			—			—			—
Other, net		(0.9	)		(1.7	)		(1.4	)		(0.1	)		0.6			(0.4	)		1.2			0.4			0.1
Effective tax rate		18.5	%		(1.0	)%		22.9	%		19.0	%		33.5	%		37.4	%		22.3	%		7.7	%		35.4	%

Deferred income taxes components

The Companies’ deferred income taxes consist of the following:

	Dominion Energy						Virginia Power						Dominion Energy Gas
At December 31,	2018			2017			2018			2017			2018			2017
(millions)
Deferred income taxes:
Total deferred income tax assets	$	2,748		$	2,686		$	1,054			$   923			$   318		$	320
Total deferred income tax liabilities		7,813			7,158			4,020			3,600			1,783			1,774
Total net deferred income tax liabilities	$	5,065		$	4,472		$	2,966			$2,677			$1,465		$	1,454
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	$	4,933		$	5,056		$	3,367			$2,969			$1,170		$	1,132
Excess deferred income taxes		(993	)		(1,050	)		(678	)		(687	)		(254	)		(244	)
Nuclear decommissioning		815			829			273			260			—			—
Deferred state income taxes		626			834			284			378			175			227
Federal benefit of deferred state income taxes		(132	)		(175	)		(60	)		(79	)		(37	)		(48	)
Deferred fuel, purchased energy and gas costs		60			1			59			(3	)		1			2
Pension benefits		81			141			(132	)		(104	)		431			419
Other postretirement benefits		(5	)		(51	)		55			44			(1	)		(2	)
Loss and credit carryforwards		(1,546	)		(1,536	)		(183	)		(111	)		(7	)		(4	)
Valuation allowances		158			146			5			5			12			3
Partnership basis differences		1,135			473			—			—			26			26
Other		(67	)		(196	)		(24	)		5			(51	)		(57	)
Total net deferred income tax liabilities	$	5,065		$	4,472		$	2,966			$2,677			$1,465		$	1,454
Deferred Investment Tax Credits – Regulated Operations		51			51			51			51			—			—
Total Deferred Taxes and Deferred Investment Tax Credits	$	5,116		$	4,523		$	3,017			$2,728			$1,465		$	1,454

Summary of deductible loss and credit carryforwards

At December 31, 2018, Dominion Energy had the following deductible loss and credit carryforwards:

	Deductible Amount		Deferred Tax Asset		Valuation Allowance			Expiration Period
(millions)
Federal losses		$   120	$	25		$    —			2034
Federal investment credits		—		1,007		—			2033-2038
Federal production credits		—		150		—			2031-2038
Other federal credits		—		62		—			2031-2038
State losses		1,126		73		(61	)		2019-2038
State minimum tax credits		—		122		—			No expiration
State investment and other credits		—		107		(90	)		2019-2025
Total		$1,246	$	1,546		$(151)

At December 31, 2018, Virginia Power had the following deductible loss and credit carryforwards:

	Deductible Amount		Deferred Tax Asset		Valuation Allowance			Expiration Period
(millions)
Federal losses		$  1		$   —		$ —			2034
Federal investment credits		—		113		—			2034-2038
Federal production and other credits		—		61		—			2031-2038
State investment credits		—		9		(5	)		2024
Total		$  1		$183		$(5	)

At December 31, 2018, Dominion Energy Gas had the following deductible loss and credit carryforwards:

	Deductible Amount		Deferred Tax Asset		Valuation Allowance			Expiration Period
(millions)
Other federal credits	$	—	$	1	$	—			2032-2037
State losses		53		5		(5	)		2036-2038
Total	$	53	$	6	$	(5	)

Reconciliation of changes in unrecognized tax benefits

A reconciliation of changes in the Companies’ unrecognized tax benefits follows:

	Dominion Energy									Virginia Power									Dominion Energy Gas
	2018			2017			2016			2018			2017			2016			2018		2017			2016
(millions)
Balance at January 1	$	38		$	64		$	103		$	4		$	13		$	12			$ —	$	7			$29
Increases-prior period positions		10			1			9			—			—			4			—		—			1
Decreases-prior period positions		—			(9	)		(44	)		—			(1	)		(3	)		—		—			(19	)
Increases-current period positions		10			5			6			—			—			—			—		—			—
Settlements with tax authorities		(6	)		(23	)		(8	)		(1	)		(8	)		—			—		(7	)		(4	)
Expiration of statutes of limitations		(8	)		—			(2	)		(1	)		—			—			—		—			—
Balance at December 31	$	44		$	38		$	64		$	2		$	4		$	13			$—	$	—			$  7

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value Inputs, Assets, Quantitative Information

The following table presents Dominion Energy’s quantitative information about Level 3 fair value measurements at December 31, 2018. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques		Unobservable Input		Range		Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)		$42		Discounted cash flow		Market price (per Dth)(3)		(2) - 8		(1	)
FTRs		15		Discounted cash flow		Market price (per MWh)(3)		(2) - 7		1
Physical options:
Natural gas		2		Option model		Market price (per Dth)(3)		1 - 8		3
						Price volatility (4)		18% - 73%		30	%
Electricity		11		Option model		Market price (per MWh)(3)		34 - 50		42
						Price volatility (4)		39% - 60%		49	%
Total assets		$70
Liabilities
Financial forwards:
FTRs		$  6		Discounted cash flow		Market price (per MWh)(3)		(2) - 6		—
Total liabilities		$  6

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

Fair Value, Option, Qualitative Disclosures

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)

Fair Value, by Balance Sheet Grouping

The following table presents Dominion Energy’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)
December 31, 2018
Assets
Derivatives:
Commodity	$	—	$	180		$  70	$	250
Interest rate		—		18		—		18
Foreign currency		—		26		—		26
Investments(1):
Equity securities:
U.S.		3,277		—		—		3,277
Fixed income:
Corporate debt instruments		—		431		—		431
Government securities		455		688		—		1,143
Cash equivalents and other		11		—		—		11
Total assets	$	3,743	$	1,343		$  70	$	5,156
Liabilities
Derivatives:
Commodity	$	—	$	129		$    6	$	135
Interest rate		—		142		—		142
Foreign currency		—		2		—		2
Total liabilities	$	—	$	273		$    6	$	279
December 31, 2017
Assets
Derivatives:
Commodity	$	—	$	101		$157	$	258
Interest rate		—		17		—		17
Foreign currency		—		32		—		32
Investments(1):
Equity securities:
U.S.		3,493		—		—		3,493
Fixed income:
Corporate debt instruments		—		444		—		444
Government securities		307		794		—		1,101
Cash equivalents and other		34		—		—		34
Total assets	$	3,834	$	1,388		$157	$	5,379
Liabilities
Derivatives:
Commodity	$	—	$	190		$    7	$	197
Interest rate		—		85		—		85
Foreign currency		—		2		—		2
Total liabilities	$	—	$	277		$    7	$	284

(1) Includes investments held in the nuclear decommissioning and rabbi trusts. Excludes $220 million and $88 million of assets at December 31, 2018 and 2017, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation

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

	2018			2017			2016
(millions)
Balance at January 1,	$	150		$	139		$	95
Total realized and unrealized gains (losses):
Included in earnings:
Operating Revenue		(2	)		3			—
Electric fuel and other energy-related purchases		(15	)		(42	)		(35	)
Purchased gas		—			1			—
Included in other comprehensive income (loss)		1			(2	)		—
Included in regulatory assets/liabilities		(44	)		42			(39	)
Settlements		(27	)		6			38
Purchases		—			—			87
Transfers out of Level 3		1			3			(7	)
Balance at December 31,	$	64		$	150		$	139
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date:
Operating Revenue	$	—		$	2		$	—
Electric fuel and other energy-related purchases		—			—			(1	)

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

instruments. For the Companies’ financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:

December 31,	2018				2017
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion Energy
Long-term debt, including securities due within one year(2)	$	29,952		$31,045	$	28,666		$31,233
Credit facility borrowings		73		73		—		—
Junior subordinated notes(3)		3,430		3,358		3,981		4,102
Remarketable subordinated notes(3)		1,386		1,340		1,379		1,446
Virginia Power
Long-term debt, including securities due within one year(3)	$	11,671		$12,400	$	11,346		$12,842
Dominion Energy Gas
Long-term debt, including securities due within one year(4)	$	4,058		$  4,072	$	3,570		$  3,719

(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 issuances 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 or premium, and foreign currency remeasurement adjustments. At December 31, 2018, and 2017, includes the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt of $(20) million and $(22) million, respectively.

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

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

Virginia Electric and Power Company

Fair Value Inputs, Assets, Quantitative Information

The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2018. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques		Unobservable Input		Range		Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)		$38		Discounted cash flow		Market price (per Dth)(3)		(2)-8		(1	)
FTRs		15		Discounted cash flow		Market price (per MWh)(3)		(2)-7		1
Physical options:
Natural gas		2		Option model		Market price (per Dth)(3)		1-8		3
						Price volatility (4)		18%-73%		30	%
Electricity		11		Option model		Market price (per MWh)(3)		34-50		42
						Price volatility (4)		39%-60%		49	%
Total assets		$66
Liabilities
Financial forwards:
FTRs		$  6		Discounted cash flow		Market price (per MWh)(3)		(2)-6		—
Total liabilities		$  6

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

Fair Value, Option, Qualitative Disclosures

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)

Fair Value, by Balance Sheet Grouping

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)
December 31, 2018
Assets
Derivatives:
Commodity	$	—	$	24	$	66	$	90
Interest rate		—		3		—		3
Investments(1):
Equity securities:
U.S.		1,476		—		—		1,476
Fixed income:
Corporate debt instruments		—		221		—		221
Government securities		164		343		—		507
Total assets	$	1,640	$	591	$	66	$	2,297
Liabilities
Derivatives:
Commodity	$	—	$	9	$	6	$	15
Interest rate		—		88		—		88
Total liabilities	$	—	$	97	$	6	$	103
December 31, 2017
Assets
Derivatives:
Commodity	$	—	$	14	$	152	$	166
Investments(1):
Equity securities:
U.S.		1,566		—		—		1,566
Fixed income:
Corporate debt instruments		—		224		—		224
Government securities		168		326		—		494
Cash equivalents and other		16		—		—		16
Total assets	$	1,750	$	564	$	152	$	2,466
Liabilities
Derivatives:
Commodity	$	—	$	4	$	5	$	9
Interest rate		—		57		—		57
Total liabilities	$	—	$	61	$	5	$	66

(1) Includes investments held in the nuclear decommissioning trusts. Excludes $160 million and $27 million of assets at December 31, 2018 and 2017, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation

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

	2018			2017			2016
(millions)
Balance at January 1,	$	147		$	143		$	93
Total realized and unrealized gains (losses):
Included in earnings:
Electric fuel and other energy-related purchases		(17	)		(43	)		(35	)
Included in regulatory assets/liabilities		(45	)		40			(37	)
Settlements		(25	)		7			35
Purchases		—			—			87
Balance at December 31,	$	60		$	147		$	143

Dominion Energy Gas Holdings, LLC

Fair Value, by Balance Sheet Grouping

The following table presents Dominion Energy 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)
December 31, 2018
Assets
Commodity		$ —		$  3		$ —		$  3
Foreign currency		—		26		—		26
Total assets		$ —		$29		$ —		$29
Liabilities
Interest rate		$ —		$17		$ —		$17
Foreign currency		—		2		—		2
Total liabilities		$ —		$19		$ —		$19
December 31, 2017
Assets
Foreign currency		$ —		$32		$ —		$32
Total assets		$ —		$32		$ —		$32
Liabilities
Commodity		$ —		$  4		$   2		$  6
Foreign currency		—		2		—		2
Total liabilities		$ —		$  6		$   2		$  8

Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation

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

	2018			2017			2016
(millions)
Balance at January 1,	$	(2	)	$	(2	)	$	6
Total realized and unrealized gains (losses):
Included in other comprehensive income (loss)		1			(3	)		—
Transfers out of Level 3		1			3			(8	)
Balance at December 31,	$	—		$	(2	)	$	(2	)

XML

Derivatives And Hedge Accounting Activities (Tables)

12 Months Ended

Dec. 31, 2018

Offsetting Assets

The tables below present Dominion Energy’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

			December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	175	$	12	$	—	$	163	$	174	$	9	$	—	$	165
Exchange		68		68		—		—		80		80		—		—
Interest rate contracts:
Over-the-counter		18		1		—		17		17		8		—		9
Foreign currency contracts:
Over-the-counter		26		2		—		24		32		2		—		30
Total derivatives, subject to a master netting or similar arrangement	$	287	$	83	$	—	$	204	$	303	$	99	$	—	$	204

(1) Excludes $7 million and $4 million of derivative assets at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.

Offsetting Liabilities

	December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	19	$	12	$	—	$	7	$	76	$	9	$	6	$	61
Exchange		115		68		47		—		120		80		40		—
Interest rate contracts:
Over-the-counter		142		1		—		141		85		8		—		77
Foreign currency contracts:
Over-the-counter		2		2		—		—		2		2		—		—
Total derivatives, subject to a master netting or similar arrangement	$	278	$	83	$	47	$	148	$	283	$	99	$	46	$	138

(1) Excludes $1 million of derivative liabilities at December 31, 2018 and 2017, which are not subject to master netting or similar arrangements.

Schedule of Volume of Derivative Activity

The following table presents the volume of Dominion Energy’s derivative activity as of December 31, 2018. 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)		56		27
Basis		214		557
Electricity (MWh):
Fixed price(1)		11,101,869		1,537,200
FTRs		45,351,415		—
Liquids (Gal)(2)		14,413,200		—
Interest rate(3)	$	2,700,000,000	$	3,915,839,913
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.

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy’s Consolidated Balance Sheet at December 31, 2018:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12  Months After-Tax			Maximum Term
(millions)
Commodities:
Gas		$     —			$   1			36 months
Electricity		27			26			24 months
Other		2			2			3 months
Interest rate		(276	)		(29	)		396 months
Foreign currency		12			(2	)		90 months
Total		$(235	)		$ (2	)

Fair Value of Derivatives

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of Dominion Energy’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 December 31, 2018
ASSETS
Current Assets
Commodity		$  55		$154	$	209
Interest rate		14		—		14
Total current derivative assets(1)		69		154		223
Noncurrent Assets
Commodity		6		35		41
Interest rate		4		—		4
Foreign currency		26		—		26
Total noncurrent derivative assets(2)		36		35		71
Total derivative assets		$105		$189	$	294
LIABILITIES
Current Liabilities
Commodity		$  17		$112	$	129
Interest rate		26		—		26
Foreign currency		2		—		2
Total current derivative liabilities(3)		45		112		157
Noncurrent Liabilities
Commodity		5		1		6
Interest rate		116		—		116
Total noncurrent derivative liabilities(4)		121		1		122
Total derivative liabilities		$166		$113	$	279
At December 31, 2017
ASSETS
Current Assets
Commodity		$    5		$158	$	163
Interest rate		6		—		6
Total current derivative assets(1)		11		158		169
Noncurrent Assets
Commodity		—		95		95
Interest rate		11		—		11
Foreign currency		32		—		32
Total noncurrent derivative assets(2)		43		95		138
Total derivative assets		$  54		$253	$	307
LIABILITIES
Current Liabilities
Commodity		$103		$  92	$	195
Interest rate		53		—		53
Foreign currency		2		—		2
Total current derivative liabilities(3)		158		92		250
Noncurrent Liabilities
Commodity		1		1		2
Interest rate		32		—		32
Total noncurrent derivative liabilities(4)		33		1		34
Total derivative liabilities		$191		$  93	$	284

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

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

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

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

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location

The following tables present the gains and losses on Dominion Energy’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)
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$  (90	)
Electric fuel and other energy-related purchases					14
Total commodity		$  64			$(76	)		$ —
Interest rate(3)		(18	)		(48	)		39
Foreign currency(4)		(6	)		(13	)		—
Total		$  40			$(137	)		$39
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$  81
Purchased gas					(2	)
Total commodity		$    1			$  79			$ —
Interest rate(3)		(8	)		(52	)		(58	)
Foreign currency(4)		18			20			—
Total		$  11			$  47			$(58	)
Year Ended December 31, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$330
Purchased gas					(13	)
Electric fuel and other energy-related purchases					(10	)
Total commodity		$164			$307			$ —
Interest rate(3)		(66	)		(31	)		(26	)
Foreign currency(4)		(6	)		(17	)		—
Total		$  92			$259			$(26	)

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

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

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

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2018			2017			2016
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue		$(28	)		$  18			$  2
Purchased gas		11			(3	)		4
Electric fuel and other energy-related purchases		(9	)		(59	)		(70	)
Other operations & maintenance		—			(1	)		1
Total		$(26	)		$(45	)		$(63	)

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

Virginia Electric and Power Company

Offsetting Assets

The tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

	December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter		$64		$  6		$—		$58		$155		$  4		$—		$151
Interest rate contracts:
Over-the-counter		3		—		—		3		—		—		—		—
Total derivatives, subject to a master netting or similar arrangement		$67		$  6		$—		$61		$155		$  4		$—		$151

(1) Excludes $26 million and $11 million of derivative assets at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.

Offsetting Liabilities

	December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet						Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts:
Over-the-counter		$  6		$  6		$—		$—		$  4		$  4		$—		$ —
Interest rate contracts:
Over-the-counter		88		—		—		88		57		—		—		57
Total derivatives, subject to a master netting or similar arrangement		$94		$  6		$—		$88		$61		$  4		$—		$57

(1) Excludes $9 million and $5 million of derivative liabilities at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.

Schedule of Volume of Derivative Activity

The following table presents the volume of Virginia Power’s derivative activity at December 31, 2018. 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)		29		8
Basis		136		488
Electricity (MWh):
Fixed price(1)		367,019		—
FTRs		45,351,415		—
Interest rate(2)	$	700,000,000	$	1,200,000,000

(1) Includes options.

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

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)

The following table presents selected information related to losses on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at December 31, 2018:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Interest rate	$	(13	)	$	(1	)		396 months
Total	$	(13	)	$	(1	)

Fair Value of Derivatives

The following tables present 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 December 31, 2018
ASSETS
Current Assets
Commodity		$ —		$   60		$   60
Interest rate		3		—		3
Total current derivative assets(1)		3		60		63
Noncurrent Assets
Commodity		—		30		30
Total noncurrent derivative assets(2)		—		30		30
Total derivative assets		$  3		$   90		$   93
LIABILITIES
Current Liabilities
Commodity		$ —		$   15		$   15
Interest rate		10		—		10
Total current derivative liabilities(3)		10		15		25
Noncurrent Liabilities
Interest rate		78		—		78
Total noncurrent derivatives liabilities(4)		78		—		78
Total derivative liabilities		$88		$   15		$103
At December 31, 2017
ASSETS
Current Assets
Commodity		$ —		$   75		$   75
Total current derivative assets(1)		—		75		75
Noncurrent Assets
Commodity		—		91		91
Total noncurrent derivative assets(2)		—		91		91
Total derivative assets		$ —		$166		$166
LIABILITIES
Current Liabilities
Commodity		$ —		$     9		$     9
Interest rate		44		—		44
Total current derivative liabilities(3)		44		9		53
Noncurrent Liabilities
Interest rate		13		—		13
Total noncurrent derivative liabilities(4)		13		—		13
Total derivative liabilities		$57		$     9		$   66

(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.

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location

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)
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Interest rate(3)	$	2		$	(1	)	$	39
Total	$	2		$	(1	)	$	39
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Interest rate(3)	$	(8	)	$	(1	)	$	(58	)
Total	$	(8	)	$	(1	)	$	(58	)
Year Ended December 31, 2016
Derivative type and location of gains (losses):
Interest rate(3)	$	(3	)	$	(1	)	$	(26	)
Total	$	(3	)	$	(1	)	$	(26	)

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

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

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

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2018		2017		2016
(millions)
Derivative type and location of gains (losses):
Commodity(2)		$2		$(57)		$(70)
Total		$2		$(57)		$(70)

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

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

Dominion Energy Gas Holdings, LLC

Offsetting Assets

The tables below present Dominion Energy Gas’ derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

	December 31, 2018								December 31, 2017
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	3	$	—	$	—	$	3	$	—	$	—	$	—	$	—
Foreign currency contracts:
Over-the-counter		26		2		—		24		32		2		—		30
Total derivatives, subject to a master netting or similar arrangement	$	29	$	2	$	—	$	27	$	32	$	2	$	—	$	30

Offsetting Liabilities

	December 31, 2018								December 31, 2017
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Off set in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts
Over-the-counter	$	—	$	—	$	—	$	—	$	6	$	—	$	—	$	6
Interest rate contracts:
Over-the-counter		17		—		—		17		—		—		—		—
Foreign currency contracts:
Over-the-counter		2		2		—		—		2		2		—		—
Total derivatives, subject to a master netting or similar arrangement	$	19	$	2	$	—	$	17	$	8	$	2	$	—	$	6

Schedule of Volume of Derivative Activity

The following table presents the volume of Dominion Energy Gas’ derivative activity at December 31, 2018. 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
NGLs (Gal)		14,413,200		—
Interest rate(1)	$	300,000,000	$	750,000,000
Foreign currency(1)(2)	$	—	$	280,000,000

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

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

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2018:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
NGLs		$     2			$   2			3 months
Interest rate		(39	)		(4	)		312 months
Foreign currency		12			(2	)		90 months
Total		$(25	)		$(4	)

Fair Value of Derivatives

The following table presents the fair values of Dominion Energy 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 December 31, 2018
ASSETS
Current Assets
Commodity		$  3		$—		$  3
Total current derivative assets(1)		3		—		3
Noncurrent Assets
Foreign currency		26		—		26
Total noncurrent derivative assets(2)		26		—		26
Total derivative assets		$29		$—		$29
LIABILITIES
Current Liabilities
Interest rate		$  9		$—		$  9
Foreign currency		2		—		2
Total current derivative liabilities(3)		11		—		11
Noncurrent Liabilities
Interest rate		8		—		8
Total noncurrent derivative liabilities(4)		8		—		8
Total derivative liabilities		$19		$—		$19
At December 31, 2017
ASSETS
Noncurrent Assets
Foreign currency	$32		$—		$32
Total noncurrent derivative assets(2)		32		—		32
Total derivative assets		$32		$—		$32
LIABILITIES
Current Liabilities
Commodity		$  6		$—		$  6
Foreign currency		2		—		2
Total current derivative liabilities(3)		8		—		8
Total derivative liabilities		$  8		$—		$  8

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

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

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

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

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location

The following tables present the gains and losses on Dominion Energy 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)
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$  (8	)
Total commodity		$   1			$  (8	)
Interest rate(2)		(18	)		(6	)
Foreign currency(3)		(6	)		(13	)
Total		$(23	)		$(27	)
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$  (8	)
Total commodity		$(10	)		$  (8	)
Interest rate(2)		—			(5	)
Foreign currency(3)		18			20
Total		$   8			$   7
Year Ended December 31, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$   4
Total commodity		$(12	)		$   4
Interest rate(2)		(8	)		(2	)
Foreign currency(3)		(6	)		(17	)
Total		$(26	)		$(15	)

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

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

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

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives
Year Ended December 31,	2018			2017		2016
(millions)
Derivative type and location of gains (losses):
Commodity
Operating revenue		$(11	)		$—		$1
Total		$(11	)		$—		$1

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Earnings Per Share Computation

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

	2018		2017		2016
(millions, except EPS)
Net Income Attributable to Dominion Energy	$	2,447	$	2,999	$	2,123
Average shares of common stock outstanding – Basic		654.2		636.0		616.4
Net effect of dilutive securities(1)		0.7		—		0.7
Average shares of common stock outstanding – Diluted		654.9		636.0		617.1
Earnings Per Common Share – Basic	$	3.74	$	4.72	$	3.44
Earnings Per Common Share – Diluted	$	3.74	$	4.72	$	3.44

(1) Dilutive securities for 2018 consist primarily of forward sale agreements, effective April 2018 to December 2018. Dilutive securities for 2016 consist primarily of the 2013 Equity Units. See Notes 17 and 19 for more information.

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Investments (Tables)

12 Months Ended

Dec. 31, 2018

Equity and Debt Securities and Cash Equivalents and Cost Method Investments in Decommissioning Trust Funds

decommissioning costs for its nuclear plants. Dominion Energy’s decommissioning trust funds are summarized below:

	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Fair Value
(millions)
December 31, 2018
Equity securities:(1)
U.S.		$1,741		$1,640		$(51)			$3,330
Fixed income securities:(2)
Corporate debt instruments		435		5		(9)			431
Government securities		1,092		17		(12)			1,097
Common/collective trust funds		76		—		—			76
Cash equivalents and other(3)		4		—		—			4
Total		$3,348		$1,662		$(72)	(4)		$4,938
December 31, 2017
Equity securities:(2)
U.S.		$1,569		$1,857		$ —			$3,426
Fixed income securities:(2)
Corporate debt instruments		430		15		(1)			444
Government securities		1,039		27		(5)			1,061
Common/collective trust funds		60		—		—			60
Cost method investments		68		—		—			68
Cash equivalents and other(3)		34		—		—			34
Total		$3,200		$1,899		$  (6)	(4)		$5,093

(1) Effective January 2018, unrealized gains and losses on equity securities, including those previously classified as cost method investments, are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(2) Unrealized gains and losses on equity securities (for 2017) and fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(3) Includes pending sales of securities of $5 million at December 31, 2017.

(4) The fair value of securities in an unrealized loss position was $833 million and $565 million at December 31, 2018 and 2017, respectively.

Unrealized Gain Loss on Equity

The portion of unrealized gains and losses that relates to equity securities held within Dominion Energy’s nuclear decommissioning trusts is summarized below:

	Twelve Months Ended December 31, 2018
(millions)
Net losses recognized during the period	$	(245	)
Less: Net gains recognized during the period on securities sold during the period		(58	)
Unrealized losses recognized during the period on securities still held at December 31, 2018(1)	$	(303	)

(1) Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

Investments Classified by Contractual Maturity Date

The fair value of Dominion Energy’s debt securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2018 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	167
Due after one year through five years		389
Due after five years through ten years		376
Due after ten years		672
Total	$	1,604

Marketable Securities

Presented below is selected information regarding Dominion Energy’s equity and debt securities with readily determinable fair values held in nuclear decommissioning trust funds.

Year Ended December 31,	2018		2017		2016
(millions)
Proceeds from sales	$	1,804	$	1,831	$	1,422
Realized gains(1)		140		166		128
Realized losses(1)		91		71		55

(1) Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.

Other-Than-Temporary Impairment Losses

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

Year Ended December 31,	2018			2017			2016
(millions)
Total other-than-temporary impairment losses(1)	$	30		$	44		$	51
Losses recorded to the nuclear decommissioning trust regulatory liability		—			(16	)		(16	)
Losses recognized in other comprehensive income (before taxes)		(30	)		(5	)		(12	)
Net impairment losses recognized in earnings	$	—		$	23		$	23

(1) Amounts include other-than-temporary impairment losses for debt securities of $5 million and $13 million at December 31, 2017 and 2016, respectively.

Investments Accounts Under Equity Method of Accounting

Investments that Dominion Energy and Dominion Energy Gas account for under the equity method of accounting are as follows:

Company	Ownership%			Investment Balance				Description
As of December 31,				2018		2017
(millions)
Dominion Energy
Atlantic Coast Pipeline		48	%	$	820	$	382		Gas transmission system
Blue Racer		50	%		—		691		Midstream gas and     related services
Iroquois		50	%(1)		302		311		Gas transmission system
Fowler Ridge		50	%		82		81		Wind-powered merchant     generation facility
Other(2)		various			74		79
Total				$	1,278	$	1,544
Dominion Energy Gas
Iroquois		24.07	%	$	91	$	95		Gas transmission system
Total				$	91	$	95

(1) Comprised of Dominion Energy Midstream’s interest of 25.93% and Dominion Energy Gas’ interest of 24.07%. See Note 15 for more information.

(2) Liability of less than $1 million and $17 million associated with NedPower recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets as of December 31, 2018 and 2017, respectively. See additional discussion of NedPower below.

Virginia Electric and Power Company

Equity and Debt Securities and Cash Equivalents and Cost Method Investments in Decommissioning Trust Funds

decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below:

	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Fair Value
(millions)
December 31, 2018
Equity securities:(1)
U.S.		$858		$751		$(24	)		$1,585
Fixed income securities:(2)
Corporate debt instruments		224		2		(5	)		221
Government securities		504		7		(5	)		506
Common/collective trust funds		51		—		—			51
Cash equivalents and other(3)		6		—		—			6
Total		$1,643		$760		$(34)	(4)		$2,369
December 31, 2017
Equity securities:(2)
U.S.		$   734		$831		$—			$1,565
Fixed income securities:(2)
Corporate debt instruments		216		8		—			224
Government securities		482		13		(2	)		493
Common/collective trust funds		27		—		—			27
Cost method investments		68		—		—			68
Cash equivalents and other(3)		22		—		—			22
Total		$1,549		$852		$(2	)(4)		$2,399

(1) Effective January 2018, unrealized gains and losses on equity securities, including those previously classified as cost method investments, are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(2) Unrealized gains and losses on equity securities (for 2017) and fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(3) Includes pending sales of securities of $6 million at both December 31, 2018 and 2017.

(4) The fair value of securities in an unrealized loss position was $404 million and $234 million at December 31, 2018 and 2017, respectively.

Unrealized Gain Loss on Equity

The portion of unrealized gains and losses that relates to equity securities held within Virginia Power’s nuclear decommissioning trusts is summarized below:

	Twelve Months Ended December 31, 2018
(millions)
Net losses recognized during the period	$	(105	)
Less: Net gains recognized during the period on securities sold during the period		(32	)
Unrealized losses recognized during the period on securities still held at December 31, 2018(1)	$	(137	)

(1) Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

Investments Classified by Contractual Maturity Date

The fair value of Virginia Power’s debt securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2018, by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	54
Due after one year through five years		156
Due after five years through ten years		210
Due after ten years		358
Total	$	778

Marketable Securities

Presented below is selected information regarding Virginia Power’s equity and debt securities with readily determinable fair values held in nuclear decommissioning trust funds.

Year Ended December 31,	2018		2017		2016
(millions)
Proceeds from sales	$	887	$	849	$	733
Realized gains(1)		60		75		63
Realized losses(1)		27		30		27

(1) Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.

Other-Than-Temporary Impairment Losses

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

Year Ended December 31,	2018			2017			2016
(millions)
Total other-than-temporary impairment losses(1)	$	15		$	20		$	26
Losses recorded to the nuclear decommissioning trust regulatory liability		—			(16	)		(16	)
Losses recognized in other comprehensive income (before taxes)		(15	)		(2	)		(7	)
Net impairment losses recognized in earnings	$	—		$	2		$	3

(1) Amounts include other-than-temporary impairment losses for debt securities of $2 million and $8 million at December 31, 2017 and 2016 , respectively.

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Schedule of Regulatory Assets

Regulatory assets and liabilities include the following:

At December 31,	2018		2017
(millions)
Dominion Energy
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	174	$	23
Deferred rate adjustment clause costs(2)		96		70
Deferred nuclear refueling outage costs(3)		69		54
Unrecovered gas costs(4)		14		38
Other		143		109
Regulatory assets-current		496		294
Unrecognized pension and other postretirement benefit costs(5)		1,497		1,336
Deferred rate adjustment clause costs(2)		329		401
Utility reform legislation(6)		204		147
PJM transmission rates(7)		192		222
Derivatives(8)		184		223
Deferred cost of fuel used in electric generation(1)		83		—
Other		187		151
Regulatory assets-noncurrent		2,676		2,480
Total regulatory assets	$	3,172	$	2,774
Regulatory liabilities:
Provision for future cost of removal and AROs(9)	$	117	$	101
Cost-of-service impact of 2017 Tax Reform Act(10)		104		—
Reserve for rate credits to electric utility customers(11)		71		—
Other		64		92
Regulatory liabilities-current(12)		356		193
Income taxes refundable through future rates(13)		4,071		4,058
Provision for future cost of removal and AROs(9)		1,409		1,384
Nuclear decommissioning trust(14)		1,070		1,121
Derivatives(8)		25		69
Other		265		284
Regulatory liabilities-noncurrent		6,840		6,916
Total regulatory liabilities	$	7,196	$	7,109
Virginia Power
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	174	$	23
Deferred rate adjustment clause costs(2)		78		56
Deferred nuclear refueling outage costs(3)		69		54
Other		103		72
Regulatory assets-current		424		205
Deferred rate adjustment clause costs(2)		230		312
PJM transmission rates(7)		192		222
Derivatives(8)		151		190
Deferred cost of fuel used in electric generation(1)		83		—
Other		81		86
Regulatory assets-noncurrent		737		810
Total regulatory assets	$	1,161	$	1,015
Regulatory liabilities:
Cost-of-service impact of 2017 Tax Reform Act(10)	$	95	$	—
Provision for future cost of removal(9)		92		80
Reserve for rate credits to customers(11)		71		—
Other		41		47
Regulatory liabilities-current		299		127
Income taxes refundable through future rates(13)		2,579		2,581
Nuclear decommissioning trust(14)		1,070		1,121
Provision for future cost of removal(9)		940		915
Derivatives(8)		25		69
Other		33		74
Regulatory liabilities-noncurrent		4,647		4,760
Total regulatory liabilities	$	4,946	$	4,887
Dominion Energy Gas
Regulatory assets:
Deferred rate adjustment clause costs(2)	$	18	$	14
Unrecovered gas costs(4)		9		8
Other		2		4
Regulatory assets-current(16)		29		26
Unrecognized pension and other postretirement benefit costs(5)		392		258
Utility reform legislation(6)		204		147
Deferred rate adjustment clause costs(2)		99		89
Other		32		17
Regulatory assets-noncurrent		727		511
Total regulatory assets	$	756	$	537
Regulatory liabilities:
Provision for future cost of removal and AROs(9)	$	14	$	13
PIPP(15)		3		20
Other		4		5
Regulatory liabilities-current(12)		21		38
Income taxes refundable through future rates(13)		1,011		998
Provision for future cost of removal and AROs(9)		158		160
Cost-of-service impact of 2017 Tax Reform Act(10)		19		—
Other		97		69
Regulatory liabilities-noncurrent		1,285		1,227
Total regulatory liabilities	$	1,306	$	1,265

 (1) Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Dominion Energy and Virginia Power’s generation operations. See Note 13 for more information.

 (2) Primarily reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects net of income taxes refundable from the 2017 Tax Reform Act for Virginia Power and deferrals of costs associated with certain current and prospective rider projects for Dominion Energy Gas. See Note 13 for more information.

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

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

 (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 Energy and Dominion Energy Gas’ rate-regulated subsidiaries.

 (6) Ohio legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future.

 (7) Reflects amounts related to the PJM transmission cost allocation matter. See Note 13 for more information.

 (8) As discussed under Derivative Instruments in Note 2, 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.

 (9) 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.

(10) Balance refundable to customers related to the decrease in revenue requirements for recovery of income taxes at the Companies’ regulated electric generation and electric and natural gas distribution operations. See Note 13 for more information.

(11) Charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers. See Note 13 for more information.

(12) Current regulatory liabilities are presented in other current liabilities in Dominion Energy and Dominion Energy Gas’ Consolidated Balance Sheets.

(13) Amounts recorded to pass the effect of reduced income tax rates from the 2017 Tax Reform Act to customers in future periods, which will reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity.

(14) 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.

(15) 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 rider according to East Ohio tariff provisions. See Note 13 for more information.

(16) Current regulatory assets are presented in other current assets in Dominion Energy Gas’ Consolidated Balance Sheets.

Schedule of Regulatory Liabilities

Regulatory assets and liabilities include the following:

At December 31,	2018		2017
(millions)
Dominion Energy
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	174	$	23
Deferred rate adjustment clause costs(2)		96		70
Deferred nuclear refueling outage costs(3)		69		54
Unrecovered gas costs(4)		14		38
Other		143		109
Regulatory assets-current		496		294
Unrecognized pension and other postretirement benefit costs(5)		1,497		1,336
Deferred rate adjustment clause costs(2)		329		401
Utility reform legislation(6)		204		147
PJM transmission rates(7)		192		222
Derivatives(8)		184		223
Deferred cost of fuel used in electric generation(1)		83		—
Other		187		151
Regulatory assets-noncurrent		2,676		2,480
Total regulatory assets	$	3,172	$	2,774
Regulatory liabilities:
Provision for future cost of removal and AROs(9)	$	117	$	101
Cost-of-service impact of 2017 Tax Reform Act(10)		104		—
Reserve for rate credits to electric utility customers(11)		71		—
Other		64		92
Regulatory liabilities-current(12)		356		193
Income taxes refundable through future rates(13)		4,071		4,058
Provision for future cost of removal and AROs(9)		1,409		1,384
Nuclear decommissioning trust(14)		1,070		1,121
Derivatives(8)		25		69
Other		265		284
Regulatory liabilities-noncurrent		6,840		6,916
Total regulatory liabilities	$	7,196	$	7,109
Virginia Power
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	174	$	23
Deferred rate adjustment clause costs(2)		78		56
Deferred nuclear refueling outage costs(3)		69		54
Other		103		72
Regulatory assets-current		424		205
Deferred rate adjustment clause costs(2)		230		312
PJM transmission rates(7)		192		222
Derivatives(8)		151		190
Deferred cost of fuel used in electric generation(1)		83		—
Other		81		86
Regulatory assets-noncurrent		737		810
Total regulatory assets	$	1,161	$	1,015
Regulatory liabilities:
Cost-of-service impact of 2017 Tax Reform Act(10)	$	95	$	—
Provision for future cost of removal(9)		92		80
Reserve for rate credits to customers(11)		71		—
Other		41		47
Regulatory liabilities-current		299		127
Income taxes refundable through future rates(13)		2,579		2,581
Nuclear decommissioning trust(14)		1,070		1,121
Provision for future cost of removal(9)		940		915
Derivatives(8)		25		69
Other		33		74
Regulatory liabilities-noncurrent		4,647		4,760
Total regulatory liabilities	$	4,946	$	4,887
Dominion Energy Gas
Regulatory assets:
Deferred rate adjustment clause costs(2)	$	18	$	14
Unrecovered gas costs(4)		9		8
Other		2		4
Regulatory assets-current(16)		29		26
Unrecognized pension and other postretirement benefit costs(5)		392		258
Utility reform legislation(6)		204		147
Deferred rate adjustment clause costs(2)		99		89
Other		32		17
Regulatory assets-noncurrent		727		511
Total regulatory assets	$	756	$	537
Regulatory liabilities:
Provision for future cost of removal and AROs(9)	$	14	$	13
PIPP(15)		3		20
Other		4		5
Regulatory liabilities-current(12)		21		38
Income taxes refundable through future rates(13)		1,011		998
Provision for future cost of removal and AROs(9)		158		160
Cost-of-service impact of 2017 Tax Reform Act(10)		19		—
Other		97		69
Regulatory liabilities-noncurrent		1,285		1,227
Total regulatory liabilities	$	1,306	$	1,265

 (1) Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Dominion Energy and Virginia Power’s generation operations. See Note 13 for more information.

 (2) Primarily reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects net of income taxes refundable from the 2017 Tax Reform Act for Virginia Power and deferrals of costs associated with certain current and prospective rider projects for Dominion Energy Gas. See Note 13 for more information.

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

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

 (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 Energy and Dominion Energy Gas’ rate-regulated subsidiaries.

 (6) Ohio legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future.

 (7) Reflects amounts related to the PJM transmission cost allocation matter. See Note 13 for more information.

 (8) As discussed under Derivative Instruments in Note 2, 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.

 (9) 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.

(10) Balance refundable to customers related to the decrease in revenue requirements for recovery of income taxes at the Companies’ regulated electric generation and electric and natural gas distribution operations. See Note 13 for more information.

(11) Charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers. See Note 13 for more information.

(12) Current regulatory liabilities are presented in other current liabilities in Dominion Energy and Dominion Energy Gas’ Consolidated Balance Sheets.

(13) Amounts recorded to pass the effect of reduced income tax rates from the 2017 Tax Reform Act to customers in future periods, which will reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity.

(14) 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.

(15) 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 rider according to East Ohio tariff provisions. See Note 13 for more information.

(16) Current regulatory assets are presented in other current assets in Dominion Energy Gas’ Consolidated Balance Sheets.

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Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Summary of Additional Significant Riders Associated with Virginia Power Projects

Additional significant riders associated with various Virginia Power projects are as follows:

Rider Name	Application Date	Approval Date	Rate Year Beginning	Total Revenue Requirement (millions)		Increase (Decrease) Over Previous Year (millions)
Rider S	June 2018	February 2019	April 2019	$	215	$	(3	)
Rider GV	June 2018	February 2019	April 2019		120		38
Rider W	June 2018	February 2019	April 2019		105		(4	)
Rider R	June 2018	February 2019	April 2019		57		(9	)
Rider B	June 2018	February 2019	April 2019		38		(9	)
Rider BW	October 2018	Pending	September 2019		123		7
Rider US-2	October 2018	Pending	September 2019		16		3
Rider E	December 2018	Pending	November 2019		114		N/A

Summary of Additional Significant Virginia Power Electric Transmission Projects Approved and Applied

Additional significant Virginia Power electric transmission projects approved and applied for in 2018 are as follows:

Description and Location of Project	Application Date	Approval Date	Type of Line		Miles of Lines		Cost Estimate (millions)
Rebuild and operate existing 115 kV transmission lines between the Possum Point Switching Station and Northern Virginia Electric Cooperative’s Smoketown delivery point	June 2017	February 2018		230 kV		9	$	20
Rebuild and operate between the Dooms substation and the Valley substation, along with associated substation work	September 2017	September 2018		500 kV		18		65
Build and operate between the Idylwood and Tysons substations, along with associated substation work	November 2017	September 2018		230 kV		4		125
Rebuild and operate between the Chesterfield and Hopewell substations, along with associated substation work	May 2018	November 2018		230 kV		8		30
Rebuild and operate between the Chesterfield and Lakeside substations, along with associated substation work	May 2018	December 2018		230 kV		21		35
Rebuild and operate between the Landstown and Thrasher substations, along with associated substation work	June 2018	December 2018		230 kV		8.5		20
Partial rebuild of overhead transmission lines in Alleghany County, Virginia and Covington, Virginia	August 2018	Pending		138 kV		5		15
Build a new substation and connect three existing transmission lines thereto in Fluvanna County, Virginia	October 2018	Pending		230 kV		<1		30

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Changes to Asset Retirement Obligations

The changes to AROs during 2017 and 2018 were as follows:

	Amount
(millions)
Dominion Energy
AROs at December 31, 2016	$	2,485
Obligations incurred during the period		37
Obligations settled during the period		(214	)
Revisions in estimated cash flows		7
Accretion		117
AROs at December 31, 2017(1)	$	2,432
Obligations incurred during the period		20
Obligations settled during the period		(159	)
Revisions in estimated cash flows(2)		120
Accretion		119
AROs at December 31, 2018(1)	$	2,532
Virginia Power
AROs at December 31, 2016	$	1,443
Obligations incurred during the period		11
Obligations settled during the period		(152	)
Revisions in estimated cash flows		(1	)
Accretion		64
AROs at December 31, 2017	$	1,365
Obligations incurred during the period		14
Obligations settled during the period		(119	)
Revisions in estimated cash flows(2)		120
Accretion		65
AROs at December 31, 2018	$	1,445
Dominion Energy Gas
AROs at December 31, 2016	$	156
Obligations incurred during the period		2
Obligations settled during the period		(7	)
Accretion		9
AROs at December 31, 2017(3)	$	160
Obligations incurred during the period		4
Obligations settled during the period		(6	)
Accretion		9
AROs at December 31, 2018(3)	$	167

(1) Includes $263 million and $282 million reported in other current liabilities at December 31, 2017, and 2018, respectively.

(2) Reflects future ash pond and landfill closure costs at certain utility generation facilities. See Note 22 for further information.

(3) Includes $146 million and $153 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities, at December 31, 2017 and 2018, respectively.

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Equity (Tables)

12 Months Ended

Dec. 31, 2018

Schedule of Accumulated Other Comprehensive Income (Loss)

Presented in the table below is a summary of AOCI by component:

At December 31,	2018			2017
(millions)
Dominion Energy
Net deferred losses on derivatives-hedging activities, net of $79 and $188 tax	$	(234	)	$	(301	)
Net unrealized gains on nuclear decommissioning trust funds, net of $— and $(419) tax		2			747
Net unrecognized pension and other postretirement benefit costs, net of $519 and $692 tax		(1,465	)		(1,101	)
Other comprehensive loss from equity method investees, net of $— and $2 tax		(2	)		(3	)
Total AOCI, including noncontrolling interest	$	(1,699	)	$	(658	)
Less other comprehensive income attributable to noncontrolling interest		1			1
Total AOCI, excluding noncontrolling interest	$	(1,700	)	$	(659	)
Virginia Power
Net deferred losses on derivatives-hedging activities, net of $4 and $8 tax	$	(13	)	$	(12	)
Net unrealized gains on nuclear decommissioning trust funds, net of $— and $(47) tax		1			74
Total AOCI	$	(12	)	$	62
Dominion Energy Gas
Net deferred losses on derivatives-hedging activities, net of $8 and $15 tax	$	(25	)	$	(23	)
Net unrecognized pension costs, net of $56 and $59 tax		(144	)		(75	)
Total AOCI	$	(169	)	$	(98	)

DOMINION ENERGY

The following table presents Dominion Energy’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 loss from equity method investees			Total
(millions)
Year Ended December 31, 2018
Beginning balance		$(302	)		$ 747			$(1,101	)		$(3	)		$(659	)
Other comprehensive income before reclassifications: gains (losses)		30			(18	)		(215	)		1			(202	)
Amounts reclassified from AOCI: (gains) losses(1)		102			5			78			—			185
Net current period other comprehensive income (loss)		132			(13)			(137	)		1			(17	)
Cumulative-effect of changes in accounting principle		(64	)		(732)			(227	)		—			(1,023	)
Less other comprehensive income (loss) attributable to noncontrolling interest		1			—			—			—			1
Ending balance		$(235	)		$2			$(1,465	)		$(2	)		$(1,700	)
Year Ended December 31, 2017
Beginning balance		$(280	)		$ 569			$(1,082	)		$(6	)		$  (799	)
Other comprehensive income before reclassifications: gains (losses)		8			215			(69	)		3			157
Amounts reclassified from AOCI: (gains) losses(1)		(29	)		(37	)		50			—			(16	)
Net current period other comprehensive income (loss)		(21	)		178			(19	)		3			141
Less other comprehensive income (loss) attributable to noncontrolling interest		1			—			—			—			1
Ending balance		$(302	)		$ 747			$(1,101	)		$(3	)		$  (659	)

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

Reclassification out of Accumulated Other Comprehensive Income

The following table presents Dominion Energy’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)
Year Ended December 31, 2018
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$90			Operating revenue
		(14	)		Electric fuel and other energy-related purchases
Interest rate contracts		48			Interest and related charges
Foreign currency contracts		13			Other Income
Total		137
Tax		(35	)		Income tax expense
Total, net of tax		$102
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities		$7			Other income
Total		7
Tax		(2	)		Income tax expense
Total, net of tax		$5
Unrecognized pension and other postretirement benefit costs:
Amortization of prior-service costs (credits)		$(21	)		Other income
Amortization of actuarial losses		120			Other income
Total		99
Tax		(21	)		Income tax expense
Total, net of tax		$78
Year Ended December 31, 2017
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$(81	)		Operating revenue
		2			Purchased gas
Interest rate contracts		52			Interest and related charges
Foreign currency contracts		(20	)		Other Income
Total		(47	)
Tax		18			Income tax expense
Total, net of tax		$(29	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities		$(81	)		Other income
Impairment		23			Other income
Total		(58	)
Tax		21			Income tax expense
Total, net of tax		$(37	)
Unrecognized pension and other postretirement benefit costs:
Prior-service costs (credits)		$(21	)		Other income
Actuarial losses		103			Other income
Total		82
Tax		(32	)		Income tax expense
Total, net of tax		$50

Summary of Restricted Stock Activity

The following table provides a summary of restricted stock activity for the years ended December 31, 2018, 2017 and 2016:

	Shares			Weighted —average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2015		855			$66.16
Granted		372			71.67
Vested		(301	)		56.83
Cancelled and forfeited		(40	)		71.75
Nonvested at December 31, 2016		886			$71.40
Granted		454			74.24
Vested		(287	)		68.90
Cancelled and forfeited		(10	)		72.37
Nonvested at December 31, 2017		1,043			$73.32
Granted		534			72.92
Vested		(316	)		73.59
Cancelled and forfeited		(53	)		74.25
Nonvested at December 31, 2018		1,208			$73.03

Virginia Electric and Power Company

Schedule of Accumulated Other Comprehensive Income (Loss)

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

	Deferred gains and losses on derivatives- hedging activities			Unrealized gains and losses on investment securities			Total
(millions)
Year Ended December 31, 2018
Beginning balance	$	(12)		$	74			$ 62
Other comprehensive income before reclassifications: gains (losses)		1			—			1
Amounts reclassified from AOCI: (gains) losses(1)		1			—			1
Net current period other comprehensive income (loss)		2			—			2
Cumulative-effect of changes in accounting principle		(3	)		(73	)		(76	)
Ending balance	$	(13	)	$	1			$(12	)
Year Ended December 31, 2017
Beginning balance	$	(8	)	$	54			$ 46
Other comprehensive income before reclassifications: gains (losses)		(5	)		24			19
Amounts reclassified from AOCI: gains (losses)(1)		1			(4	)		(3	)
Net current period other comprehensive income (loss)		(4	)		20			16
Ending balance	$	(12	)	$	74			$ 62

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

Reclassification out of Accumulated Other Comprehensive Income

The following table presents Virginia Power’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)
Year Ended December 31, 2018
(Gains) losses on cash flow hedges:
Interest rate contracts		$ 1			Interest and related charges
Total		1
Tax		—			Income tax expense
Total, net of tax		$ 1
Year Ended December 31, 2017
(Gains) losses on cash flow hedges:
Interest rate contracts		$ 1			Interest and related charges
Total		1
Tax		—			Income tax expense
Total, net of tax		$ 1
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities		$(9	)		Other income
Impairment		2			Other income
Total		(7	)
Tax		3			Income tax expense
Total, net of tax		$(4	)

Dominion Energy Gas Holdings, LLC

Schedule of Accumulated Other Comprehensive Income (Loss)

The following table presents Dominion Energy 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)
Year Ended December 31, 2018
Beginning balance		$(23	)		$  (75	)	$	(98	)
Other comprehensive income before reclassifications: gains (losses)		(17	)		(52	)		(69	)
Amounts reclassified from AOCI: (gains) losses(1)		20			4			24
Net current period other comprehensive income (loss)		3			(48	)		(45	)
Cumulative-effect of changes in accounting principle		(5	)		(21	)		(26	)
Ending balance		$(25	)		$(144	)	$	(169	)
Year Ended December 31, 2017
Beginning balance		$(24	)		$  (99	)	$	(123	)
Other comprehensive income before reclassifications: gains (losses)		5			20			25
Amounts reclassified from AOCI: gains (losses)(1)		(4	)		4			—
Net current period other comprehensive income (loss)		1			24			25
Ending balance		$(23	)		$  (75	)	$	(98	)

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

Reclassification out of Accumulated Other Comprehensive Income

The following table presents Dominion Energy 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)
Year Ended December 31, 2018
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$   8		Operating revenue
Interest rate contracts		6		Interest and related charges
Foreign currency contracts		13		Other income
Total		27
Tax		(7	)	Income tax expense
Total, net of tax		$ 20
Unrecognized pension costs:
Actuarial losses		$   6		Other income
Total		6
Tax		(2	)	Income tax expense
Total, net of tax		$   4
Year Ended December 31, 2017
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$   8		Operating revenue
Interest rate contracts		5		Interest and related charges
Foreign currency contracts		(20	)	Other income
Total		(7	)
Tax		3		Income tax expense
Total, net of tax		$  (4	)
Unrecognized pension costs:
Actuarial losses		$   6		Other income
Total		6
Tax		(2	)	Income tax expense
Total, net of tax		$   4

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans funded status

The following table summarizes the changes in pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units):

	Pension Benefits						Other Postretirement Benefits
Year Ended December 31,	2018			2017			2018			2017
(millions, except percentages)
Dominion Energy
Changes in benefit obligation:
Benefit obligation at beginning of year	$	9,052		$	8,132		$	1,529		$	1,478
Service cost		157			138			27			26
Interest cost		337			345			56			60
Benefits paid		(358	)		(323	)		(87	)		(83	)
Actuarial (gains) losses during the year		(688	)		830			(158	)		119
Plan amendments(1)		—			5			(4	)		(73	)
Settlements and curtailments(2)		—			(75	)		—			2
Benefit obligation at end of year	$	8,500		$	9,052		$	1,363		$	1,529
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	8,062		$	7,016		$	1,729		$	1,512
Actual return (loss) on plan assets		(513	)		1,327			(92	)		236
Employer contributions		6			118			12			13
Benefits paid		(358	)		(323	)		(68	)		(32	)
Settlements(2)		—			(76	)		—			—
Fair value of plan assets at end of year	$	7,197		$	8,062		$	1,581		$	1,729
Funded status at end of year	$	(1,303	)	$	(990	)	$	218		$	200
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	$	1,003		$	1,117		$	276		$	261
Other current liabilities		(34	)		(8	)		(2	)		—
Noncurrent pension and other postretirement benefit liabilities		(2,272	)		(2,099	)		(56	)		(61	)
Net amount recognized	$	(1,303	)	$	(990	)	$	218		$	200
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate		4.42%–4.43%			3.80%–3.81%			4.37%–4.38%			3.76%
Weighted average rate of increase for compensation		4.32%			4.09%			4.30%-4.55%			3.95%-4.11%
Dominion Energy Gas
Changes in benefit obligation:
Benefit obligation at beginning of year	$	773		$	683		$	290		$	320
Service cost		18			15			4			4
Interest cost		29			30			11			12
Benefits paid		(34	)		(33	)		(18	)		(19	)
Actuarial (gains) losses during the year		(56	)		78			(27	)		34
Plan amendments(1)		—			—			(4	)		(61	)
Benefit obligation at end of year	$	730		$	773		$	256		$	290
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	1,803		$	1,542		$	333		$	299
Actual return (loss) on plan assets		(113	)		294			(16	)		41
Employer contributions		—			—			12			12
Benefits paid		(34	)		(33	)		(18	)		(19	)
Fair value of plan assets at end of year	$	1,656		$	1,803		$	311		$	333
Funded status at end of year	$	926		$	1,030		$	55		$	43
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	$	926		$	1,030		$	63		$	57
Noncurrent pension and other postretirement benefit liabilities(3)		—			—			(8	)		(14	)
Net amount recognized	$	926		$	1,030		$	55		$	43
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate		4.42	%		3.81	%		4.37	%		3.76	%
Weighted average rate of increase for compensation		4.55	%		4.11	%		n/a			n/a

(1) 2017 amounts relate primarily to a plan amendment that changed post-65 retiree medical coverage for certain current and future Local 69 retirees effective July 1, 2017.

(2) 2017 amount relates primarily to settlement and curtailment as a result of the voluntary and involuntary separation programs at Dominion Energy Questar.

(3) Reflected in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.

Benefit obligation in excess of plan asset

The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units):

	Pension Benefits				Other Postretirement Benefits
As of December 31,	2018		2017		2018		2017
(millions)
Dominion Energy
Benefit obligation	$	7,705	$	8,209		$164		$191
Fair value of plan assets		5,398		6,103		136		156
Dominion Energy Gas
Benefit obligation	$	—	$	—		$134		$157
Fair value of plan assets		—		—		126		143

Accumulated benefit obligation in excess of plan assets

The following table provides information on the ABO and fair value of plan assets for Dominion Energy’s pension plans with an ABO in excess of plan assets:

As of December 31,	2018		2017
(millions)
Accumulated benefit obligation	$	7,056	$	7,392
Fair value of plan assets		5,398		6,103

Benefit payments expected future service

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans:

	Estimated Future Benefit Payments
	Pension Benefits		Other Postretirement Benefits
(millions)
Dominion Energy
2019		$407		$98
2020		405		99
2021		426		99
2022		442		99
2023		465		98
2024-2028	2,548		461
Dominion Energy Gas
2019		$37		$19
2020		39		19
2021		40		19
2022		42		19
2023		43		19
2024-2028		223		90

Fair values of pension and post retirement plan assets by asset category

The fair values of Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) pension plan assets by asset category are as follows:

At December 31,	2018								2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Dominion Energy
Cash and cash equivalents	$	17	$	1		$—	$	18	$	18	$	—		$—	$	18
Common and preferred stocks:
U.S.		1,645		—		—		1,645		1,902		—		—		1,902
International		1,061		—		—		1,061		1,151		—		—		1,151
Insurance contracts		—		318		—		318		—		352		—		352
Corporate debt instruments		23		729		—		752		41		729		—		770
Government securities		25		605		—		630		9		676		—		685
Total recorded at fair value	$	2,771	$	1,653		$—	$	4,424	$	3,121	$	1,757		$—	$	4,878
Assets recorded at NAV(1):
Common/collective trust funds								1,849								2,272
Alternative investments:
Real estate funds								108								111
Private equity funds								633								606
Debt funds								155								161
Hedge funds								17								19
Total recorded at NAV							$	2,762							$	3,169
Total investments(2)							$	7,186							$	8,047
Dominion Energy Gas
Cash and cash equivalents	$	4	$	—		$—	$	4	$	4	$	—		$—	$	4
Common and preferred stocks:
U.S.		378		—		—		378		425		—		—		425
International		244		—		—		244		257		—		—		257
Insurance contracts		—		73		—		73		—		79		—		79
Corporate debt instruments		5		168		—		173		9		163		—		172
Government securities		6		139		—		145		2		151		—		153
Total recorded at fair value	$	637	$	380		$—	$	1,017	$	697	$	393		$—	$	1,090
Assets recorded at NAV(1):
Common/collective trust funds								425								509
Alternative investments:
Real estate funds								25								25
Private equity funds								146								135
Debt funds								36								36
Hedge funds								4								4
Total recorded at NAV							$	636							$	709
Total investments(3)							$	1,653							$	1,799

(1) These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

(2) Excludes net assets related to pending sales of securities of $12 million, net accrued income of $21 million, and includes net assets related to pending purchases of securities of $22 million at December 31, 2018. Excludes net assets related to pending sales of securities of $11 million, net accrued income of $19 million, and includes net assets related to pending purchases of securities of $15 million at December 31, 2017.

(3) Excludes net assets related to pending sales of securities of $3 million, net accrued income of $5 million, and includes net assets related to pending purchases of securities of $5 million at December 31, 2018. Excludes net assets related to pending sales of securities of $3 million, net accrued income of $4 million, and includes net assets related to pending purchases of securities of $3 million at December 31, 2017.

The fair values of Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) other postretirement plan assets by asset category are as follows:

At December 31,	2018								2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Dominion Energy
Cash and cash equivalents		$1		$1		$—	$	2		$1		$2		$—		$3
Common and preferred stocks:
U.S.		554		—		—		554		636		—		—		636
International		170		—		—		170		196		—		—		196
Insurance contracts		—		19		—		19		—		21		—		21
Corporate debt instruments		1		44		—		45		2		44		—		46
Government securities		2		37		—		39		1		41		—		42
Total recorded at fair value		$728		$101		$—	$	829		$836		$108		$—		$944
Assets recorded at NAV(1):
Common/collective trust funds								650								689
Alternative investments:
Real estate funds								10								9
Private equity funds								80								73
Debt funds								10								11
Hedge funds								1								1
Total recorded at NAV							$	751								$783
Total investments(2)							$	1,580								$1,727
Dominion Energy Gas
Common and preferred stocks:
U.S.		$113		$—		$—	$	113		$130		$—		$—		$130
International		30		—		—		30		33		—		—		33
Total recorded at fair value		$143		$—		$—	$	143		$163		$—		$—		$163
Assets recorded at NAV(1):
Common/collective trust funds								148								154
Alternative investments:
Real estate funds								2								1
Private equity funds								18								15
Debt funds								—								—
Total recorded at NAV							$	168								$170
Total investments							$	311								$333

(1) These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

(2) Excludes net assets related to pending sales of securities of $1 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $2 million at December 31, 2018. Excludes net assets related to pending sales of securities of $1 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $1 million at December 31, 2017.

Net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities

 The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans are as follows:

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2018			2017			2016			2018			2017			2016
(millions, except percentages)
Dominion Energy
Service cost	$	157		$	138		$	118		$	27		$	26		$	31
Interest cost		337			345			317			56			60			65
Expected return on plan assets		(663	)		(639	)		(573	)		(143	)		(128	)		(118	)
Amortization of prior service (credit) cost		1			1			1			(52	)		(51	)		(35	)
Amortization of net actuarial loss		193			162			111			11			13			8
Settlements and curtailments		—			—			1			—			—			—
Net periodic benefit (credit) cost	$	25		$	7		$	(25	)	$	(101	)	$	(80	)	$	(49	)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	490		$	142		$	931		$	78		$	12		$	178
Prior service (credit) cost		—			5			—			(4	)		(73	)		(216	)
Settlements and curtailments		—			1			(1	)		—			2			—
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss		(193	)		(162	)		(111	)		(11	)		(13	)		(8	)
Amortization of prior service credit (cost)		(1	)		(1	)		(1	)		52			51			35
Total recognized in other comprehensive income and regulatory assets and liabilities	$	296		$	(15	)	$	818		$	115		$	(21	)	$	(11	)
Significant assumptions used to determine periodic cost:
Discount rate		3.80%-3.8	1%		3.31%-4.5	0%		2.87%-4.9	9%		3.76%			3.92%-4.4	7%		3.56%-4.9	4%
Expected long-term rate of return on plan assets		8.75	%		8.75	%		8.75	%		8.50	%		8.50	%		8.50	%
Weighted average rate of increase for compensation		4.09	%		4.09	%		4.22	%		3.95%-4.1	1%		3.29	%		4.22	%
Healthcare cost trend rate(1)											7.00	%		7.00	%		7.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(1)											5.00	%		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate(1)(2)											2022			2021			2020
Dominion Energy Gas
Service cost	$	18		$	15		$	13		$	4		$	4		$	5
Interest cost		29			30			30			11			12			14
Expected return on plan assets		(150	)		(141	)		(134	)		(28	)		(24	)		(23	)
Amortization of prior service (credit) cost		—			—			—			(4	)		(3	)		1
Amortization of net actuarial loss		19			16			13			3			2			1
Net periodic benefit (credit) cost	$	(84	)	$	(80	)	$	(78	)	$	(14	)	$	(9	)	$	(2	)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	207		$	(75	)	$	91		$	16		$	18		$	28
Prior service cost		—			—			—			(4	)		(61	)		—
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss		(19	)		(16	)		(13	)		(3	)		(2	)		(1	)
Amortization of prior service credit (cost)		—			—			—			4			3			(1	)
Total recognized in other comprehensive income and regulatory assets and liabilities	$	188		$	(91	)	$	78		$	13		$	(42	)	$	26
Significant assumptions used to determine periodic cost:
Discount rate		3.81	%		4.50	%		4.99	%		3.81	%		4.47	%		4.93	%
Expected long-term rate of return on plan assets		8.75	%		8.75	%		8.75	%		8.50	%		8.50	%		8.50	%
Weighted average rate of increase for compensation		4.11	%		4.11	%		3.93	%		4.55	%		4.11	%		3.93	%
Healthcare cost trend rate(1)											7.00	%		7.00	%		7.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(1)											5.00	%		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate(1)											2022			2021			2020

(1) Assumptions used to determine net periodic cost for the following year.

(2) The Society of Actuaries model used to determine healthcare cost trend rates was updated in 2014. The new model converges to the ultimate trend rate much more quickly than previous models.

Components of AOCI and regulatory assets and liabilities that have not been recognized as components of periodic benefit (credit) cost

The components of AOCI and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans that have not been recognized as components of net periodic benefit (credit) cost are as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2018		2017		2018			2017
(millions)
Dominion Energy
Net actuarial loss	$	3,477	$	3,181	$	350		$	283
Prior service (credit) cost		7		8		(393	)		(440	)
Total(1)	$	3,484	$	3,189	$	(43	)	$	(157	)
Dominion Energy Gas
Net actuarial loss	$	555	$	367	$	89		$	76
Prior service (credit) cost		—		—		(52	)		(52	)
Total(2)	$	555	$	367	$	37		$	24

(1) As of December 31, 2018, of the $3.5 billion and $(43) million related to pension benefits and other postretirement benefits, $2.0 billion and $(41) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2017, of the $3.2 billion and $(157) million related to pension benefits and other postretirement benefits, $1.9 billion and $(87) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.

(2) As of December 31, 2018, of the $555 million related to pension benefits, $200 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $37 million related to other postretirement benefits is included entirely in regulatory assets and liabilities. As of December 31, 2017, of the $367 million related to pension benefits, $134 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $24 million related to other postretirement benefits is included entirely in regulatory assets and liabilities.

Components of AOCI and regulatory assets and liabilities that are expected to be amortized as components of periodic benefit cost in 2019

The following table provides the components of AOCI and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans as of December 31, 2018 that are expected to be amortized as components of net periodic benefit (credit) cost in 2019:

	Pension Benefits		Other Postretirement Benefits
(millions)
Dominion Energy
Net actuarial loss		$155	$	18
Prior service (credit) cost		1		(52)
Dominion Energy Gas
Net actuarial loss		$  19	$	4
Prior service (credit) cost		—		(4	)

Effect of one percentage point change on benefit plans

A one percentage point change in assumed healthcare cost trend rates would have had the following effects for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) other postretirement benefit plans:

	Other Postretirement Benefits
	One percentage point increase		One percentage point decrease
(millions)
Dominion Energy
Effect on net periodic cost for 2019		$  20		$  (16)
Effect on other postretirement benefit obligation at December 31, 2018		130		(110)
Dominion Energy Gas
Effect on net periodic cost for 2019		$    4		$    (3)
Effect on other postretirement benefit obligation at December 31, 2018		25		(22)

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Related-Party Transactions (Tables)

12 Months Ended

Dec. 31, 2018

Virginia Electric and Power Company

Schedule of Related Party Transactions

Presented below are significant transactions with DES and other affiliates:

Year Ended December 31,	2018			2017			2016
(millions)
Commodity purchases from affiliates		$	930		$	674		$	571
Services provided by affiliates(1)			450			453			454
Services provided to affiliates			24			25			22

(1) Includes capitalized expenditures of $145 million, $144 million and $144 million for the year ended December 31, 2018, 2017 and 2016, respectively.

Dominion Energy Gas Holdings, LLC

Schedule of Related Party Transactions

 The costs of these services follow:

Year Ended December 31,	2018			2017			2016
(millions)
Sales of natural gas and transportation and storage services to affiliates		$	58		$	70		$	69
Purchases of natural gas from affiliates			6			5			9
Services provided by related parties(1)			131			143			141
Services provided to related parties(2)			216			156			128

(1) Includes capitalized expenditures of $37 million, $45 million and $49 million for the year ended December 31, 2018, 2017 and 2016, respectively.

(2) Amounts primarily attributable to Atlantic Coast Pipeline, a related party VIE.

Schedule of Related Party Transactions

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

At December 31,	2018			2017
(millions)
Other receivables(1)		$	13		$	12
Customer receivables from related parties			1			1
Imbalances receivable from affiliates			1			1
Imbalances payable to affiliates(2)			13			—
Affiliated notes receivable(3)			16			20

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

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

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

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Operating Segments (Tables)

12 Months Ended

Dec. 31, 2018

Segment Reporting Disclosure Other Information

 A description of the operations included in the Companies’ primary operating segments is as follows:

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

(1) Includes remaining producer services activities.

Schedule of Segment Reporting Information, by Segment

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

Year Ended December 31,	Power Delivery		Power Generation			Gas Infrastructure			Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2018
Total revenue from external customers	$	2,206	$	7,104		$	4,221		$	(208	)	$	43		$	13,366
Intersegment revenue		23		11			27			674			(735	)		—
Total operating revenue		2,229		7,115			4,248			466			(692	)		13,366
Depreciation, depletion and amortization		625		746			615			14			—			2,000
Impairment of assets and related charges		—		1			8			394			—			403
Gains on sales of assets		—		6			(186	)		(200	)		—			(380	)
Equity in earnings of equity method investees		—		18			178			1			—			197
Interest income		—		90			64			126			(196	)		84
Interest and related charges		265		374			268			782			(196	)		1,493
Income tax expense (benefit)		160		294			330			(204	)		—			580
Net income (loss) attributable to Dominion Energy		587		1,254			1,214			(608	)		—			2,447
Investment in equity method investees		—		82			1,159			37			—			1,278
Capital expenditures		1,564		1,321			1,415			105			—			4,405
Total assets (billions)		17.8		28.2			31.5			11.2			(10.8	)		77.9
2017
Total revenue from external customers	$	2,206	$	6,676		$	2,832		$	16		$	856		$	12,586
Intersegment revenue		22		10			834			610			(1,476	)		—
Total operating revenue		2,228		6,686			3,666			626			(620	)		12,586
Depreciation, depletion and amortization		593		747			522			43			—			1,905
Impairment of assets and related charges		—		—			—			15			—			15
Gains on sales of assets		—		—			(147	)		—			—			(147	)
Equity in earnings of equity method investees		—		(181	)		159			4			—			(18	)
Interest income		4		92			45			96			(155	)		82
Interest and related charges		265		342			109			644			(155	)		1,205
Income tax expense (benefit)		334		373			487			(1,224	)		—			(30	)
Net income (loss) attributable to Dominion Energy		531		1,181			898			389			—			2,999
Investment in equity method investees		—		81			1,422			41			—			1,544
Capital expenditures		1,433		2,275			2,149			52			—			5,909
Total assets (billions)		16.7		29.0			28.0			12.0			(9.1	)		76.6
2016
Total revenue from external customers	$	2,210	$	6,747		$	2,069		$	(7	)	$	718		$	11,737
Intersegment revenue		23		10			697			609			(1,339	)		—
Total operating revenue		2,233		6,757			2,766			602			(621	)		11,737
Depreciation, depletion and amortization		537		662			330			30			—			1,559
Impairment of assets and related charges		—		—			—			4			—			4
Gains on sales of assets		—		4			(44	)		—			—			(40	)
Equity in earnings of equity method investees		—		(16	)		105			22			—			111
Interest income		—		74			34			36			(78	)		66
Interest and related charges		244		290			38			516			(78	)		1,010
Income tax expense (benefit)		308		279			431			(363	)		—			655
Net income (loss) attributable to Dominion Energy		484		1,397			726			(484	)		—			2,123
Capital expenditures		1,320		2,440			2,322			43			—			6,125

Virginia Electric and Power Company

Schedule of Segment Reporting Information, by Segment

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

Year Ended December 31,	Power Delivery		Power Generation		Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2018
Operating revenue	$	2,204	$	5,630	$	(215	)	$	—		$	7,619
Depreciation and amortization		624		533		(25	)		—			1,132
Interest income		—		9		5			(4	)		10
Interest and related charges		265		250		—			(4	)		511
Income tax expense (benefit)		158		220		(78	)		—			300
Net income (loss)		586		1,008		(312	)		—			1,282
Capital expenditures		1,539		1,003		—			—			2,542
Total assets (billions)		17.6		19.4		—			(0.1	)		36.9
2017
Operating revenue	$	2,212	$	5,344	$	—		$	—		$	7,556
Depreciation and amortization		594		547		—			—			1,141
Interest income		4		15		3			(3	)		19
Interest and related charges		265		232		—			(3	)		494
Income tax expense (benefit)		334		534		(94	)		—			774
Net income		527		939		74			—			1,540
Capital expenditures		1,439		1,290		—			—			2,729
Total assets (billions)		16.6		18.6		—			(0.1	)		35.1
2016
Operating revenue	$	2,217	$	5,390	$	(19	)	$	—		$	7,588
Depreciation and amortization		537		488		—			—			1,025
Interest income		—		—		—			—			—
Interest and related charges		244		219		—			(2	)		461
Income tax expense (benefit)		307		524		(104	)		—			727
Net income (loss)		482		909		(173	)		—			1,218
Capital expenditures		1,313		1,336		—			—			2,649

Dominion Energy Gas Holdings, LLC

Schedule of Segment Reporting Information, by Segment

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

Year Ended December 31,	Gas Infrastructure			Corporate and Other			Consolidated Total
(millions)
2018
Operating revenue	$	1,940		$	—		$	1,940
Depreciation and amortization		244			—			244
Impairment of assets and related charges		5			341			346
Gains on sales of assets		(119	)		—			(119	)
Equity in earnings of equity method investees		24			—			24
Interest income		2			—			2
Interest and related charges		104			1			105
Income tax expense (benefit)		188			(102	)		86
Net income (loss)		552			(251	)		301
Investment in equity method investees		91			—			91
Capital expenditures		772			—			772
Total assets (billions)		11.8			0.6			12.4
2017
Operating revenue	$	1,814		$	—		$	1,814
Depreciation and amortization		227			—			227
Impairment of assets and related charges		15			1			16
Gains on sales of assets		(70	)		—			(70	)
Equity in earnings of equity method investees		21			—			21
Interest income		2			—			2
Interest and related charges		97			—			97
Income tax expense (benefit)		256			(205	)		51
Net income		436			179			615
Investment in equity method investees		95			—			95
Capital expenditures		778			—			778
Total assets (billions)		11.3			0.6			11.9
2016
Operating revenue	$	1,638		$	—		$	1,638
Depreciation and amortization		214			(10	)		204
Gains on sales of assets		(45	)		—			(45	)
Equity in earnings of equity method investees		21			—			21
Interest income		1			—			1
Interest and related charges		92			2			94
Income tax expense (benefit)		237			(22	)		215
Net income (loss)		395			(3	)		392
Capital expenditures		854			—			854

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Data

A summary of the Companies’ quarterly results of operations for the years ended December 31, 2018 and 2017 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

DOMINION ENERGY

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(millions)
2018
Operating revenue	$	3,466	$	3,088	$	3,451	$	3,361
Income from operations		875		742		1,150		834
Net income including noncontrolling interests		526		478		883		662
Net income attributable to Dominion Energy		503		449		854		641
Basic EPS:
Net income attributable to Dominion Energy		0.77		0.69		1.31		0.97
Diluted EPS:
Net income attributable to Dominion Energy		0.77		0.69		1.30		0.97
Dividends declared per common share		0.835		0.835		0.835		0.835
2017
Operating revenue	$	3,384	$	2,813	$	3,179	$	3,210
Income from operations		1,079		753		1,152		953
Net income including noncontrolling interests		674		417		696		1,333
Net income attributable to Dominion Energy		632		390		665		1,312
Basic EPS:
Net income attributable to Dominion Energy		1.01		0.62		1.03		2.04
Diluted EPS:
Net income attributable to Dominion Energy		1.01		0.62		1.03		2.04
Dividends declared per common share		0.755		0.755		0.770		0.770

Virginia Electric and Power Company

Quarterly Financial Data

Virginia Power’s quarterly results of operations were as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(millions)
2018
Operating revenue	$	1,748	$	1,829	$	2,232	$	1,810
Income from operations		364		533		756		418
Net income		184		339		520		239
2017
Operating revenue	$	1,831	$	1,747	$	2,154	$	1,824
Income from operations		653		613		847		619
Net income		356		318		459		407

Dominion Energy Gas Holdings, LLC

Quarterly Financial Data

Dominion Energy Gas’ quarterly results of operations were as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(millions)
2018
Operating revenue		$526		$459		$423		$532
Income (loss) from operations		201		7		182		(55	)
Net income (loss)	166		15		136		(16)
2017
Operating revenue		$490		$422		$401		$501
Income from operations		156		116		185		181
Net income		108		77		117		313

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Nature of Operations (Narrative) (Detail)	12 Months Ended
	Dec. 31, 2018 Segments
Subsidiary, Sale of Stock [Line Items]
Number of operating segments	3
Iroquois | Partnership Interest | Dominion Energy Midstream Partners, LP
Subsidiary, Sale of Stock [Line Items]
Noncontrolling partnership percentage interest	25.93%
Common and Subordinated Units | Dominion Energy Midstream Partners, LP
Subsidiary, Sale of Stock [Line Items]
Ownership interest percentage of limited partner interests	60.90%
Convertible Preferred Units | Dominion Energy Midstream Partners, LP
Subsidiary, Sale of Stock [Line Items]
Ownership interest percentage of limited partner interests	37.50%
Virginia Electric and Power Company
Subsidiary, Sale of Stock [Line Items]
Number of operating segments	2
Dominion Energy Gas Holdings, LLC
Subsidiary, Sale of Stock [Line Items]
Number of operating segments	1

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Significant Accounting Policies (Narrative) (Detail) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2018 USD ($) Mcfe	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($) Mcfe Contract $ / shares	Dec. 31, 2017 USD ($) Mcfe	Dec. 31, 2016 USD ($)
Significant Accounting Policies [Line Items]
Accrued unbilled revenue	$ 626		$ 626	$ 661
Percentage of fuel currently subject to deferred fuel accounting			84.00%
Federal statutory income tax rate			21.00%	35.00%	35.00%
Recognized interest income			$ 11	$ 11
Margin deposit assets	$ 95		95	92
Capitalized interest costs and AFUDC			134	236	$ 159
Asset impairment charges			$ 403	$ 15	$ 4
Estimated proved developed or proved gas and oil reserves rate per unit | Mcfe	1.89		1.89	2.11
Unrealized gains reclassified from AOCI to retained earnings	$ 1,100		$ 1,100
Unrealized gains reclassified from AOCI to retained earnings after-tax			734
Net unrealized gains on equity securities previously classified as cost method investments	36		36
Net unrealized gains on equity securities previously classified as cost method investments, after tax	22		22
Net unrealized gains in other income			190
Net unrealized gains in other income, after tax			$ 142
Gain per share from unrealized loss on securities | $ / shares			$ 0.22
Tax reform, reclassification of tax benefit from AOCI to retained earnings			$ 289
Accounting Standards Update 2014-09 [Member] | Cumulative Effect Of Changes In Accounting Principle [Member]
Significant Accounting Policies [Line Items]
Change in accounting principle to retained earnings and membership interests	3		3
Accounting Standards Update 2017-05 [Member] | Cumulative Effect Of Changes In Accounting Principle [Member]
Significant Accounting Policies [Line Items]
Change in accounting principle to retained earnings and membership interests	127		127
Current Regulatory Liabilities [Member]
Significant Accounting Policies [Line Items]
Net unrealized gains on equity securities previously classified as cost method investments	33		33
Retained Earnings
Significant Accounting Policies [Line Items]
Net unrealized gains on equity securities previously classified as cost method investments	3		3
Maximum
Significant Accounting Policies [Line Items]
Operating lease, right-of-use asset	500		$ 500
Maximum | Nonutility Gas Gathering and Processing
Significant Accounting Policies [Line Items]
Estimated useful lives			50 years
Minimum
Significant Accounting Policies [Line Items]
Operating lease, right-of-use asset	450		$ 450
Minimum | Nonutility Gas Gathering and Processing
Significant Accounting Policies [Line Items]
Estimated useful lives			3 years
Change in Depreciation Rates from New Depreciation Study
Significant Accounting Policies [Line Items]
Increase (decrease) in EPS | $ / shares			$ 0.07
Change in Estimated Useful Life | Merchant generation assets
Significant Accounting Policies [Line Items]
Increase (decrease) in depreciation expense			$ (30)	$ 26
Increase (decrease) in depreciation expense, after tax			(23)	16
Performing Processing And Fractionation Services [Member] | Accounting Standards Update 2014-09 [Member]
Significant Accounting Policies [Line Items]
Operating revenue			107	0
Other energy-related purchases			107	0
Transportation And Storage Arrangements [Member] | Accounting Standards Update 2014-09 [Member]
Significant Accounting Policies [Line Items]
Operating revenue				111
Purchased gas				111
Virginia Electric and Power Company
Significant Accounting Policies [Line Items]
Accrued unbilled revenue	392		$ 392	$ 400
Federal statutory income tax rate			21.00%	35.00%	35.00%
Recognized interest income			$ 11	$ 11
Noncurrent income taxes receivable				1
Margin deposit assets	1		1	23
Capitalized interest costs			56	37	$ 21
AFUDC related to projects			4	22	$ 31
Unrealized gains reclassified from AOCI to retained earnings	119		119
Unrealized gains reclassified from AOCI to retained earnings after-tax			73
Net unrealized gains on equity securities previously classified as cost method investments	36		36
Net unrealized gains on equity securities previously classified as cost method investments, after tax	22		22
Net unrealized gains in other income			24
Net unrealized gains in other income, after tax			18
Tax reform, reclassification of tax benefit from AOCI to retained earnings			3
Virginia Electric and Power Company | Scenario, Forecast
Significant Accounting Policies [Line Items]
Asset impairment charges		$ 190
Asset Impairment Charges After Tax		$ 141
Virginia Electric and Power Company | Current Regulatory Liabilities [Member]
Significant Accounting Policies [Line Items]
Net unrealized gains on equity securities previously classified as cost method investments	33		33
Virginia Electric and Power Company | Retained Earnings
Significant Accounting Policies [Line Items]
Net unrealized gains on equity securities previously classified as cost method investments	3		3
Virginia Electric and Power Company | Affiliated Entity
Significant Accounting Policies [Line Items]
Income tax payable	36		36	16
Virginia Electric and Power Company | Change in Depreciation Rates from New Depreciation Study
Significant Accounting Policies [Line Items]
Increase (decrease) in depreciation expense			(60)	40
Increase (decrease) in depreciation expense, after tax			(44)	25
Virginia Electric and Power Company | Federal
Significant Accounting Policies [Line Items]
Noncurrent income taxes receivable				1
Virginia Electric and Power Company | Federal | Affiliated Entity
Significant Accounting Policies [Line Items]
Income tax payable	34		34	16
Virginia Electric and Power Company | State | Affiliated Entity
Significant Accounting Policies [Line Items]
Income tax payable	2		2
Virginia Electric and Power Company | State | Maximum
Significant Accounting Policies [Line Items]
Noncurrent income taxes receivable				1
Dominion Energy Gas Holdings, LLC
Significant Accounting Policies [Line Items]
Accrued unbilled revenue	131		$ 131	$ 121
Federal statutory income tax rate			21.00%	35.00%	35.00%
Capitalized interest costs			$ 18	$ 25	$ 8
Asset impairment charges	219		346	16
Inventory under LIFO method	12		12	9
Amount exceeded on LIFO basis	87		87	79
Tax reform, reclassification of tax benefit from AOCI to retained earnings			26
Dominion Energy Gas Holdings, LLC | Accounting Standards Update 2014-09 [Member] | Cumulative Effect Of Changes In Accounting Principle [Member]
Significant Accounting Policies [Line Items]
Change in accounting principle to retained earnings and membership interests	3		3
Dominion Energy Gas Holdings, LLC | Affiliated Entity
Significant Accounting Policies [Line Items]
Income tax payable	2		2	25
Dominion Energy Gas Holdings, LLC | Maximum
Significant Accounting Policies [Line Items]
Operating lease, right-of-use asset	70		$ 70
Dominion Energy Gas Holdings, LLC | Maximum | Nonutility Gas Gathering and Processing
Significant Accounting Policies [Line Items]
Estimated useful lives			50 years
Dominion Energy Gas Holdings, LLC | Minimum
Significant Accounting Policies [Line Items]
Operating lease, right-of-use asset	60		$ 60
Dominion Energy Gas Holdings, LLC | Minimum | Nonutility Gas Gathering and Processing
Significant Accounting Policies [Line Items]
Estimated useful lives			10 years
Dominion Energy Gas Holdings, LLC | Performing Processing And Fractionation Services [Member] | Accounting Standards Update 2014-09 [Member]
Significant Accounting Policies [Line Items]
Operating revenue			$ 103	0
Other energy-related purchases			103	0
Dominion Energy Gas Holdings, LLC | Transportation And Storage Arrangements [Member] | Accounting Standards Update 2014-09 [Member]
Significant Accounting Policies [Line Items]
Operating revenue				79
Purchased gas				79
Dominion Energy Gas Holdings, LLC | Federal | Affiliated Entity
Significant Accounting Policies [Line Items]
Income tax payable	8		8	21
Dominion Energy Gas Holdings, LLC | State
Significant Accounting Policies [Line Items]
Noncurrent income taxes receivable	13		13	14
Dominion Energy Gas Holdings, LLC | State | Affiliated Entity
Significant Accounting Policies [Line Items]
Income tax payable	6		$ 6	$ 4
DETI | Accounting Standards Update 2014-09 [Member] | Cumulative Effect Of Changes In Accounting Principle [Member]
Significant Accounting Policies [Line Items]
Number of existing contracts | Contract			3
Virginia Power [Member] | Maximum
Significant Accounting Policies [Line Items]
Operating lease, right-of-use asset	250		$ 250
Virginia Power [Member] | Minimum
Significant Accounting Policies [Line Items]
Operating lease, right-of-use asset	200		$ 200
SCANA | Maximum
Significant Accounting Policies [Line Items]
Estimated useful lives			78 years
Capital lease obligation non - current	35		$ 35
SCANA | Minimum
Significant Accounting Policies [Line Items]
Estimated useful lives			5 years
Capital lease obligation non - current	$ 30		$ 30
Merchant Solar Projects | Terra Nova Renewable Partners
Significant Accounting Policies [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	50.00%		50.00%
Percentage of equity interest sold to noncontrolling interest owners	33.00%		33.00%
Merchant Solar Projects | Terra Nova Renewable Partners | Call Option
Significant Accounting Policies [Line Items]
Percentage ownership in total units	67.00%		67.00%

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Significant Accounting Policies (Checks the Outstanding Accounts Payable but not yet Presented for Payment and Recorded) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Accounts Payable [Line Items]
Accounts payable for checks outstanding	$ 35	$ 30
Virginia Electric and Power Company
Accounts Payable [Line Items]
Accounts payable for checks outstanding	16	17
Dominion Energy Gas Holdings, LLC
Accounts Payable [Line Items]
Accounts payable for checks outstanding	$ 7	$ 7

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Significant Accounting Policies (Reconciliation of Total Cash, Restricted Cash and Equivalents) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash, Cash Equivalents and Restricted Cash [Line Items]
Cash and cash equivalents		$ 268	$ 120	$ 261	$ 607
Restricted cash and equivalents	[1]	123	65	61	25
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows		391	185	322	632
Virginia Electric and Power Company
Cash, Cash Equivalents and Restricted Cash [Line Items]
Cash and cash equivalents		29	14	11	18
Restricted cash and equivalents	[1]	9	10
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows		38	24	11	18
Dominion Energy Gas Holdings, LLC
Cash, Cash Equivalents and Restricted Cash [Line Items]
Cash and cash equivalents		10	4	23	13
Restricted cash and equivalents	[1]	24	26	20	14
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows		$ 34	$ 30	$ 43	$ 27

[1] Restricted cash and equivalent balances are presented within other current assets in the Companies' Consolidated Balance Sheets.

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Significant Accounting Policies (Depreciation Rates and Estimated Useful Life) (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Merchant Generation Nuclear
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	44 years
LNG Facility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	40 years
Minimum | Merchant Generation-Other
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	15 years
Minimum | Nonutility Gas Gathering and Processing
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	3 years
Minimum | Nonutility Gas Gathering and Processing | Dominion Energy Gas Holdings, LLC
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	10 years
Minimum | General and Other
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years
Maximum | Merchant Generation-Other
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	30 years
Maximum | Nonutility Gas Gathering and Processing
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	50 years
Maximum | Nonutility Gas Gathering and Processing | Dominion Energy Gas Holdings, LLC
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	50 years
Maximum | General and Other
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	59 years
Generation
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.71%	2.94%	2.83%
Generation | Virginia Electric and Power Company
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.71%	2.94%	2.83%
Transmission
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.54%	2.55%	2.47%
Transmission | Virginia Electric and Power Company
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.52%	2.54%	2.36%
Transmission | Dominion Energy Gas Holdings, LLC
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.45%	2.40%	2.43%
Distribution
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.97%	3.00%	3.02%
Distribution | Virginia Electric and Power Company
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	3.31%	3.32%	3.32%
Storage
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.40%	2.48%	2.29%
Storage | Dominion Energy Gas Holdings, LLC
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.46%	2.45%	2.19%
Gas Gathering and Processing
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.62%	2.21%	2.66%
Gas Gathering and Processing | Dominion Energy Gas Holdings, LLC
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	3.07%	2.42%	2.58%
General and Other
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	4.56%	4.89%	4.12%
General and Other | Virginia Electric and Power Company
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	4.52%	4.68%	3.49%
General and Other | Dominion Energy Gas Holdings, LLC
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	5.59%	4.96%	4.54%
Distribution | Dominion Energy Gas Holdings, LLC
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.41%	2.42%	2.55%

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Acquisitions and Dispositions (Acquisition Of Scana) (Narrative) (Detail) - USD ($) $ / shares in Units, $ in Millions			1 Months Ended					2 Months Ended	3 Months Ended									12 Months Ended
		Sep. 16, 2016	Feb. 28, 2019	Jan. 31, 2019	Aug. 31, 2018	Jul. 31, 2018	Jun. 30, 2018	Oct. 31, 2017	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2019	Dec. 31, 2015
Business Acquisition And Dispositions [Line Items]
Regulatory Liabilities										$ 7,196				$ 7,109				$ 7,196	$ 7,109
Regulatory liabilities-current	[1]									356				193				356	193
After tax charge in statements of income										641	$ 854	$ 449	$ 503	1,312	$ 665	$ 390	$ 632	2,447	2,999	$ 2,123
Other Commitment, Fiscal Year Maturity [Abstract]
Cash, restricted cash and equivalents										391				185				391	185	$ 322		$ 632
Deferred tax asset recorded on federal net operating loss carryforwards										1,800								1,800
Deferred tax asset recorded on state net operating loss carryforwards										2,400								2,400
Valuation allowance, deferred tax asset, change in amount																		0
Unrecognized Tax Benefits, Increase Resulting from Acquisition																		106
Property, plant and equipment, in service										$ 76,578				$ 74,823				$ 76,578	$ 74,823
Intangible assets, weighted-average amortization period																		15 years
Preferred stock, shares authorized										20,000,000				20,000,000				20,000,000	20,000,000
Return of equity percentage																				10.50%
Decrease in revenue requirement, natural gas rates																		$ 20
Decrease in revenue requirement, adjustments to customer rates																		13
Before tax charge in statements of income																		3,129	$ 3,090	$ 2,867
Liabilities recorded										$ 55,866				$ 57,215				55,866	$ 57,215
Subsequent Event
Business Acquisition And Dispositions [Line Items]
Stock issued during period for acquisition, shares				22,500,000
Stock issued during period for acquisition, value				$ 1,600
SCE&G [Member] | Subsequent Event
Other Commitment, Fiscal Year Maturity [Abstract]
Preferred stock, shares authorized																					20,000,000
SCANA | Subsequent Event
Other Commitment, Fiscal Year Maturity [Abstract]
Preferred stock, shares authorized			1,000
Preferred stock, no par value			$ 0
SCANA
Business Acquisition And Dispositions [Line Items]
Combination debt outstanding										13,083								$ 13,083
Period to provide refund to customer																		20 years
Regulatory Liabilities								$ 1,100
Refund Liability to electric service customers										1,000								$ 1,000
Business combination cost related to exclusion from rate recovery																		105
Remaining regulatory asset										4,219								4,219
Other Commitment, Fiscal Year Maturity [Abstract]
Charitable contributions, annual committed increase for next five years		$ 1
Cash, restricted cash and equivalents										389								389
Restricted cash										115								115
Equity method investment										20								20
Business combination cost related to exclusion from rate recovery, after tax charge																		79
Property, plant and equipment, in service										16,331								16,331
Regulatory assets for deferred income tax										190								190
Intangible assets										281								281
Intangible assets, accumulated amortization										181								$ 181
Intangible assets, weighted-average amortization period																		5 years
Provision of bill credits impact on retail electric customer rates																		$ 100
Reduction in base rates to retail electric customers																		67
Transaction cost																		27
SCANA | Provision for future cost of removal and AROs
Other Commitment, Fiscal Year Maturity [Abstract]
Purchase price allocation																		577
Business combination, consideration, liabilities incurred																		$ 23
SCANA | Minimum
Other Commitment, Fiscal Year Maturity [Abstract]
Charitable contributions, period committed for annual increase		5 years
Estimated useful lives																		5 years
SCANA | Maximum
Other Commitment, Fiscal Year Maturity [Abstract]
Estimated useful lives																		78 years
SCANA | SCE&G Ratepayer Case [Member]
Other Commitment, Fiscal Year Maturity [Abstract]
Escrow account										$ 2,000								$ 2,000
Credit in future electric rate relief																		2,000
Cash payment																		115
SCANA | SCE&G Ratepayer Case [Member] | Minimum
Other Commitment, Fiscal Year Maturity [Abstract]
Proceeds from sale of property																		60
SCANA | SCE&G Ratepayer Case [Member] | Maximum
Other Commitment, Fiscal Year Maturity [Abstract]
Proceeds from sale of property																		$ 85
SCANA | Scenario, Forecast
Business Acquisition And Dispositions [Line Items]
Period to provide refund to customer									11 years
Regulatory Liabilities									$ 1,000
Reduction in operating revenue									(1,000)
Regulatory liabilities-current									140
After tax charge in statements of income									(756)
Other Commitment, Fiscal Year Maturity [Abstract]
Regulatory assets deferred, expected to be recognized									145
SCANA | Scenario, Forecast | SCE&G Ratepayer Case [Member]
Business Acquisition And Dispositions [Line Items]
After tax charge in statements of income									(135)
Other Commitment, Fiscal Year Maturity [Abstract]
Before tax charge in statements of income									$ (180)
SCANA | Subsequent Event
Business Acquisition And Dispositions [Line Items]
Common stock agreed to issue				66.90%
Stock issued during period for acquisition, shares				95,600,000
Stock issued during period for acquisition, value				$ 6,800
Combination debt outstanding				6,900
Business combination, refund to customers				$ 2,000
Period to provide refund to customer				20 years
Business combination cost related to exclusion from rate recovery				$ 2,400
Remaining regulatory asset				2,800
Other Commitment, Fiscal Year Maturity [Abstract]
Tender offer expire date			Mar. 31, 2019
Repurchase of medium term notes			$ 300
SCANA | Toshiba Corporation
Business Acquisition And Dispositions [Line Items]
Cash consideration								$ 1,100
SCANA | Columbia Energy | Subsequent Event
Business Acquisition And Dispositions [Line Items]
Business combination cost related to exclusion from rate recovery				180
SCANA | V.C. Summer Units
Other Commitment, Fiscal Year Maturity [Abstract]
Equity method investment, ownership percentage										66.70%								66.70%
Property, plant and equipment, in service										$ 1,500								$ 1,500
Property, plant and equipment, accumulated depreciation										644								644
Property, plant and equipment, under construction										$ 128								$ 128
SCE&G [Member]
Other Commitment, Fiscal Year Maturity [Abstract]
Equity method investment, ownership percentage										55.00%								55.00%
Percentage of average residential electric bill						18.00%
Reduction in revenue						$ 31
Liabilities recorded										$ 11								$ 11
Contesting amount for filed liens in Fairfield country					$ 285
Maximum assessment cost,per incident																		92
Maximum yearly assessment per nuclear incident																		14
Maximum amount of coverage to nuclear facility for property damage and outage costs										$ 2,800								2,800
Maximum loss for a single nuclear incident																		2,800
Maximum prosepective insurance premium per nuclear incident																		23
NEIL Maximum Insurance Coverage To Nuclear Facility For Property Damage And Outage Costs From Non-Nuclear Event																		415
Maximum Retrospective Premium Assessment																		$ 2
SCE&G [Member] | SCDOR [Member]
Other Commitment, Fiscal Year Maturity [Abstract]
Proportional share with NND project							100.00%
Proposed assessment amount from audit							$ 410
SCE&G [Member] | SOUTH CAROLINA
Other Commitment, Fiscal Year Maturity [Abstract]
Amount claimed by plaintiffs in legal matter						$ 75
Proportional share with NND project						55.00%
SCE&G [Member] | Subsequent Event
Other Commitment, Fiscal Year Maturity [Abstract]
Repurchase of first mortgage bonds			1,000
Purchase of additional first mortgage bonds			$ (1,200)
Tender offer expire date			Mar. 31, 2019
Recover of cost and net lost revenue with incentive				30
SCE&G [Member] | Subsequent Event | Revolving Credit Facility
Other Commitment, Fiscal Year Maturity [Abstract]
Line of Credit Facility, Maximum Borrowing Capacity				$ 6,000

[1] Current regulatory liabilities are presented in other current liabilities in Dominion Energy and Dominion Energy Gas' Consolidated Balance Sheets.

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Acquisitions and Dispositions (Schedule of Preliminary Allocation of Purchase Price to Assets Acquired and Liabilities Assumed) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Sep. 16, 2016
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]
Goodwill	[1]	$ 6,410	$ 6,405	$ 6,399
SCANA
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]
Total current assets		1,756
Investments		213
Property, plant and equipment, net		10,982
Goodwill		2,438
Regulatory assets		4,219
Other deferred charges and other assets, including intangible assets		314
Total Assets		19,922
Total current liabilities		1,506
Long-term debt		6,707
Deferred income taxes		1,097
Regulatory liabilities		2,664
Other deferred credits and other liabilities		1,109
Total Liabilities		13,083
Total purchase price		$ 6,839
Dominion Energy Questar Corporation
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]
Total current assets					$ 224
Investments	[2]				58
Property, plant and equipment, net	[3]				4,131
Goodwill					3,111
Other deferred charges and other assets, including intangible assets					75
Total Assets					7,599
Total current liabilities	[4]				793
Long-term debt	[5]				963
Deferred income taxes					807
Regulatory liabilities					259
Other deferred credits and other liabilities					220
Total Liabilities					3,202
Total purchase price					4,397
Asset retirement obligations					$ 160

[1] Goodwill amounts do not contain any accumulated impairment losses.

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

[3] Nonregulated property, plant and equipment, excluding land, will be depreciated over remaining useful lives primarily ranging from 9 to 18 years

[4] Includes $301 million of short-term debt, of which no amounts remain outstanding at December 31, 2018, as well as a $250 million variable interest rate term loan due in August 2017 that was paid in July 2017.

[5] Unsecured senior and medium-term notes with maturities which range from 2017 to 2048 and bear interest at rates from 2.98% to 7.20%.

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Acquisitions and Dispositions (Schedule of Property Plant and Equipment) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Utility:
Generation	$ 19,250	$ 17,602
Transmission	16,669	15,335
Distribution	18,549	17,408
Storage	2,905	2,887
Nuclear fuel	1,626	1,599
General and other	1,476	1,514
Plant under construction	2,385	7,765
Total utility	64,930	66,049
Total property, plant and equipment	$ 76,578	$ 74,823
Generation
Utility:
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.71%	2.94%	2.83%
Transmission
Utility:
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.54%	2.55%	2.47%
Distribution
Utility:
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.97%	3.00%	3.02%
Storage
Utility:
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.40%	2.48%	2.29%
General and Other
Utility:
Average composite depreciation rates on utility property, plant and equipment (percentage)	4.56%	4.89%	4.12%
SCANA
Utility:
Generation	$ 5,720
Transmission	2,416
Distribution	6,044
Storage	99
Nuclear fuel	611
General and other	631
Plant under construction	527
Total utility	16,048
Nonutility, including plant under construction	283
Total property, plant and equipment	$ 16,331
SCANA | Generation
Utility:
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.61%
SCANA | Transmission
Utility:
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.47%
SCANA | Distribution
Utility:
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.48%
SCANA | Storage
Utility:
Average composite depreciation rates on utility property, plant and equipment (percentage)	2.48%
SCANA | General and Other
Utility:
Average composite depreciation rates on utility property, plant and equipment (percentage)	5.64%

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Acquisitions and Dispositions (Schedule of Finite-Lived Intangible Assets Future Amortization Expense) (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Business Acquisition [Line Items]
2019	$ 67
2020	56
2021	44
2022	34
2023	23
SCANA
Business Acquisition [Line Items]
2019	95
2020	90
2021	80
2022	74
2023	$ 71

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Acquisitions and Dispositions (Schedule of Line of Credit Facilities) (Detail) - USD ($)		Dec. 31, 2018		Dec. 31, 2017
Business Acquisition [Line Items]
Facility Limit		$ 6,000,000,000	[1]	$ 5,500,000,000
Letters of credit advances		88,000,000	[1]	76,000,000
Facility capacity available		5,588,000,000	[1]	$ 2,126,000,000
SCANA Existing Facilities
Business Acquisition [Line Items]
Facility Limit		1,800,000,000
Letters of credit advances		37,000,000
Facility capacity available		1,550,000,000
SCANA Existing Facilities | Letter of Credit
Business Acquisition [Line Items]
Letters of credit advances		$ 40,000,000
Weighted-average interest rate		3.87%
SCANA Existing Facilities | Commercial Paper
Business Acquisition [Line Items]
Weighted-average interest rate		3.63%
Outstanding commercial paper		$ 173,000,000
SCANA Existing Facilities | SCANA
Business Acquisition [Line Items]
Facility Limit		400,000,000
Letters of credit advances		37,000,000
Facility capacity available		321,000,000
SCANA Existing Facilities | SCANA | Letter of Credit
Business Acquisition [Line Items]
Letters of credit advances	[2]	$ 40,000,000
Weighted-average interest rate		3.87%
SCANA Existing Facilities | SCANA | Commercial Paper
Business Acquisition [Line Items]
Weighted-average interest rate		3.65%
Outstanding commercial paper		$ 2,000,000
SCANA Existing Facilities | SCE&G [Member]
Business Acquisition [Line Items]
Facility Limit	[3]	1,200,000,000
Facility capacity available		$ 1,127,000,000
SCANA Existing Facilities | SCE&G [Member] | Commercial Paper
Business Acquisition [Line Items]
Weighted-average interest rate		3.82%
Outstanding commercial paper		$ 73,000,000
SCANA Existing Facilities | PSNC [Member]
Business Acquisition [Line Items]
Facility Limit		200,000,000
Facility capacity available		$ 102,000,000
SCANA Existing Facilities | PSNC [Member] | Commercial Paper
Business Acquisition [Line Items]
Weighted-average interest rate		3.49%
Outstanding commercial paper		$ 98,000,000

[1] This credit facility matures in March 2023 and can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

[2] In January 2019, SCANA repaid $40 million in letter of credit advances.

[3] Includes South Carolina Fuel Company, Inc.'s $500 million credit facility.

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Acquisitions and Dispositions (Schedule of Line of Credit Facilities) (Parenthetical) (Detail) - USD ($)	1 Months Ended
	Jan. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Business Acquisition [Line Items]
Credit facility amount		$ 6,000,000,000	[1]	$ 5,500,000,000
SCANA | Subsequent Event
Business Acquisition [Line Items]
Repayment of letter of credit advances	$ 40,000,000
South Carolina [Member]
Business Acquisition [Line Items]
Credit facility amount		$ 500,000,000

[1] This credit facility matures in March 2023 and can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

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Acquisitions and Dispositions (Schedule of Long Term Debt) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Current maturities of long-term debt	[1],[2]	$ 3,624	$ 3,078
Unamortized discount, premium and debt issuance costs, net		(248)	$ (245)
SCANA
Business Acquisition [Line Items]
Total principal		6,795
Current maturities of long-term debt		(59)
Unamortized discount, premium and debt issuance costs, net		(29)
Total long-term debt		6,707
Variable rate debt		$ 68
Variable rate debt, interest rate		1.72%
SCANA | Unsecured Medium Term Notes due Two Thousand Twenty to Two Thousand Twenty Two [Member]
Business Acquisition [Line Items]
Weighted- average Coupon (percentage)	[3]	5.42%
Total principal		$ 800
SCANA | Unsecured Senior Notes due Two Thousand Nineteen to Two Thousand Thirty Four [Member]
Business Acquisition [Line Items]
Weighted- average Coupon (percentage)	[3]	3.44%
Total principal		$ 70
SCANA | First Mortgage Bonds due Two Thousand Twenty One to Two Thousand Sixty Five [Member]
Business Acquisition [Line Items]
Weighted- average Coupon (percentage)	[3]	5.52%
Total principal		$ 4,990
SCANA | Genco Notes due Two Thousand Nineteen to Two Thousand Twenty Four [Member]
Business Acquisition [Line Items]
Weighted- average Coupon (percentage)	[3]	5.49%
Total principal		$ 40
SCANA | Industrial and Pollution Control Bonds due Two Thousand Twenty Eight to Two Thousand Thirty Eight [Member]
Business Acquisition [Line Items]
Weighted- average Coupon (percentage)	[3],[4]	3.52%
Total principal	[4]	$ 122
SCANA | Psnc Senior Debentures and Notes due Two Thousand Twenty to Two Thousand Forty Seven [Member]
Business Acquisition [Line Items]
Weighted- average Coupon (percentage)	[3]	5.07%
Total principal		$ 700
SCANA | Others due Two Thousand Nineteen to Two Thousand Twenty Seven [Member]
Business Acquisition [Line Items]
Weighted- average Coupon (percentage)	[3]	3.46%
Total principal		$ 73

[1] 2017 excludes $250 million of Dominion Energy Questar Pipeline's senior notes that matured in February 2018 using proceeds from the January 2018 issuance, through private placements, of $100 million and $150 million of senior notes that mature in 2028 and 2038, respectively.

[2] Includes $20 million of estimated mandatory prepayments due within one year based on estimated cash flows in excess of debt service at SBL Holdco and Dominion Solar Projects III, Inc.

[3] Represents weighted-average coupon rates for debt outstanding at closing of the SCANA Combination.

[4] Includes variable rate debt of $68 million, with a weighted-average interest rate of 1.72%, which is hedged by fixed swaps

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Acquisitions and Dispositions (Scheduled Principal Payments of Long-Term Debt) (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Debt Instrument [Line Items]
Weighted- average Coupon, 2019	3.23%
Weighted- average Coupon, 2020	2.80%
Weighted- average Coupon, 2021	3.64%
Weighted- average Coupon, 2022	3.02%
Weighted- average Coupon, 2023	3.41%
Weighted- average Coupon, Thereafter	4.51%
SCANA
Debt Instrument [Line Items]
2019	$ 59
2020	368
2021	797
2022	266
2023	14
Thereafter	5,291
Total	$ 6,795
Weighted- average Coupon, 2019	3.91%
Weighted- average Coupon, 2020	6.26%
Weighted- average Coupon, 2021	4.20%
Weighted- average Coupon, 2022	5.22%
Weighted- average Coupon, 2023	3.29%
Weighted- average Coupon, Thereafter	5.51%
Weighted- average Coupon, Total	5.36%
SCANA | Unsecured Senior Notes
Debt Instrument [Line Items]
2019	$ 4
2020	4
2021	4
2022	4
2023	4
Thereafter	50
Total	70
SCANA | Unsecured Medium-term Notes [Member]
Debt Instrument [Line Items]
2020	250
2021	300
2022	250
Total	800
SCANA | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
2021	330
Thereafter	4,660
Total	4,990
SCANA | PSNC Senior Notes And Debentures [Member]
Debt Instrument [Line Items]
2020	100
2021	150
Thereafter	450
Total	700
SCANA | Senior Notes
Debt Instrument [Line Items]
2019	7
2020	7
2021	7
2022	7
2023	7
Thereafter	5
Total	40
SCANA | Industrial and Pollution Control Bonds [Member]
Debt Instrument [Line Items]
Thereafter	122
Total	122
SCANA | Other Long Term Debt [Member]
Debt Instrument [Line Items]
2019	48
2020	7
2021	6
2022	5
2023	3
Thereafter	4
Total	$ 73

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Acquisitions and Dispositions (Long-term Purchase Commitment) (Detail) - SCANA - Purchased electric capacity $ in Millions	Dec. 31, 2018 USD ($)	[1]
Debt Instrument [Line Items]
2019	$ 31
2020	30
2021	30
2022	30
2023	30
Thereafter	310
Total	$ 461

[1] Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities which expire at various dates through 2046. Capacity payments under the contracts are generally based on fixed dollar amounts per month.

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Acquisitions and Dispositions (Lease Commitments) (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Debt Instrument [Line Items]
2019	$ 64
2020	61
2021	55
2022	47
2023	38
Thereafter	384
Total	649
SCANA
Debt Instrument [Line Items]
2019	10
2020	8
2021	7
2022	6
2023	4
Thereafter	30
Total	$ 65

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Acquisitions and Dispositions (Schedule of Unaudited Pro Forma Information) (Detail) - Dominion Energy Questar Corporation - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	[1]	Dec. 31, 2016	[2]
Business Acquisition [Line Items]
Operating Revenue	$ 17,505		$ 12,497
Net income attributable to Dominion Energy	$ 2,081		$ 2,300
Earnings Per Common Share - Basic	$ 2.78		$ 3.73
Earnings Per Common Share - Diluted	$ 2.77		$ 3.73

[1] Amounts include adjustments for non-recurring costs directly related to the SCANA Combination.

[2] Amounts include adjustments for non-recurring costs directly related to the Dominion Energy Questar Combination.

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Acquisitions and Dispositions (Acquisition of Dominion Energy Questar) (Narrative) (Detail) - USD ($) $ / shares in Units, $ in Millions			1 Months Ended					3 Months Ended		12 Months Ended
	Dec. 01, 2016	Sep. 16, 2016	Jul. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Aug. 31, 2016	Apr. 30, 2016	Sep. 30, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition And Dispositions [Line Items]
Issuance of common stock										$ 2,461	$ 1,302	$ 2,152
Issuance of short-term notes										1,450		1,200
Issuance of common stock										2,461	1,302	2,152
Increase (decrease) to goodwill related modifications to preliminary valuation amounts										5
Other Commitment, Fiscal Year Maturity [Abstract]
Repayment of short-term notes										$ 1,450	$ 250	$ 1,800
Dominion Energy Questar Pipeline LLC | Dominion Energy Midstream Partners, LP | Subsidiary of Common Parent | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Other Commitment, Fiscal Year Maturity [Abstract]
Cash consideration	$ 823
Debt financed distribution	300
Amount of consideration	1,300
Dominion Energy Questar Pipeline LLC | Dominion Energy Midstream Partners, LP | Subsidiary of Common Parent | Partnership Interest | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Other Commitment, Fiscal Year Maturity [Abstract]
Combined value of common and convertible preferred units	$ 467
Dominion Energy Questar Pipeline LLC | Dominion Energy Midstream Partners, LP | Limited Partner | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Senior Unsecured Promissory Note Payable | Notes Payable, Other Payables
Other Commitment, Fiscal Year Maturity [Abstract]
Repayments of promissory note				$ 301
Dominion Energy Questar Pipeline LLC | Dominion Energy Midstream Partners, LP | Limited Partner | Common Units | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Other Commitment, Fiscal Year Maturity [Abstract]
Number of common units to be purchased				6,656,839
Questar Fueling Company | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Other Commitment, Fiscal Year Maturity [Abstract]
Cash consideration				$ 28
Underwritten Public Offering
Business Acquisition And Dispositions [Line Items]
Issuance of common stock							$ 756
Term Loans | Dominion Energy Questar Pipeline LLC | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Private Placement Term Loan Agreement Maturing in September 2017
Other Commitment, Fiscal Year Maturity [Abstract]
Repayment of short-term notes				$ 1,200
Capital Unit, Class A
Business Acquisition And Dispositions [Line Items]
Issuance of common stock			$ 1,000
Dominion Energy Questar Corporation
Business Acquisition And Dispositions [Line Items]
Price per share		$ 25.00
Total consideration		$ 4,400
Number of shares of Dominion Questar outstanding at closing		175,500,000
Issuance of senior notes						$ 1,300
Increase (decrease) to goodwill related modifications to preliminary valuation amounts								$ 6	$ (6)
Contributions to fund Dominion Questar's qualified and non-qualified defined benefit pension plans		$ 75
Dominion Energy Questar Corporation | Commitment for Charitable Contributions
Other Commitment, Fiscal Year Maturity [Abstract]
Charitable contributions, next twelve months		1
Charitable contributions, second year		1
Charitable contributions, third year		1
Charitable contributions, fourth year		1
Charitable contributions, fifth year		$ 1
Dominion Energy Questar Corporation | Commitment for Charitable Contributions | Minimum
Other Commitment, Fiscal Year Maturity [Abstract]
Period for charitable contributions		5 years
Dominion Energy Questar Corporation | White River Hub LLC
Business Acquisition And Dispositions [Line Items]
Ownership percentage		50.00%
Dominion Energy Questar Corporation | Underwritten Public Offering
Business Acquisition And Dispositions [Line Items]
Issuance of common stock							$ 500
Dominion Energy Questar Corporation | Term Loans
Business Acquisition And Dispositions [Line Items]
Issuance of short-term notes					$ 1,200
Dominion Energy Questar Corporation | Capital Unit, Class A
Business Acquisition And Dispositions [Line Items]
Issuance of common stock						$ 1,400

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Acquisitions and Dispositions (Schedule of Preliminary Allocation of Purchase Price to Assets Acquired and Liabilities Assumed) (Parenthetical) (Detail) - Dominion Energy Questar Corporation - USD ($) $ in Millions	Sep. 16, 2016	Dec. 31, 2018
Business Acquisition [Line Items]
Short-term debt	$ 301
White River Hub LLC
Business Acquisition [Line Items]
Equity method investment	$ 40
Minimum
Business Acquisition [Line Items]
Estimated useful lives	9 years
Maximum
Business Acquisition [Line Items]
Estimated useful lives	18 years
Unsecured Senior Notes | Minimum
Business Acquisition [Line Items]
Interest rate (percentage)		2.98%
Unsecured Senior Notes | Maximum
Business Acquisition [Line Items]
Interest rate (percentage)		7.20%
Variable Interest Rate Short Term Loan Due in August 2017 [Member]
Business Acquisition [Line Items]
Short-term note outstanding	$ 250

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Acquisitions and Dispositions (Results of Operations and Pro Forma Information) (Narrative) (Detail) - Dominion Energy Questar Corporation - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Increase in operating revenue			$ 379
Increase in net income			73
Other operations and maintenance
Business Acquisition [Line Items]
Transaction and transition costs incurred	$ 9	$ 26	58
Interest And Related Charges
Business Acquisition [Line Items]
Transaction and transition costs incurred			$ 16

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Acquisitions and Dispositions (Schedule of Acquisitions of Solar Projects) (Detail) $ in Millions		1 Months Ended						12 Months Ended
		Oct. 31, 2017 USD ($) Project MW	Sep. 30, 2017 USD ($) Project MW	Jun. 30, 2017 USD ($) Project MW	May 31, 2017 USD ($) Project MW	Mar. 31, 2017 USD ($) Project MW	Feb. 28, 2017 USD ($) Project MW	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Business Acquisition [Line Items]
Project Cost								$ 151	$ 405	$ 40
Community Energy Solar, Inc
Business Acquisition [Line Items]
Number of Projects | Project							1
Total consideration	[1],[2]						$ 29
Project Cost	[3]						$ 205
MW capacity | MW							100
Solar Frontier Americas Holding, LLC
Business Acquisition [Line Items]
Number of Projects | Project	[4]					1
Total consideration	[1],[2]					$ 77
Project Cost	[3]					$ 78
MW capacity | MW						30
Solar Projects from Cypress Creek Renewables, LLC
Business Acquisition [Line Items]
Number of Projects | Project					1
Total consideration	[1],[2]				$ 154
Project Cost	[3]				$ 160
MW capacity | MW					79
Hecate Energy Virginia C&C LLC
Business Acquisition [Line Items]
Number of Projects | Project			1	1
Total consideration	[1],[2]		$ 40	$ 16
Project Cost	[3]		$ 41	$ 16
MW capacity | MW			20	10
Strata Solar Development, LLC/Moorings Farm 2 Holdco, LLC
Business Acquisition [Line Items]
Number of Projects | Project				2
Total consideration	[1],[2]			$ 20
Project Cost	[3]			$ 20
MW capacity | MW				10
Strata Solar Development, LLC
Business Acquisition [Line Items]
Number of Projects | Project		2
Total consideration	[1],[2]	$ 20
Project Cost	[3]	$ 21
MW capacity | MW		10

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

[2] The purchase price was primarily allocated to Property, Plant and Equipment.

[3] Includes acquisition cost.

[4] In April 2017, Dominion Energy discontinued efforts on the acquisition of the additional 20 MW solar project from Solar Frontier Americas Holding LLC.

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Acquisitions and Dispositions (Schedule of Acquisitions of Solar Projects) (Parenthetical) (Detail)	1 Months Ended
	Apr. 30, 2017 MW
Business Combinations Discontinued Operations And Disposal Groups [Abstract]
Discontinued efforts on acquisition of additional MW capacity	20

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Acquisitions and Dispositions (Merchant Solar Projects) (Narrative) (Detail) $ in Millions	1 Months Ended		12 Months Ended
	Dec. 31, 2015 USD ($) Project	Sep. 30, 2015 Project MW	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($) Project MW	Jan. 31, 2016 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Project Cost			$ 151	$ 405	$ 40
Merchant Solar Projects | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
MW capacity | MW		425
Number of solar projects | Project		24
Total number of solar projects related to potential sale | Project	15
Amount of consideration	$ 184					$ 117
Merchant Solar Projects | Disposal Group, Disposed of by Sale, Not Discontinued Operations | SunEdison, Inc
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of equity interest sold to non-controlling interest owners		33.00%
Number of Solar Development Projects in Operation [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of equity interests acquired					100.00%
Number of Projects | Project					7
Aggregate purchase price					$ 32
Project Cost					$ 421
MW capacity | MW					221

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Acquisitions and Dispositions (Narrative) (Detail) $ in Millions	1 Months Ended		3 Months Ended	12 Months Ended
	Sep. 30, 2015 USD ($) Project	Jun. 30, 2015 USD ($) Project MW	Sep. 30, 2016 USD ($) MW	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Nov. 30, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Project Cost				$ 151	$ 405	$ 40
Four Brothers Solar, LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of equity interests acquired		50.00%
Number of Projects | Project		4
Purchase price		$ 64
MW capacity | MW		320
Project Cost			$ 670
Three Cedars
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of equity interests acquired	50.00%
Number of Projects | Project	3
Purchase price	$ 43
MW capacity | MW			210
Project Cost			$ 450
Four Brothers and Three Cedars | Investment Credits | IRS
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of federal investment tax credits on projects claimed				99.00%
NRG Energy, Inc
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contributions from SunEdison and NRG to Four Brothers and Three Cedars					9
NRG Energy, Inc | Four Brothers and Three Cedars
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of equity interests acquired							50.00%
Sun Edison Inc
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contributions from SunEdison and NRG to Four Brothers and Three Cedars						$ 189
Sun Edison Inc | Four Brothers and Three Cedars
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contributions from SunEdison and NRG to Four Brothers and Three Cedars					$ 301

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Operating Revenue (Schedule of Operating Revenue Recognition from Contracts with Customers) (Detail) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Public Utilities General Disclosures [Line Items]
Operating revenue		$ 3,361	$ 3,451	$ 3,088	$ 3,466	$ 3,210	$ 3,179	$ 2,813	$ 3,384	$ 13,366	[1]	$ 12,586	[1]	$ 11,737	[1]
Virginia Electric and Power Company
Public Utilities General Disclosures [Line Items]
Operating revenue		1,810	2,232	1,829	1,748	1,824	2,154	1,747	1,831	7,619	[2]	7,556	[2]	7,588	[2]
Dominion Energy Gas Holdings, LLC
Public Utilities General Disclosures [Line Items]
Operating revenue		$ 532	$ 423	$ 459	$ 526	$ 501	$ 401	$ 422	$ 490	1,940	[3]	$ 1,814	[3]	$ 1,638	[3]
Subsequent To Adoption of Revised Guidance
Public Utilities General Disclosures [Line Items]
Operating revenue										12,895
Nonregulated electric sales										1,294
Nonregulated gas sales										214
Nonregulated gas transportation and storage										442
Other regulated revenues										179
Other nonregulated revenues	[4],[5]									563
Operating revenue										13,366
Subsequent To Adoption of Revised Guidance | FERC-regulated
Public Utilities General Disclosures [Line Items]
Regulated gas transportation and storage										1,091
Subsequent To Adoption of Revised Guidance | State-regulated
Public Utilities General Disclosures [Line Items]
Regulated gas transportation and storage										640
Subsequent To Adoption of Revised Guidance | Residential
Public Utilities General Disclosures [Line Items]
Regulated gas sales										818
Subsequent To Adoption of Revised Guidance | Commercial
Public Utilities General Disclosures [Line Items]
Regulated gas sales										221
Subsequent To Adoption of Revised Guidance | Other
Public Utilities General Disclosures [Line Items]
Regulated gas sales										36
Subsequent To Adoption of Revised Guidance | Regulated Electric Sales | Residential
Public Utilities General Disclosures [Line Items]
Operating revenue										3,413
Subsequent To Adoption of Revised Guidance | Regulated Electric Sales | Commercial
Public Utilities General Disclosures [Line Items]
Operating revenue										2,503
Subsequent To Adoption of Revised Guidance | Regulated Electric Sales | Industrial
Public Utilities General Disclosures [Line Items]
Operating revenue										490
Subsequent To Adoption of Revised Guidance | Regulated Electric Sales | Government and Other Retail
Public Utilities General Disclosures [Line Items]
Operating revenue										854
Subsequent To Adoption of Revised Guidance | Regulated Electric Sales | Wholesale
Public Utilities General Disclosures [Line Items]
Operating revenue										137
Subsequent To Adoption of Revised Guidance | Other
Public Utilities General Disclosures [Line Items]
Operating revenue	[4],[6]									471
Subsequent To Adoption of Revised Guidance | Virginia Electric and Power Company
Public Utilities General Disclosures [Line Items]
Operating revenue										7,584
Other regulated revenues										132
Other nonregulated revenues	[4],[5]									55
Operating revenue										7,619
Subsequent To Adoption of Revised Guidance | Virginia Electric and Power Company | Regulated Electric Sales | Residential
Public Utilities General Disclosures [Line Items]
Operating revenue										3,413
Subsequent To Adoption of Revised Guidance | Virginia Electric and Power Company | Regulated Electric Sales | Commercial
Public Utilities General Disclosures [Line Items]
Operating revenue										2,503
Subsequent To Adoption of Revised Guidance | Virginia Electric and Power Company | Regulated Electric Sales | Industrial
Public Utilities General Disclosures [Line Items]
Operating revenue										490
Subsequent To Adoption of Revised Guidance | Virginia Electric and Power Company | Regulated Electric Sales | Government and Other Retail
Public Utilities General Disclosures [Line Items]
Operating revenue										854
Subsequent To Adoption of Revised Guidance | Virginia Electric and Power Company | Regulated Electric Sales | Wholesale
Public Utilities General Disclosures [Line Items]
Operating revenue										137
Subsequent To Adoption of Revised Guidance | Virginia Electric and Power Company | Other
Public Utilities General Disclosures [Line Items]
Operating revenue	[5],[6]									35
Subsequent To Adoption of Revised Guidance | Dominion Energy Gas Holdings, LLC
Public Utilities General Disclosures [Line Items]
Operating revenue										1,949
Nonregulated gas sales	[5]									13
Other regulated revenues	[5]									22
Other nonregulated revenues	[5]									10
Operating revenue										1,940
Management service revenue	[5]									205
Subsequent To Adoption of Revised Guidance | Dominion Energy Gas Holdings, LLC | FERC-regulated
Public Utilities General Disclosures [Line Items]
Regulated gas transportation and storage	[5]									763
Subsequent To Adoption of Revised Guidance | Dominion Energy Gas Holdings, LLC | State-regulated
Public Utilities General Disclosures [Line Items]
Regulated gas transportation and storage	[5]									605
Subsequent To Adoption of Revised Guidance | Dominion Energy Gas Holdings, LLC | Residential
Public Utilities General Disclosures [Line Items]
Regulated gas sales										81
Subsequent To Adoption of Revised Guidance | Dominion Energy Gas Holdings, LLC | Other
Public Utilities General Disclosures [Line Items]
Regulated gas sales										27
Subsequent To Adoption of Revised Guidance | Dominion Energy Gas Holdings, LLC | Other
Public Utilities General Disclosures [Line Items]
Operating revenue										(9)
Subsequent To Adoption of Revised Guidance | Dominion Energy Gas Holdings, LLC | NGL Production
Public Utilities General Disclosures [Line Items]
Operating revenue	[4],[5]									$ 223

[1] See Note 9 for amounts attributable to related parties.

[2] See Note 24 for amounts attributable to affiliates.

[3] See Note 24 for amounts attributable to related parties.

[4] Amounts above include $241 million and $206 million for the year ended December 31, 2018 primarily consisting of NGL sales at Dominion Energy and Dominion Energy Gas, respectively, which are considered to be goods transferred at a point in time. In addition, the amounts include $17 million and $11 million of sales of renewable energy credits at both Dominion Energy and Virginia Power for the year ended December 31, 2018, respectively, which are considered to be goods transferred at a point in time.

[5] See Notes 9 and 24 for amounts attributable to related parties and affiliates.

[6] Amounts above include $15 million of alternative revenue at Dominion Energy and Virginia Power for the year ended December 31, 2018.

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Operating Revenue (Schedule of Operating Revenue Recognition from Contracts with Customers) (Parenthetical) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Public Utilities General Disclosures [Line Items]
Alternative revenue	$ 15
NGL Midstream
Public Utilities General Disclosures [Line Items]
Sales revenue	241
Renewable Energy Investment Tax Credits
Public Utilities General Disclosures [Line Items]
Sales revenue	17
Virginia Electric and Power Company | Renewable Energy Investment Tax Credits
Public Utilities General Disclosures [Line Items]
Sales revenue	11
Dominion Energy Gas Holdings, LLC | NGL Midstream
Public Utilities General Disclosures [Line Items]
Sales revenue	$ 206

XML

Operating Revenue (Schedule of Aggregate Amount of Transaction Price Allocated To Fixed-price Performance Obligations That Unsatisfied At End of Reporting Period And Expected To be Recognized) (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2019-01-01
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 1,643
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2019-01-01 | Virginia Electric and Power Company
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 21
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2019-01-01 | Dominion Energy Gas Holdings, LLC
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 600
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 1,563
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01 | Virginia Electric and Power Company
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 3
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01 | Dominion Energy Gas Holdings, LLC
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 560
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 1,448
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01 | Virginia Electric and Power Company
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 1
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01 | Dominion Energy Gas Holdings, LLC
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 475
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 1,319
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01 | Virginia Electric and Power Company
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 0
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01 | Dominion Energy Gas Holdings, LLC
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 384
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 1,154
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01 | Virginia Electric and Power Company
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 0
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01 | Dominion Energy Gas Holdings, LLC
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 268
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 13,693
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01 | Virginia Electric and Power Company
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 0
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01 | Dominion Energy Gas Holdings, LLC
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 1,612
Revenue, expected to be recognized on multi-year contracts, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: (nil) [Member]
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 20,820
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: (nil) [Member] | Virginia Electric and Power Company
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	25
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: (nil) [Member] | Dominion Energy Gas Holdings, LLC
Revenues From Contract With Customer [Line Items]
Revenue, expected to be recognized on multi-year contracts	$ 3,899

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Operative Revenue (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenues From Contract With Customer [Line Items]
Contract asset balances	$ 42	$ 46
Contract liability balances	106	132
Revenue recognized from contract liability balances	94
Dominion Energy Gas Holdings, LLC
Revenues From Contract With Customer [Line Items]
Contract asset balances	58	66
Contract liability balances	40	41
Revenue recognized from contract liability balances	41
Virginia Electric and Power Company
Revenues From Contract With Customer [Line Items]
Contract liability balances	22	$ 50
Revenue recognized from contract liability balances	$ 25

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Operating Revenue (Schedule of Operating Revenue Prior to Revised Guidance of Revenue Recognition From Contracts with Customers ) (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Public Utilities General Disclosures [Line Items]
Total operating revenue	$ 3,361	$ 3,451	$ 3,088	$ 3,466	$ 3,210	$ 3,179	$ 2,813	$ 3,384	$ 13,366	[1]	$ 12,586	[1]	$ 11,737	[1]
Virginia Electric and Power Company
Public Utilities General Disclosures [Line Items]
Total operating revenue	1,810	2,232	1,829	1,748	1,824	2,154	1,747	1,831	7,619	[2]	7,556	[2]	7,588	[2]
Dominion Energy Gas Holdings, LLC
Public Utilities General Disclosures [Line Items]
Total operating revenue	$ 532	$ 423	$ 459	$ 526	$ 501	$ 401	$ 422	$ 490	$ 1,940	[3]	1,814	[3]	1,638	[3]
Prior to adoption of revised guidance
Public Utilities General Disclosures [Line Items]
Nonregulated electric sales											1,429		1,519
Regulated gas sales											1,067		500
Nonregulated gas sales											457		354
Total operating revenue											12,586		11,737
Prior to adoption of revised guidance | Regulated Electric Sales
Public Utilities General Disclosures [Line Items]
Revenue											7,383		7,348
Prior to adoption of revised guidance | Gas Transportation and Storage
Public Utilities General Disclosures [Line Items]
Revenue											1,786		1,636
Prior to adoption of revised guidance | Other
Public Utilities General Disclosures [Line Items]
Revenue											464		380
Prior to adoption of revised guidance | Virginia Electric and Power Company
Public Utilities General Disclosures [Line Items]
Total operating revenue											7,556		7,588
Prior to adoption of revised guidance | Virginia Electric and Power Company | Regulated Electric Sales
Public Utilities General Disclosures [Line Items]
Revenue											7,383		7,348
Prior to adoption of revised guidance | Virginia Electric and Power Company | Other
Public Utilities General Disclosures [Line Items]
Revenue											173		240
Prior to adoption of revised guidance | Dominion Energy Gas Holdings, LLC
Public Utilities General Disclosures [Line Items]
Regulated gas sales											87		119
Nonregulated gas sales											20		13
Total operating revenue											1,814		1,638
Prior to adoption of revised guidance | Dominion Energy Gas Holdings, LLC | Gas Transportation and Storage
Public Utilities General Disclosures [Line Items]
Revenue											1,435		1,307
Prior to adoption of revised guidance | Dominion Energy Gas Holdings, LLC | Other
Public Utilities General Disclosures [Line Items]
Revenue											181		137
Prior to adoption of revised guidance | Dominion Energy Gas Holdings, LLC | NGL Production
Public Utilities General Disclosures [Line Items]
Revenue											$ 91		$ 62

[1] See Note 9 for amounts attributable to related parties.

[2] See Note 24 for amounts attributable to affiliates.

[3] See Note 24 for amounts attributable to related parties.

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Income Taxes (Narrative) (Detail) - USD ($) $ in Millions	1 Months Ended		3 Months Ended	12 Months Ended
	Oct. 31, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
Federal statutory income tax rate				21.00%	35.00%	35.00%
State deferred income tax expense				$ (1)	$ 132	$ 50
Current federal income taxes				63	(27)	(70)
Deferred income tax expense			$ (851)	46	(851)	0
Benefit for deferred income taxes						96
Increase (Decrease) to deferred income tax expense				23
Increase (Decrease) in regulatory liabilities				35	4,200
Decrease in unrecognized tax benefits due to settlement				6	23	8
Unrecognized tax benefits that would impact effective tax rate			31	37	31	45
Decrease in accumulated deferred income tax liability			3,100		3,100
Increase in deferred tax asset					1,100
Increase (Decrease) in tax expense as a result of changes in unrecognized tax benefits				(5)	$ (9)	(18)
Carryback claim for specified liability losses involving prior tax years
Income Taxes [Line Items]
Current federal income taxes				(47)
Maximum
Income Taxes [Line Items]
State deferred income tax expense				1
Decrease in Unrecognized tax benefits due to settlement negotiations and expiration of statutes of limitations				18
Amount that earnings could potentially increase if changes were to occur				$ 17
Federal
Income Taxes [Line Items]
Federal tax credits						129
Realizable domestic production activities deduction						17
Federal | Dominion Midstream Partners, LP | Questar Pipeline, LLC | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Taxes [Line Items]
Current federal income taxes						$ 212
Virginia Electric and Power Company
Income Taxes [Line Items]
Federal statutory income tax rate				21.00%	35.00%	35.00%
State deferred income tax expense				$ 55	$ 59	$ 27
Current federal income taxes				76	505	258
Deferred income tax expense			(93)	21	(93)	0
Increase (Decrease) to deferred income tax expense				23
Increase (Decrease) in regulatory liabilities	$ 14			31	2,600
Decrease in unrecognized tax benefits due to settlement		$ 8		1	8
Unrecognized tax benefits that would impact effective tax rate		2	3	2	3	9
Interest income		$ 11
Decrease in accumulated deferred income tax liability			1,900		1,900
Increase in deferred tax asset					700
Increase (Decrease) in tax expense as a result of changes in unrecognized tax benefits				$ (2)	$ (6)	$ 1
Dominion Energy Gas Holdings, LLC
Income Taxes [Line Items]
Federal statutory income tax rate				21.00%	35.00%	35.00%
State deferred income tax expense				$ (4)	$ 20	$ 1
Current federal income taxes				53	24	(23)
Deferred income tax expense			(197)	(11)	(197)	0
Increase (Decrease) to deferred income tax expense				11
Increase (Decrease) in regulatory liabilities				(16)	1,000
Decrease in unrecognized tax benefits due to settlement					7	4
Unrecognized tax benefits that would impact effective tax rate						5
Decrease in accumulated deferred income tax liability			800		800
Increase in deferred tax asset					200
Increase (Decrease) in tax expense as a result of changes in unrecognized tax benefits				(1)	(5)	$ (11)
Dominion Energy Gas Holdings, LLC | Maximum
Income Taxes [Line Items]
Unrecognized tax benefits that would impact effective tax rate			$ 1	1	$ 1
Decrease in Unrecognized tax benefits due to settlement negotiations and expiration of statutes of limitations				1
Amount that earnings could potentially increase if changes were to occur				$ 1

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Income Taxes (Income Tax Expense for Continuing Operations Including Noncontrolling Interests) (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current:
Federal		$ (45)	$ (1)	$ (155)
State		108	(26)	85
Total current expense (benefit)		63	(27)	(70)
Deferred:
2017 Tax Reform Act impact	$ (851)	46	(851)	0
Taxes before operating loss carryforwards and investment tax credits		436	739	1,050
Tax utilization expense (benefit) of operating loss carryforwards		92	174	(161)
Investment tax credits		(56)	(200)	(248)
State		(1)	132	50
Total deferred expense (benefit)		517	(6)	691
Investment tax credit-gross deferral		2	5	35
Investment tax credit-amortization		(2)	(2)	(1)
Total income tax expense (benefit)		580	(30)	655
Virginia Electric and Power Company
Current:
Federal		36	432	168
State		40	73	90
Total current expense (benefit)		76	505	258
Deferred:
2017 Tax Reform Act impact	(93)	21	(93)	0
Taxes before operating loss carryforwards and investment tax credits		199	319	435
Tax utilization expense (benefit) of operating loss carryforwards		0	4	(2)
Investment tax credits		(51)	(23)	(25)
State		55	59	27
Total deferred expense (benefit)		224	266	435
Investment tax credit-gross deferral		2	5	35
Investment tax credit-amortization		(2)	(2)	(1)
Total income tax expense (benefit)		300	774	727
Dominion Energy Gas Holdings, LLC
Current:
Federal		23	16	(27)
State		30	8	4
Total current expense (benefit)		53	24	(23)
Deferred:
2017 Tax Reform Act impact	$ (197)	(11)	(197)	0
Taxes before operating loss carryforwards and investment tax credits		48	199	239
Tax utilization expense (benefit) of operating loss carryforwards		0	5	(2)
Investment tax credits		0	0	0
State		(4)	20	1
Total deferred expense (benefit)		33	27	238
Investment tax credit-gross deferral		0	0	0
Investment tax credit-amortization		0	0	0
Total income tax expense (benefit)		$ 86	$ 51	$ 215

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Income Taxes (Reconciliation of Income Taxes at the U.S. Statutory Federal Income Tax Rate) (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Effective Income Tax Computation [Line Items]
U.S. statutory rate	21.00%	35.00%	35.00%
Increases (reductions) resulting from:
State taxes, net of federal benefit	3.00%	2.00%	2.40%
Investment tax credits	(1.90%)	(6.30%)	(11.70%)
Production tax credits	(0.70%)	(0.70%)	(0.80%)
Valuation allowances	0.30%	0.20%	1.20%
Reversal of excess deferred income taxes	(2.00%)
Federal legislative change	1.50%	(27.50%)
State legislative change	(0.60%)		(0.60%)
AFUDC-equity	(0.80%)	(1.40%)	(0.60%)
Employee stock ownership plan deduction	(0.40%)	(0.60%)	(0.60%)
Other, net	(0.90%)	(1.70%)	(1.40%)
Effective tax rate	18.50%	(1.00%)	22.90%
Virginia Electric and Power Company
Effective Income Tax Computation [Line Items]
U.S. statutory rate	21.00%	35.00%	35.00%
Increases (reductions) resulting from:
State taxes, net of federal benefit	4.70%	3.70%	3.80%
Investment tax credits	(3.50%)	(0.80%)
Production tax credits	(0.70%)	(0.40%)	(0.50%)
Valuation allowances			0.10%
Reversal of excess deferred income taxes	(3.20%)
Federal legislative change	1.30%	(4.00%)
AFUDC-equity	(0.50%)	(0.60%)	(0.60%)
Other, net	(0.10%)	0.60%	(0.40%)
Effective tax rate	19.00%	33.50%	37.40%
Dominion Energy Gas Holdings, LLC
Effective Income Tax Computation [Line Items]
U.S. statutory rate	21.00%	35.00%	35.00%
Increases (reductions) resulting from:
State taxes, net of federal benefit	3.20%	2.40%	0.50%
Valuation allowances	1.80%	0.30%
Reversal of excess deferred income taxes	(1.70%)
Federal legislative change	(2.80%)	(29.50%)
State legislative change	0.20%
AFUDC-equity	(0.60%)	(0.90%)	(0.20%)
Other, net	1.20%	0.40%	0.10%
Effective tax rate	22.30%	7.70%	35.40%

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Income Taxes (Schedule of Deferred Income Taxes) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred income taxes:
Total deferred income tax assets	$ 2,748	$ 2,686
Total deferred income tax liabilities	7,813	7,158
Total net deferred income tax liabilities	5,065	4,472
Plant and equipment, primarily depreciation method and basis differences	4,933	5,056
Excess deferred income taxes	(993)	(1,050)
Nuclear decommissioning	815	829
Deferred state income taxes	626	834
Federal benefit of deferred state income taxes	(132)	(175)
Deferred fuel, purchased energy and gas costs	60	1
Pension benefits	81	141
Other postretirement benefits	(5)	(51)
Loss and credit carryforwards	(1,546)	(1,536)
Valuation allowances	158	146
Partnership basis differences	1,135	473
Other	(67)	(196)
Total net deferred income tax liabilities	5,065	4,472
Deferred Investment Tax Credits - Regulated Operations	51	51
Total Deferred Taxes and Deferred Investment Tax Credits	5,116	4,523
Virginia Electric and Power Company
Deferred income taxes:
Total deferred income tax assets	1,054	923
Total deferred income tax liabilities	4,020	3,600
Total net deferred income tax liabilities	2,966	2,677
Plant and equipment, primarily depreciation method and basis differences	3,367	2,969
Excess deferred income taxes	(678)	(687)
Nuclear decommissioning	273	260
Deferred state income taxes	284	378
Federal benefit of deferred state income taxes	(60)	(79)
Deferred fuel, purchased energy and gas costs	59	(3)
Pension benefits	(132)	(104)
Other postretirement benefits	55	44
Loss and credit carryforwards	(183)	(111)
Valuation allowances	5	5
Other	(24)	5
Total net deferred income tax liabilities	2,966	2,677
Deferred Investment Tax Credits - Regulated Operations	51	51
Total Deferred Taxes and Deferred Investment Tax Credits	3,017	2,728
Dominion Energy Gas Holdings, LLC
Deferred income taxes:
Total deferred income tax assets	318	320
Total deferred income tax liabilities	1,783	1,774
Total net deferred income tax liabilities	1,465	1,454
Plant and equipment, primarily depreciation method and basis differences	1,170	1,132
Excess deferred income taxes	(254)	(244)
Deferred state income taxes	175	227
Federal benefit of deferred state income taxes	(37)	(48)
Deferred fuel, purchased energy and gas costs	1	2
Pension benefits	431	419
Other postretirement benefits	(1)	(2)
Loss and credit carryforwards	(7)	(4)
Valuation allowances	12	3
Partnership basis differences	26	26
Other	(51)	(57)
Total net deferred income tax liabilities	1,465	1,454
Total Deferred Taxes and Deferred Investment Tax Credits	$ 1,465	$ 1,454

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Income Taxes (Schedule of Deductible Loss and Credit Carryforwards) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Deductible loss and credit carryforwards [Line Items]
Deductible amount	$ 1,246
Deferred Tax Asset	1,546
Valuation Allowance	(151)
Virginia Electric and Power Company
Deductible loss and credit carryforwards [Line Items]
Deductible amount	1
Deferred Tax Asset	183
Valuation Allowance	(5)
Dominion Energy Gas Holdings, LLC
Deductible loss and credit carryforwards [Line Items]
Deductible amount	53
Deferred Tax Asset	6
Valuation Allowance	(5)
Federal
Deductible loss and credit carryforwards [Line Items]
Deductible amount	120
Losses, Deferred tax asset	25
Losses, Valuation allowance	0
Tax credits, Deferred tax asset	62
Federal | Virginia Electric and Power Company
Deductible loss and credit carryforwards [Line Items]
Deductible amount	$ 1
Losses, Expiration Period	2034
Federal | Dominion Energy Gas Holdings, LLC
Deductible loss and credit carryforwards [Line Items]
Tax credits, Deductible amount	$ 0
Tax credits, Deferred tax asset	1
Tax Credits, Valuation allowance	0
Federal | Investment Credits
Deductible loss and credit carryforwards [Line Items]
Tax credits, Deferred tax asset	1,007
Federal | Investment Credits | Virginia Electric and Power Company
Deductible loss and credit carryforwards [Line Items]
Tax credits, Deferred tax asset	113
Federal | Federal production credits
Deductible loss and credit carryforwards [Line Items]
Tax credits, Deferred tax asset	150
Federal | Federal Production And Other Credits | Virginia Electric and Power Company
Deductible loss and credit carryforwards [Line Items]
Tax credits, Deferred tax asset	61
State
Deductible loss and credit carryforwards [Line Items]
Deductible amount	1,126
Losses, Deferred tax asset	73
Losses, Valuation allowance	(61)
State minimum tax credits	122
State | Dominion Energy Gas Holdings, LLC
Deductible loss and credit carryforwards [Line Items]
Deductible amount	53
Losses, Deferred tax asset	5
Losses, Valuation allowance	(5)
State | Investment Credits | Virginia Electric and Power Company
Deductible loss and credit carryforwards [Line Items]
Tax credits, Deferred tax asset	9
Tax Credits, Valuation allowance	(5)
State | Investment and Other Credit
Deductible loss and credit carryforwards [Line Items]
Tax credits, Deferred tax asset	107
Tax Credits, Valuation allowance	$ (90)
Earliest Tax Year | Federal
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2031
Earliest Tax Year | Federal | Dominion Energy Gas Holdings, LLC
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2032
Earliest Tax Year | Federal | Investment Credits
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2033
Earliest Tax Year | Federal | Investment Credits | Virginia Electric and Power Company
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2034
Earliest Tax Year | Federal | Federal production credits
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2031
Earliest Tax Year | Federal | Federal Production And Other Credits | Virginia Electric and Power Company
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2031
Earliest Tax Year | State
Deductible loss and credit carryforwards [Line Items]
Losses, Expiration Period	2019
Earliest Tax Year | State | Dominion Energy Gas Holdings, LLC
Deductible loss and credit carryforwards [Line Items]
Losses, Expiration Period	2036
Earliest Tax Year | State | Investment and Other Credit
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2019
Latest Tax Year | Federal
Deductible loss and credit carryforwards [Line Items]
Losses, Expiration Period	2034
Tax Credits, Expiration Period	2038
Latest Tax Year | Federal | Dominion Energy Gas Holdings, LLC
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2037
Latest Tax Year | Federal | Investment Credits
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2038
Latest Tax Year | Federal | Investment Credits | Virginia Electric and Power Company
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2038
Latest Tax Year | Federal | Federal production credits
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2038
Latest Tax Year | Federal | Federal Production And Other Credits | Virginia Electric and Power Company
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2038
Latest Tax Year | State
Deductible loss and credit carryforwards [Line Items]
Losses, Expiration Period	2038
Latest Tax Year | State | Dominion Energy Gas Holdings, LLC
Deductible loss and credit carryforwards [Line Items]
Losses, Expiration Period	2038
Latest Tax Year | State | Investment Credits | Virginia Electric and Power Company
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2024
Latest Tax Year | State | Investment and Other Credit
Deductible loss and credit carryforwards [Line Items]
Tax Credits, Expiration Period	2025

XML

Income Taxes (Unrecognized Tax Benefits) (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1		$ 38	$ 64	$ 103
Increases-prior period positions		10	1	9
Decreases-prior period positions			(9)	(44)
Increases-current period positions		10	5	6
Settlements with tax authorities		(6)	(23)	(8)
Expiration of statutes of limitations		(8)		(2)
Balance at December 31		44	38	64
Virginia Electric and Power Company
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1		4	13	12
Increases-prior period positions				4
Decreases-prior period positions			(1)	(3)
Settlements with tax authorities	$ (8)	(1)	(8)
Expiration of statutes of limitations		(1)
Balance at December 31		$ 2	4	13
Dominion Energy Gas Holdings, LLC
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1			7	29
Increases-prior period positions				1
Decreases-prior period positions				(19)
Settlements with tax authorities			$ (7)	(4)
Balance at December 31				$ 7

XML

Income Taxes (Earliest Tax Year) (Detail)	12 Months Ended
	Dec. 31, 2018
Pennsylvania
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2012	[1]
Connecticut
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2015
Virginia
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2015	[2]
West Virginia
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2015	[1]
New York
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2011	[1]
Utah
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2015

[1] Considered a major state for Dominion Energy Gas' operations.

[2] Considered a major state for Virginia Power's operations.

XML

Fair Value Measurements (Fair Value, Option, Quantitative Disclosures) (Detail) $ in Millions		12 Months Ended
		Dec. 31, 2018 USD ($) $ / MWh $ / DTH	Dec. 31, 2017 USD ($) $ / MWh $ / DTH	Dec. 31, 2016 $ / MWh $ / DTH
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		$ 294	$ 307
Fair Value of Derivative Liabilities		279	284
Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		93	166
Fair Value of Derivative Liabilities		103	66
Fair Value, Measurements, Recurring
Fair Value, Option, Quantitative Disclosures [Line Items]
Total Assets		5,156	5,379
Total liabilities		279	284
Fair Value, Measurements, Recurring | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Total Assets		2,297	2,466
Total liabilities		103	66
Fair Value, Measurements, Recurring | Commodity
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		250	258
Fair Value of Derivative Liabilities		135	197
Fair Value, Measurements, Recurring | Commodity | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		90	166
Fair Value of Derivative Liabilities		15	9
Fair Value, Measurements, Recurring | Level 3
Fair Value, Option, Quantitative Disclosures [Line Items]
Total Assets		70	157
Total liabilities		6	7
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Total Assets		66	152
Total liabilities		6	5
Fair Value, Measurements, Recurring | Level 3 | Commodity
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		70	157
Fair Value of Derivative Liabilities		6	7
Fair Value, Measurements, Recurring | Level 3 | Commodity | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		66	152
Fair Value of Derivative Liabilities		6	$ 5
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | FTRs [Member] | Commodity
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		15
Fair Value of Derivative Liabilities		6
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | FTRs [Member] | Commodity | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		15
Fair Value of Derivative Liabilities		$ 6
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | FTRs [Member] | Commodity | Liabilities | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh		(2)
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | FTRs [Member] | Commodity | Liabilities | Minimum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh		(2)
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | FTRs [Member] | Commodity | Liabilities | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh		6
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | FTRs [Member] | Commodity | Liabilities | Maximum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh			6
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Assets | FTRs [Member] | Commodity | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh		(2)
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Assets | FTRs [Member] | Commodity | Minimum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh		(2)
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Assets | FTRs [Member] | Commodity | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh		7
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Assets | FTRs [Member] | Commodity | Maximum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh			7
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Assets | FTRs [Member] | Commodity | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh	[1]	1
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Assets | FTRs [Member] | Commodity | Weighted Average | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh				1
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Natural Gas | Commodity
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets	[2]	$ 42
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Natural Gas | Commodity | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets	[2],[3]	$ 38
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Natural Gas | Assets | Commodity | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / DTH	[4]	(2)
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Natural Gas | Assets | Commodity | Minimum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / DTH		(2)
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Natural Gas | Assets | Commodity | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / DTH	[4]	8
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Natural Gas | Assets | Commodity | Maximum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / DTH			8
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Natural Gas | Assets | Commodity | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / DTH	[1],[4]	(1)
Fair Value, Measurements, Recurring | Discounted Cash Flow [Member] | Level 3 | Natural Gas | Assets | Commodity | Weighted Average | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / DTH				(1)
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Electricity | Physical Options [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		$ 11
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Electricity | Physical Options [Member] | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		$ 11
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Assets | Electricity | Physical Options [Member] | Market Price [Member] | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh		(34)
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Assets | Electricity | Physical Options [Member] | Market Price [Member] | Minimum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh		34
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Assets | Electricity | Physical Options [Member] | Market Price [Member] | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh		50
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Assets | Electricity | Physical Options [Member] | Market Price [Member] | Maximum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh			50
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Assets | Electricity | Physical Options [Member] | Market Price [Member] | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh	[1]	42
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Assets | Electricity | Physical Options [Member] | Market Price [Member] | Weighted Average | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / MWh				42
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Assets | Electricity | Physical Options [Member] | Price Volatility [Member] | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Price volatility (percentage)		(39.00%)
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Assets | Electricity | Physical Options [Member] | Price Volatility [Member] | Minimum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Price volatility (percentage)		39.00%
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Assets | Electricity | Physical Options [Member] | Price Volatility [Member] | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Price volatility (percentage)		60.00%
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Assets | Electricity | Physical Options [Member] | Price Volatility [Member] | Maximum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Price volatility (percentage)			60.00%
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Assets | Electricity | Physical Options [Member] | Price Volatility [Member] | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Price volatility (percentage)	[1]	49.00%
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Assets | Electricity | Physical Options [Member] | Price Volatility [Member] | Weighted Average | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Price volatility (percentage)				49.00%
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Physical Options [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		$ 2
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Physical Options [Member] | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		$ 2
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Assets | Physical Options [Member] | Market Price [Member] | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / DTH		1
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Assets | Physical Options [Member] | Market Price [Member] | Minimum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / DTH		1
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Assets | Physical Options [Member] | Market Price [Member] | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / DTH		8
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Assets | Physical Options [Member] | Market Price [Member] | Maximum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / DTH			8
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Assets | Physical Options [Member] | Market Price [Member] | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / DTH	[1]	3
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Assets | Physical Options [Member] | Market Price [Member] | Weighted Average | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Market Price | $ / DTH				3
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Assets | Physical Options [Member] | Price Volatility [Member] | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Price volatility (percentage)		18.00%
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Assets | Physical Options [Member] | Price Volatility [Member] | Minimum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Price volatility (percentage)		18.00%
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Assets | Physical Options [Member] | Price Volatility [Member] | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Price volatility (percentage)		73.00%
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Assets | Physical Options [Member] | Price Volatility [Member] | Maximum | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Price volatility (percentage)			73.00%
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Assets | Physical Options [Member] | Price Volatility [Member] | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Price volatility (percentage)	[1]	30.00%
Fair Value, Measurements, Recurring | Option Model [Member] | Level 3 | Natural Gas | Assets | Physical Options [Member] | Price Volatility [Member] | Weighted Average | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Price volatility (percentage)				30.00%

[1] Averages weighted by volume.

[2] Includes basis.

[3] Includes NGLs and oil.

[4] Represents market prices beyond defined terms for Levels 1 and 2.

XML

Fair Value Measurements (Narrative) (Detail) - USD ($)	3 Months Ended		12 Months Ended
	Dec. 31, 2018		Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016	Oct. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Facility Limit	$ 6,000,000,000	[1]	$ 6,000,000,000	[1]	$ 5,500,000,000
Asset impairment charges			403,000,000		15,000,000	$ 4,000,000
Revolving Credit Facility | Atlantic Coast Pipeline | Financial Guarantee [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Facility Limit							$ 3,400,000,000
Guarantee liability							$ 30,000,000
Virginia Electric and Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Facility Limit	6,000,000,000	[2]	6,000,000,000	[2]	5,500,000,000
Unrealized gains and losses included in earnings in Level 3 fair value category			0		0	0
Dominion Energy Gas Holdings, LLC
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Facility Limit	1,500,000,000	[3]	1,500,000,000	[3]	1,500,000,000
Asset impairment charges	219,000,000		346,000,000		16,000,000
Asset impairment charges, after tax	165,000,000
Property, plant and equipment estimated fair value	$ 190,000,000		190,000,000
Unrealized gains and losses included in earnings in Level 3 fair value category			$ 0		$ 0	$ 0

[1] This credit facility matures in March 2023 and can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

[2] The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Virginia Power was $1.5 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

[3] A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. The sub-limit for Dominion Energy Gas is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Dominion Energy Gas was $750 million. If Dominion Energy 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

XML

Fair Value Measurements (Assets and Liabilities that are Measured at Fair Value on a Recurring Basis) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		$ 294	$ 307
Derivative Liabilities		279	284
Virginia Electric and Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		93	166
Derivative Liabilities		103	66
Dominion Energy Gas Holdings, LLC
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		29	32	[1]
Derivative Liabilities		19	8
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		5,156	5,379
Total liabilities		279	284
Fair Value, Measurements, Recurring | Equity securities: | U.S.
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	3,277	3,493
Fair Value, Measurements, Recurring | Fixed Income | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		431	444
Fair Value, Measurements, Recurring | Fixed Income | Government Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		1,143	1,101
Fair Value, Measurements, Recurring | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		11	34
Fair Value, Measurements, Recurring | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		250	258
Derivative Liabilities		135	197
Fair Value, Measurements, Recurring | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		18	17
Derivative Liabilities		142	85
Fair Value, Measurements, Recurring | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		26	32
Derivative Liabilities		2	2
Fair Value, Measurements, Recurring | Virginia Electric and Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		2,297	2,466
Total liabilities		103	66
Fair Value, Measurements, Recurring | Virginia Electric and Power Company | Equity securities: | U.S.
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	3	1,566
Fair Value, Measurements, Recurring | Virginia Electric and Power Company | Fixed Income | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	1,476	224
Fair Value, Measurements, Recurring | Virginia Electric and Power Company | Fixed Income | Government Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	221	494
Fair Value, Measurements, Recurring | Virginia Electric and Power Company | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	507	16
Fair Value, Measurements, Recurring | Virginia Electric and Power Company | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		90	166
Derivative Liabilities		15	9
Fair Value, Measurements, Recurring | Virginia Electric and Power Company | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		88	57
Fair Value, Measurements, Recurring | Dominion Energy Gas Holdings, LLC
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		29	32
Total liabilities		19	8
Fair Value, Measurements, Recurring | Dominion Energy Gas Holdings, LLC | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		3
Derivative Liabilities			6
Fair Value, Measurements, Recurring | Dominion Energy Gas Holdings, LLC | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		17
Fair Value, Measurements, Recurring | Dominion Energy Gas Holdings, LLC | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		26	32
Derivative Liabilities		2	2
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		3,743	3,834
Fair Value, Measurements, Recurring | Level 1 | Equity securities: | U.S.
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	3,277	3,493
Fair Value, Measurements, Recurring | Level 1 | Fixed Income | Government Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		455	307
Fair Value, Measurements, Recurring | Level 1 | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		11	34
Fair Value, Measurements, Recurring | Level 1 | Virginia Electric and Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		1,640	1,750
Fair Value, Measurements, Recurring | Level 1 | Virginia Electric and Power Company | Equity securities: | U.S.
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]		1,566
Fair Value, Measurements, Recurring | Level 1 | Virginia Electric and Power Company | Fixed Income | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	1,476
Fair Value, Measurements, Recurring | Level 1 | Virginia Electric and Power Company | Fixed Income | Government Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]		168
Fair Value, Measurements, Recurring | Level 1 | Virginia Electric and Power Company | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	164	16
Fair Value, Measurements, Recurring | Level 1 | Dominion Energy Gas Holdings, LLC
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		0	0
Total liabilities		0	0
Fair Value, Measurements, Recurring | Level 1 | Dominion Energy Gas Holdings, LLC | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liabilities			0
Fair Value, Measurements, Recurring | Level 1 | Dominion Energy Gas Holdings, LLC | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		0
Fair Value, Measurements, Recurring | Level 1 | Dominion Energy Gas Holdings, LLC | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liabilities		0	0
Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		1,343	1,388
Total liabilities		273	277
Fair Value, Measurements, Recurring | Level 2 | Fixed Income | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		431	444
Fair Value, Measurements, Recurring | Level 2 | Fixed Income | Government Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		688	794
Fair Value, Measurements, Recurring | Level 2 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		180	101
Derivative Liabilities		129	190
Fair Value, Measurements, Recurring | Level 2 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		18	17
Derivative Liabilities		142	85
Fair Value, Measurements, Recurring | Level 2 | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		26	32
Derivative Liabilities		2	2
Fair Value, Measurements, Recurring | Level 2 | Virginia Electric and Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		591	564
Total liabilities		97	61
Fair Value, Measurements, Recurring | Level 2 | Virginia Electric and Power Company | Equity securities: | U.S.
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	3
Fair Value, Measurements, Recurring | Level 2 | Virginia Electric and Power Company | Fixed Income | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]		224
Fair Value, Measurements, Recurring | Level 2 | Virginia Electric and Power Company | Fixed Income | Government Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	221	326
Fair Value, Measurements, Recurring | Level 2 | Virginia Electric and Power Company | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	343
Fair Value, Measurements, Recurring | Level 2 | Virginia Electric and Power Company | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		24	14
Derivative Liabilities		9	4
Fair Value, Measurements, Recurring | Level 2 | Virginia Electric and Power Company | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		88	57
Fair Value, Measurements, Recurring | Level 2 | Dominion Energy Gas Holdings, LLC
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		29	32
Total liabilities		19	6
Fair Value, Measurements, Recurring | Level 2 | Dominion Energy Gas Holdings, LLC | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		3
Derivative Liabilities			4
Fair Value, Measurements, Recurring | Level 2 | Dominion Energy Gas Holdings, LLC | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		17
Fair Value, Measurements, Recurring | Level 2 | Dominion Energy Gas Holdings, LLC | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		26	32
Derivative Liabilities		2	2
Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		70	157
Total liabilities		6	7
Fair Value, Measurements, Recurring | Level 3 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		70	157
Derivative Liabilities		6	7
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		66	152
Total liabilities		6	5
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		66	152
Derivative Liabilities		6	5
Fair Value, Measurements, Recurring | Level 3 | Dominion Energy Gas Holdings, LLC
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		0	0
Total liabilities		0	2
Fair Value, Measurements, Recurring | Level 3 | Dominion Energy Gas Holdings, LLC | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liabilities			2
Fair Value, Measurements, Recurring | Level 3 | Dominion Energy Gas Holdings, LLC | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		0
Fair Value, Measurements, Recurring | Level 3 | Dominion Energy Gas Holdings, LLC | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liabilities		$ 0	$ 0

[1] Current derivative liabilities are presented in other current liabilities in Virginia Power's Consolidated Balance Sheets.

[2] Includes investments held in the nuclear decommissioning and rabbi trusts. Excludes $220 million and $88 million of assets at December 31, 2018 and 2017, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

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Fair Value Measurements (Assets and Liabilities that are Measured at Fair Value on a Recurring Basis) (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value using NAV	$ 220	$ 88
Virginia Electric and Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value using NAV	$ 160	$ 27

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Fair Value Measurements (Net Change in the Assets and Liabilities Measured at Fair Value on a Recurring Basis and Included in the Level 3 Fair Value Category) (Detail) - Commodity - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning balance	$ 150	$ 139	$ 95
Total realized and unrealized gains (losses):
Included in other comprehensive income (loss)	1	(2)
Included in regulatory assets/liabilities	(44)	42	(39)
Settlements	(27)	6	38
Purchases			87
Transfers out of Level 3	1	3	(7)
Ending balance	64	150	139
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date		2
Virginia Electric and Power Company
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning balance	147	143	93
Total realized and unrealized gains (losses):
Included in regulatory assets/liabilities	(45)	40	(37)
Settlements	(25)	7	35
Purchases			(87)
Ending balance	60	147	143
Dominion Energy Gas Holdings, LLC
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning balance	(2)	(2)	6
Total realized and unrealized gains (losses):
Included in other comprehensive income (loss)	1	(3)
Transfers out of Level 3	1	3	(8)
Ending balance		(2)	(2)
Operating Revenue
Total realized and unrealized gains (losses):
Included in earnings	(2)	3
Electric fuel and other energy-related purchases
Total realized and unrealized gains (losses):
Included in earnings	(15)	(42)	(35)
Electric fuel and other energy-related purchases | Virginia Electric and Power Company
Total realized and unrealized gains (losses):
Included in earnings	$ (17)	(43)	$ (35)
Purchased Gas
Total realized and unrealized gains (losses):
Included in earnings		$ 1

XML

Fair Value Measurements (Financial Instruments' Carrying Amounts and Fair Values) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	[1]	$ 29,952	$ 28,666
Credit facility borrowings		73
Junior subordinated notes	[2]	3,430	3,981
Remarketable subordinated notes	[2]	1,386	1,379
Carrying Amount | Virginia Electric and Power Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	[2]	11,671	11,346
Carrying Amount | Dominion Energy Gas Holdings, LLC
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	[3]	4,058	3,570
Estimate of Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	[1],[4]	31,045	31,233
Credit facility borrowings	[4]	73
Junior subordinated notes	[2],[4]	3,358	4,102
Remarketable subordinated notes	[2],[4]	1,340	1,446
Estimate of Fair Value | Virginia Electric and Power Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	[2],[4]	12,400	12,842
Estimate of Fair Value | Dominion Energy Gas Holdings, LLC
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	[3],[4]	$ 4,072	$ 3,719

[1] Carrying amount includes amounts which represent, the unamortized debt issuance costs, discount or premium, and foreign currency remeasurement adjustments. At December 31, 2018, and 2017, includes the valuation of certain fair value hedges associated with Dominion Energy's fixed rate debt of $(20) million and $(22) million, respectively.

[2] Carrying amount includes amounts which represent the unamortized debt issuance costs, discount or premium.

[3] Carrying amount includes amounts which represent the unamortized debt issuance costs, discount or premium, and foreign currency remeasurement adjustments.

[4] 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 issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

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Fair Value Measurements (Financial Instruments' Carrying Amounts and Fair Values) (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Valuation of certain fair value hedges associated with fixed rate debt	$ (20)	$ (22)

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Derivatives and Hedge Accounting Activities (Schedule of Offsetting Assets) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	[1]	$ 287	$ 303
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		83	99
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received		0	0
Net Amounts		204	204
Virginia Electric and Power Company
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets		67	155
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		6	4
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received		0	0
Net Amounts		61	151
Dominion Energy Gas Holdings, LLC
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets		29
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		2	2
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received		0	0
Net Amounts		27	30
Commodity | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	[1]	175	174
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		12	9
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received		0	0
Net Amounts		163	165
Commodity | Exchange
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	[1]	68	80
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		68	80
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received		0	0
Commodity | Virginia Electric and Power Company | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets		64	155
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		6	4
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received		0	0
Net Amounts		58	151
Commodity | Dominion Energy Gas Holdings, LLC | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets		3
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received		0	0
Net Amounts		3
Interest rate | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	[1]	18	17
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		1	8
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received		0	0
Net Amounts		17	9
Interest rate | Virginia Electric and Power Company | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets		3
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received		0	0
Net Amounts		3
Foreign currency | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	[1]	26	32
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		2	2
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received		0	0
Net Amounts		24	30
Foreign currency | Dominion Energy Gas Holdings, LLC | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets		26	32
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		2	2
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received		0	0
Net Amounts		$ 24	$ 30

[1] Excludes $7 million and $4 million of derivative assets at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.

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Derivatives and Hedge Accounting Activities (Schedule of Offsetting Assets) (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Offsetting Assets [Line Items]
Derivative assets, not subject to a master netting or similar arrangement	$ 7	$ 4
Virginia Electric and Power Company
Offsetting Assets [Line Items]
Derivative assets, not subject to a master netting or similar arrangement	$ 26	$ 11

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Derivatives and Hedge Accounting Activities (Schedule of Offsetting Liabilities) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Offsetting Liabilities [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet	[1]	$ 278	$ 283
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		83	99
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral		47	46
Net Amounts		148	138
Virginia Electric and Power Company
Offsetting Liabilities [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet		94	61
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		6	4
Net Amounts		88	57
Dominion Energy Gas Holdings, LLC
Offsetting Liabilities [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet		19	8
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		2	2
Net Amounts		17	6
Commodity | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet	[1]	19	76
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		12	9
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral			6
Net Amounts		7	61
Commodity | Exchange
Offsetting Liabilities [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet	[1]	115	120
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		68	80
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral		47	40
Commodity | Virginia Electric and Power Company | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet		6	4
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		6	4
Commodity | Dominion Energy Gas Holdings, LLC | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet			6
Net Amounts			6
Interest rate | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet	[1]	142	85
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		1	8
Net Amounts		141	77
Interest rate | Virginia Electric and Power Company | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet		88	57
Net Amounts		88	57
Interest rate | Dominion Energy Gas Holdings, LLC | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet		17
Net Amounts		17
Foreign currency | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet	[1]	2	2
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		2	2
Foreign currency | Dominion Energy Gas Holdings, LLC | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet		2	2
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments		$ 2	$ 2

[1] Excludes $1 million of derivative liabilities at December 31, 2018 and 2017, which are not subject to master netting or similar arrangements.

XML

Derivatives and Hedge Accounting Activities (Schedule of Offsetting Liabilities) (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Offsetting Liabilities [Line Items]
Derivative liabilities, not subject to a master netting or similar arrangement	$ 1	$ 1
Virginia Electric and Power Company
Offsetting Liabilities [Line Items]
Derivative liabilities, not subject to a master netting or similar arrangement	$ 9	$ 5

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Derivatives and Hedge Accounting Activities (Volume of Derivative Activity) (Detail)	12 Months Ended
	Dec. 31, 2018 USD ($) MWh Bcf gal
Fixed Price - Natural Gas - Non-current Derivative Contract
Derivative [Line Items]
Volume of derivative activity | Bcf	27	[1]
Fixed Price - Natural Gas - Non-current Derivative Contract | Virginia Electric and Power Company
Derivative [Line Items]
Volume of derivative activity | Bcf	8	[1]
Basis - Natural Gas - Non-current Derivative Contract [Member]
Derivative [Line Items]
Volume of derivative activity | Bcf	557
Basis - Natural Gas - Non-current Derivative Contract [Member] | Virginia Electric and Power Company
Derivative [Line Items]
Volume of derivative activity | Bcf	488
Fixed Price - Electricity - Non-current Derivative Contract [Member]
Derivative [Line Items]
Volume of electricity | MWh	1,537,200	[1]
Financial Transmission Rights - Electricity- Non-current Derivative Contract [Member]
Derivative [Line Items]
Volume of electricity | MWh	0
Liquids - Non-current Derivative Contract [Member]
Derivative [Line Items]
Volume of derivative activity | gal	0	[2]
Interest Rate - Non-current Derivative Contract
Derivative [Line Items]
Interest rate / Foreign currency (US Dollars, Euros)	$ 3,915,839,913	[3]
Interest Rate - Non-current Derivative Contract | Virginia Electric and Power Company
Derivative [Line Items]
Interest rate / Foreign currency (US Dollars, Euros)	1,200,000,000	[3]
Interest Rate - Non-current Derivative Contract | Dominion Energy Gas Holdings, LLC
Derivative [Line Items]
Interest rate / Foreign currency (US Dollars, Euros)	750,000,000
Foreign Exchange - Non- Current Derivative Contract
Derivative [Line Items]
Interest rate / Foreign currency (US Dollars, Euros)	280,000,000	[3],[4]
Foreign Exchange - Non- Current Derivative Contract | Dominion Energy Gas Holdings, LLC
Derivative [Line Items]
Interest rate / Foreign currency (US Dollars, Euros)	$ 280,000,000
Fixed Price - Natural Gas - Current Derivative Contract
Derivative [Line Items]
Volume of derivative activity | Bcf	56	[1]
Fixed Price - Natural Gas - Current Derivative Contract | Virginia Electric and Power Company
Derivative [Line Items]
Volume of derivative activity | Bcf	29	[1]
Basis - Natural Gas - Current Derivative Contract
Derivative [Line Items]
Volume of derivative activity | Bcf	214
Basis - Natural Gas - Current Derivative Contract | Virginia Electric and Power Company
Derivative [Line Items]
Volume of derivative activity | Bcf	136
Fixed Price - Electricity - Current Derivative Contract
Derivative [Line Items]
Volume of electricity | MWh	11,101,869	[1]
Fixed Price - Electricity - Current Derivative Contract | Virginia Electric and Power Company
Derivative [Line Items]
Volume of electricity | MWh	367,019	[1]
Financial Transmission Rights - Electricity- Current Derivative Contract
Derivative [Line Items]
Volume of electricity | MWh	45,351,415
Liquids - Current Derivative Contract
Derivative [Line Items]
Volume of derivative activity | gal	14,413,200	[2]
Liquids - Current Derivative Contract | Virginia Electric and Power Company
Derivative [Line Items]
Volume of electricity | MWh	45,351,415
Interest Rate - Current Derivative Contract
Derivative [Line Items]
Interest rate / Foreign currency (US Dollars, Euros)	$ 2,700,000,000	[3]
Interest Rate - Current Derivative Contract | Virginia Electric and Power Company
Derivative [Line Items]
Interest rate / Foreign currency (US Dollars, Euros)	700,000,000	[3]
Interest Rate - Current Derivative Contract | Dominion Energy Gas Holdings, LLC
Derivative [Line Items]
Interest rate / Foreign currency (US Dollars, Euros)	300,000,000
Foreign Exchange - Current Derivative Contract
Derivative [Line Items]
Interest rate / Foreign currency (US Dollars, Euros)	$ 0	[3],[4]
NGLs | Dominion Energy Gas Holdings, LLC
Derivative [Line Items]
Volume of derivative activity | gal	14,413,200

[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.

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Derivatives and Hedge Accounting Activities (Volume of Derivative Activity) (Parenthetical) (Detail) - Foreign currency	Dec. 31, 2018 EUR (€)
Derivative [Line Items]
Interest rate / Foreign currency (US Dollars, Euros)	€ 250,000,000
Dominion Energy Gas Holdings, LLC
Derivative [Line Items]
Interest rate / Foreign currency (US Dollars, Euros)	€ 250,000,000

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Derivatives and Hedge Accounting Activities (Selected Information Related to Gains (Losses) on Cash Flow Hedges Included in AOCI) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Derivative Instruments Gain Loss [Line Items]
AOCI After-Tax	$ (235)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	(2)
Commodity | Electricity
Derivative Instruments Gain Loss [Line Items]
AOCI After-Tax	27
Commodities, Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ 26
Maximum Term	24 months
Commodity | Other Energy Contract
Derivative Instruments Gain Loss [Line Items]
AOCI After-Tax	$ 2
Commodities, Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ 2
Maximum Term	3 months
Commodity | Natural Gas
Derivative Instruments Gain Loss [Line Items]
AOCI After-Tax	$ 0
Commodities, Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ 1
Maximum Term	36 months
Interest rate
Derivative Instruments Gain Loss [Line Items]
AOCI After-Tax	$ (276)
Interest rate, Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ (29)
Maximum Term	396 months
Foreign currency
Derivative Instruments Gain Loss [Line Items]
AOCI After-Tax	$ 12
Foreign currency, Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ (2)
Maximum Term	90 months
Dominion Energy Gas Holdings, LLC
Derivative Instruments Gain Loss [Line Items]
AOCI After-Tax	$ (25)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	(4)
Dominion Energy Gas Holdings, LLC | Interest rate
Derivative Instruments Gain Loss [Line Items]
AOCI After-Tax	(39)
Interest rate, Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ (4)
Maximum Term	312 months
Dominion Energy Gas Holdings, LLC | Foreign currency
Derivative Instruments Gain Loss [Line Items]
AOCI After-Tax	$ 12
Foreign currency, Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ (2)
Maximum Term	90 months
Dominion Energy Gas Holdings, LLC | NGLs
Derivative Instruments Gain Loss [Line Items]
AOCI After-Tax	$ 2
Commodities, Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ 2
Maximum Term	3 months
Virginia Electric and Power Company
Derivative Instruments Gain Loss [Line Items]
AOCI After-Tax	$ (13)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	(1)
Virginia Electric and Power Company | Interest rate
Derivative Instruments Gain Loss [Line Items]
AOCI After-Tax	(13)
Interest rate, Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ (1)
Maximum Term	384 months

XML

Derivatives and Hedge Accounting Activities (Fair Value of Derivatives) (Detail) - USD ($) $ in Millions		Dec. 31, 2018		Dec. 31, 2017
Derivatives Fair Value [Line Items]
Derivative Asset		$ 294		$ 307
Derivative Liabilities		279		284
Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Asset		93		166
Derivative Liabilities		103		66
Dominion Energy Gas Holdings, LLC
Derivatives Fair Value [Line Items]
Derivative Asset		29		32	[1]
Derivative Liabilities		19		8
Current Assets
Derivatives Fair Value [Line Items]
Derivative Asset	[2]	223		169
Current Assets | Commodity
Derivatives Fair Value [Line Items]
Derivative Asset		209		163
Current Assets | Interest rate
Derivatives Fair Value [Line Items]
Derivative Asset		14		6
Current Assets | Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Asset		63		75
Current Assets | Virginia Electric and Power Company | Commodity
Derivatives Fair Value [Line Items]
Derivative Asset		60		75
Current Assets | Virginia Electric and Power Company | Interest rate
Derivatives Fair Value [Line Items]
Derivative Asset		3
Current Assets | Dominion Energy Gas Holdings, LLC
Derivatives Fair Value [Line Items]
Derivative Asset	[3]	3
Current Assets | Dominion Energy Gas Holdings, LLC | Commodity
Derivatives Fair Value [Line Items]
Derivative Asset		3
Noncurrent Assets
Derivatives Fair Value [Line Items]
Derivative Asset	[4]	71		138
Noncurrent Assets | Commodity
Derivatives Fair Value [Line Items]
Derivative Asset		41		95
Noncurrent Assets | Interest rate
Derivatives Fair Value [Line Items]
Derivative Asset		4		11
Noncurrent Assets | Foreign currency
Derivatives Fair Value [Line Items]
Derivative Asset		26		32
Noncurrent Assets | Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Asset		30		91
Noncurrent Assets | Virginia Electric and Power Company | Commodity
Derivatives Fair Value [Line Items]
Derivative Asset		30		91
Noncurrent Assets | Dominion Energy Gas Holdings, LLC
Derivatives Fair Value [Line Items]
Derivative Asset		26	[1]	32
Noncurrent Assets | Dominion Energy Gas Holdings, LLC | Foreign currency
Derivatives Fair Value [Line Items]
Derivative Asset		26		32
Current Liabilities
Derivatives Fair Value [Line Items]
Derivative Liabilities	[5]	157		250
Current Liabilities | Commodity
Derivatives Fair Value [Line Items]
Derivative Liabilities		129		195
Current Liabilities | Interest rate
Derivatives Fair Value [Line Items]
Derivative Liabilities		26		53
Current Liabilities | Foreign currency
Derivatives Fair Value [Line Items]
Derivative Liabilities		2		2
Current Liabilities | Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Liabilities		25		53
Current Liabilities | Virginia Electric and Power Company | Commodity
Derivatives Fair Value [Line Items]
Derivative Liabilities		15		9
Current Liabilities | Virginia Electric and Power Company | Interest rate
Derivatives Fair Value [Line Items]
Derivative Liabilities		10		44
Current Liabilities | Dominion Energy Gas Holdings, LLC
Derivatives Fair Value [Line Items]
Derivative Liabilities	[6]	11		8
Current Liabilities | Dominion Energy Gas Holdings, LLC | Commodity
Derivatives Fair Value [Line Items]
Derivative Liabilities				6
Current Liabilities | Dominion Energy Gas Holdings, LLC | Interest rate
Derivatives Fair Value [Line Items]
Derivative Liabilities		9
Current Liabilities | Dominion Energy Gas Holdings, LLC | Foreign currency
Derivatives Fair Value [Line Items]
Derivative Liabilities		2		2
Noncurrent Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities	[7]	122		34
Noncurrent Liabilities [Member] | Commodity
Derivatives Fair Value [Line Items]
Derivative Liabilities		6		2
Noncurrent Liabilities [Member] | Interest rate
Derivatives Fair Value [Line Items]
Derivative Liabilities		116		32
Noncurrent Liabilities [Member] | Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Liabilities		78		13
Noncurrent Liabilities [Member] | Virginia Electric and Power Company | Interest rate
Derivatives Fair Value [Line Items]
Derivative Liabilities		78		13
Noncurrent Liabilities [Member] | Dominion Energy Gas Holdings, LLC
Derivatives Fair Value [Line Items]
Derivative Liabilities	[8]	8
Noncurrent Liabilities [Member] | Dominion Energy Gas Holdings, LLC | Interest rate
Derivatives Fair Value [Line Items]
Derivative Liabilities		8
Fair Value - Derivatives under Hedge Accounting [Member]
Derivatives Fair Value [Line Items]
Derivative Asset		105		54
Derivative Liabilities		166		191
Fair Value - Derivatives under Hedge Accounting [Member] | Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Asset		3
Derivative Liabilities		88		57
Fair Value - Derivatives under Hedge Accounting [Member] | Dominion Energy Gas Holdings, LLC
Derivatives Fair Value [Line Items]
Derivative Asset		29		32	[1]
Derivative Liabilities		19		8
Fair Value - Derivatives under Hedge Accounting [Member] | Current Assets
Derivatives Fair Value [Line Items]
Derivative Asset	[2]	69		11
Fair Value - Derivatives under Hedge Accounting [Member] | Current Assets | Commodity
Derivatives Fair Value [Line Items]
Derivative Asset		55		5
Fair Value - Derivatives under Hedge Accounting [Member] | Current Assets | Interest rate
Derivatives Fair Value [Line Items]
Derivative Asset		14		6
Fair Value - Derivatives under Hedge Accounting [Member] | Current Assets | Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Asset		3
Fair Value - Derivatives under Hedge Accounting [Member] | Current Assets | Virginia Electric and Power Company | Interest rate
Derivatives Fair Value [Line Items]
Derivative Asset		3
Fair Value - Derivatives under Hedge Accounting [Member] | Current Assets | Dominion Energy Gas Holdings, LLC
Derivatives Fair Value [Line Items]
Derivative Asset	[3]	3
Fair Value - Derivatives under Hedge Accounting [Member] | Current Assets | Dominion Energy Gas Holdings, LLC | Commodity
Derivatives Fair Value [Line Items]
Derivative Asset		3
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Assets
Derivatives Fair Value [Line Items]
Derivative Asset	[4]	36		43
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Assets | Commodity
Derivatives Fair Value [Line Items]
Derivative Asset		6
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Assets | Interest rate
Derivatives Fair Value [Line Items]
Derivative Asset		4		11
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Assets | Foreign currency
Derivatives Fair Value [Line Items]
Derivative Asset		26		32
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Assets | Dominion Energy Gas Holdings, LLC
Derivatives Fair Value [Line Items]
Derivative Asset		26	[1]	32
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Assets | Dominion Energy Gas Holdings, LLC | Foreign currency
Derivatives Fair Value [Line Items]
Derivative Asset		26		32
Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities
Derivatives Fair Value [Line Items]
Derivative Liabilities	[5]	45		158
Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities | Commodity
Derivatives Fair Value [Line Items]
Derivative Liabilities		17		103
Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities | Interest rate
Derivatives Fair Value [Line Items]
Derivative Liabilities		26		53
Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities | Foreign currency
Derivatives Fair Value [Line Items]
Derivative Liabilities		2		2
Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities | Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Liabilities		10		44
Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities | Virginia Electric and Power Company | Interest rate
Derivatives Fair Value [Line Items]
Derivative Liabilities		10		44
Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities | Dominion Energy Gas Holdings, LLC
Derivatives Fair Value [Line Items]
Derivative Liabilities	[6]	11		8
Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities | Dominion Energy Gas Holdings, LLC | Commodity
Derivatives Fair Value [Line Items]
Derivative Liabilities				6
Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities | Dominion Energy Gas Holdings, LLC | Interest rate
Derivatives Fair Value [Line Items]
Derivative Liabilities		9
Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities | Dominion Energy Gas Holdings, LLC | Foreign currency
Derivatives Fair Value [Line Items]
Derivative Liabilities		2		2
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities	[7]	121		33
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Liabilities [Member] | Commodity
Derivatives Fair Value [Line Items]
Derivative Liabilities		5		1
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Liabilities [Member] | Interest rate
Derivatives Fair Value [Line Items]
Derivative Liabilities		116		32
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Liabilities [Member] | Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Liabilities		78		13
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Liabilities [Member] | Virginia Electric and Power Company | Interest rate
Derivatives Fair Value [Line Items]
Derivative Liabilities		78		13
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Liabilities [Member] | Dominion Energy Gas Holdings, LLC
Derivatives Fair Value [Line Items]
Derivative Liabilities	[8]	8
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Liabilities [Member] | Dominion Energy Gas Holdings, LLC | Interest rate
Derivatives Fair Value [Line Items]
Derivative Liabilities		8
Derivatives Not Designated as Hedging Instruments
Derivatives Fair Value [Line Items]
Derivative Asset		189		253
Derivative Liabilities		113		93
Derivatives Not Designated as Hedging Instruments | Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Asset		90		166
Derivative Liabilities		15		9
Derivatives Not Designated as Hedging Instruments | Current Assets
Derivatives Fair Value [Line Items]
Derivative Asset	[2]	154		158
Derivatives Not Designated as Hedging Instruments | Current Assets | Commodity
Derivatives Fair Value [Line Items]
Derivative Asset		154		158
Derivatives Not Designated as Hedging Instruments | Current Assets | Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Asset		60		75
Derivatives Not Designated as Hedging Instruments | Current Assets | Virginia Electric and Power Company | Commodity
Derivatives Fair Value [Line Items]
Derivative Asset		60		75
Derivatives Not Designated as Hedging Instruments | Noncurrent Assets
Derivatives Fair Value [Line Items]
Derivative Asset	[4]	35		95
Derivatives Not Designated as Hedging Instruments | Noncurrent Assets | Commodity
Derivatives Fair Value [Line Items]
Derivative Asset		35		95
Derivatives Not Designated as Hedging Instruments | Noncurrent Assets | Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Asset		30		91
Derivatives Not Designated as Hedging Instruments | Noncurrent Assets | Virginia Electric and Power Company | Commodity
Derivatives Fair Value [Line Items]
Derivative Asset		30		91
Derivatives Not Designated as Hedging Instruments | Current Liabilities
Derivatives Fair Value [Line Items]
Derivative Liabilities	[5]	112		92
Derivatives Not Designated as Hedging Instruments | Current Liabilities | Commodity
Derivatives Fair Value [Line Items]
Derivative Liabilities		112		92
Derivatives Not Designated as Hedging Instruments | Current Liabilities | Virginia Electric and Power Company
Derivatives Fair Value [Line Items]
Derivative Liabilities		15		9
Derivatives Not Designated as Hedging Instruments | Current Liabilities | Virginia Electric and Power Company | Commodity
Derivatives Fair Value [Line Items]
Derivative Liabilities		15		9
Derivatives Not Designated as Hedging Instruments | Noncurrent Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities	[7]	1		1
Derivatives Not Designated as Hedging Instruments | Noncurrent Liabilities [Member] | Commodity
Derivatives Fair Value [Line Items]
Derivative Liabilities		$ 1		$ 1

[1] Current derivative liabilities are presented in other current liabilities in Virginia Power's Consolidated Balance Sheets.

[2] Current derivative assets are presented in other current assets in Dominion Energy's Consolidated Balance Sheets.

[3] Current derivative assets are presented in other current assets in Virginia Power's Consolidated Balance Sheets.

[4] Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion Energy's Consolidated Balance Sheets.

[5] Current derivative liabilities are presented in other current liabilities in Dominion Energy's Consolidated Balance Sheets.

[6] Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power's Consolidated Balance Sheets.

[7] Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Energy's Consolidated Balance Sheets.

[8] Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Energy Gas' Consolidated Balance Sheets.

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Derivatives and Hedge Accounting Activities (Gains and Losses on Derivatives in Cash Flow Hedging Relationships) (Detail) - Cash Flow Hedges - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[1]	$ 40		$ 11	$ 92
Amount of Gain (Loss) Reclassified From AOCI to Income		(137)		47	259
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[2]	39		(58)	(26)
Virginia Electric and Power Company
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[3]	2		(8)	(3)
Amount of Gain (Loss) Reclassified From AOCI to Income		(1)		(1)	(1)
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[4]	39		(58)	(26)
Dominion Energy Gas Holdings, LLC
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)		(23)		8	(26)
Amount of Gain (Loss) Reclassified From AOCI to Income		(27)		7	(15)
Commodity
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[1]	64		1	164
Amount of Gain (Loss) Reclassified From AOCI to Income		(76)		79	307
Commodity | Dominion Energy Gas Holdings, LLC
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)		1		(10)	(12)
Amount of Gain (Loss) Reclassified From AOCI to Income		(8)		(8)	4
Commodity | Operating Revenue
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Reclassified From AOCI to Income		(90)		81	330
Commodity | Operating Revenue | Dominion Energy Gas Holdings, LLC
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Reclassified From AOCI to Income		(8)		(8)	4
Commodity | Electric fuel and other energy-related purchases
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Reclassified From AOCI to Income		14			(10)
Commodity | Purchased Gas
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Reclassified From AOCI to Income				(2)	(13)
Interest rate
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[1],[5]	(18)	[6]	(8)	(66)
Amount of Gain (Loss) Reclassified From AOCI to Income	[5]	(48)	[6]	(52)	(31)
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[2],[5]	39	[6]	(58)	(26)
Interest rate | Virginia Electric and Power Company
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[3],[7]	2		(8)	(3)
Amount of Gain (Loss) Reclassified From AOCI to Income	[7]	(1)		(1)	(1)
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[4],[7]	39		(58)	(26)
Interest rate | Dominion Energy Gas Holdings, LLC
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)		(18)			(8)
Amount of Gain (Loss) Reclassified From AOCI to Income		(6)		(5)	(2)
Foreign currency
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[1],[8]	(6)		18	(6)
Amount of Gain (Loss) Reclassified From AOCI to Income	[8]	(13)		20	(17)
Foreign currency | Dominion Energy Gas Holdings, LLC
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)		(6)		18	(6)
Amount of Gain (Loss) Reclassified From AOCI to Income		$ (13)		$ 20	$ (17)

[1] Amounts deferred into AOCI have no associated effect in Dominion Energy'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 Energy's Consolidated Statements of Income.

[3] Amounts deferred into AOCI have no associated effect in Virginia Power's Consolidated Statements of Income.

[4] 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.

[5] Amounts recorded in Dominion Energy's Consolidated Statements of Income are classified in interest and related charges.

[6] See Note 9 for amounts attributable to related parties.

[7] Amounts recorded in Virginia Power's Consolidated Statements of Income are classified in interest and related charges.

[8] Amounts recorded in Dominion Energy's Consolidated Statements of Income are classified in other income.

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Derivatives and Hedge Accounting Activities (Schedule of Derivatives not Designated as Hedging Instruments) (Detail) - Derivatives Not Designated as Hedging Instruments - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]	$ (26)	$ (45)	$ (63)
Virginia Electric and Power Company
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[2]	2	(57)	(70)
Dominion Energy Gas Holdings, LLC
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives		(11)		1
Commodity | Operating Revenue
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]	(28)	18	2
Commodity | Operating Revenue | Virginia Electric and Power Company
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[2],[3]	2	(57)	(70)
Commodity | Operating Revenue | Dominion Energy Gas Holdings, LLC
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives		(11)		1
Commodity | Purchased Gas
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]	11	(3)	4
Commodity | Electric fuel and other energy-related purchases
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]	$ (9)	(59)	(70)
Commodity | Other operations and maintenance
Derivative Instruments Gain Loss [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]		$ (1)	$ 1

[1] Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy's Consolidated Statements of Income.

[2] 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.

[3] 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.

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Earnings Per Share (Calculation of Basic and Diluted EPS) (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Abstract]
Net Income Attributable to Dominion Energy		$ 641	$ 854	$ 449	$ 503	$ 1,312	$ 665	$ 390	$ 632	$ 2,447	$ 2,999	$ 2,123
Average shares of common stock outstanding - Basic										654.2	636.0	616.4
Net effect of dilutive securities	[1]									0.7		0.7
Average shares of common stock outstanding - Diluted										654.9	636.0	617.1
Earnings Per Common Share - Basic		$ 0.97	$ 1.31	$ 0.69	$ 0.77	$ 2.04	$ 1.03	$ 0.62	$ 1.01	$ 3.74	$ 4.72	$ 3.44
Earnings Per Common Share - Diluted		$ 0.97	$ 1.30	$ 0.69	$ 0.77	$ 2.04	$ 1.03	$ 0.62	$ 1.01	$ 3.74	$ 4.72	$ 3.44

[1] Dilutive securities for 2018 consist primarily of forward sale agreements, effective April 2018 to December 2018. Dilutive securities for 2016 consist primarily of the 2013 Equity Units. See Notes 17 and 19 for more information.

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Investments (Narrative) (Detail)		1 Months Ended					3 Months Ended		12 Months Ended
		Sep. 30, 2018 USD ($)	Dec. 31, 2016 USD ($)	Oct. 31, 2016 USD ($)	May 31, 2016 USD ($)	Sep. 30, 2014 Member mi	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Mar. 31, 2019 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity in earnings on investments										$ 197,000,000	$ 14,000,000	$ 111,000,000
Distributions received from investment										209,000,000	419,000,000	104,000,000
Carrying amount of investment that exceeded share of underlying equity							$ 161,000,000	$ 249,000,000		161,000,000	249,000,000
Equity method investment goodwill							176,000,000	73,000,000		176,000,000	73,000,000
Equity in earnings on investments										197,000,000	(18,000,000)	111,000,000
Additional membership percentage interest purchased				3.00%
Payment for purchase of equity interest				$ 14,000,000
Other receivables	[1]						331,000,000	126,000,000		331,000,000	126,000,000
Contributions to equity method affiliates										428,000,000	370,000,000	198,000,000
Impairment charge										403,000,000	15,000,000	4,000,000
Liabilities, other deferred credits and other liabilities							17,075,000,000	16,631,000,000		17,075,000,000	16,631,000,000
Finite Lived Equity Method Investment Basis Difference [Member]
Schedule of Equity Method Investments [Line Items]
Carrying amount of investment that exceeded share of underlying equity							146,000,000	15,000,000		146,000,000	15,000,000
Dominion Energy Gas Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Equity in earnings on investments										24,000,000	21,000,000	21,000,000
Other receivables	[2]						17,000,000	15,000,000		17,000,000	15,000,000
Impairment charge							219,000,000			346,000,000	16,000,000
Liabilities, other deferred credits and other liabilities							2,944,000,000	2,866,000,000		2,944,000,000	2,866,000,000
Dominion Energy Gas Holdings, LLC | Partnership Interest
Schedule of Equity Method Investments [Line Items]
Distributions received from investment										28,000,000	24,000,000	22,000,000
Carrying amount of investment that exceeded share of underlying equity							8,000,000	8,000,000		8,000,000	8,000,000
Equity in earnings on investments										24,000,000	21,000,000	21,000,000
Trading Securities
Schedule of Equity Method Investments [Line Items]
Rabbi trust securities							111,000,000	112,000,000		111,000,000	112,000,000
Other Income [Member] | Dominion Energy Gas Holdings, LLC | Partnership Interest
Schedule of Equity Method Investments [Line Items]
Percentage of non-controlling partnership interest sold					0.65%
Sales price of non-controlling partnership interest					$ 7,000,000
Amount of gain from sale					5,000,000
Amount of after tax gain from sale					$ 3,000,000
Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Distributions received from investment										36,000,000	270,000,000
Contributions to equity method affiliates										414,000,000	310,000,000	184,000,000
Atlantic Coast Pipeline | Scenario, Forecast
Schedule of Equity Method Investments [Line Items]
Project cost estimates increase									$ 250,000,000
Atlantic Coast Pipeline | DETI
Schedule of Equity Method Investments [Line Items]
Revenue										203,000,000	129,000,000	$ 95,000,000
Other receivables							13,000,000	12,000,000		$ 13,000,000	12,000,000
Atlantic Coast Pipeline | Minimum | Scenario, Forecast
Schedule of Equity Method Investments [Line Items]
Project cost estimates									7,250,000,000
Atlantic Coast Pipeline | Maximum | Scenario, Forecast
Schedule of Equity Method Investments [Line Items]
Project cost estimates									$ 7,750,000,000
Atlantic Coast Pipeline | Previous Minimum
Schedule of Equity Method Investments [Line Items]
Project cost estimates							6,000,000,000
Atlantic Coast Pipeline | Current Minimum
Schedule of Equity Method Investments [Line Items]
Project cost estimates							7,000,000,000
Atlantic Coast Pipeline | Previous Maximum
Schedule of Equity Method Investments [Line Items]
Project cost estimates							6,500,000,000
Atlantic Coast Pipeline | Current Maximum
Schedule of Equity Method Investments [Line Items]
Project cost estimates							$ 7,500,000,000
Atlantic Coast Pipeline | Pipelines | Jointly Owned Natural Gas Pipeline | Distribution
Schedule of Equity Method Investments [Line Items]
Ownership interest (percentage)							48.00%			48.00%
Length of natural gas pipeline (in miles) | mi						600
Number of members | Member						3
Duration of contract						20 years
Atlantic Coast Pipeline | Pipelines | Jointly Owned Natural Gas Pipeline | Distribution | Duke Energy
Schedule of Equity Method Investments [Line Items]
Ownership interest (percentage)							47.00%			47.00%
Atlantic Coast Pipeline | Pipelines | Jointly Owned Natural Gas Pipeline | Distribution | Southern Company Gas [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest (percentage)							5.00%			5.00%
Blue Racer
Schedule of Equity Method Investments [Line Items]
Amount of gain from sale							$ 546,000,000
Amount of after tax gain from sale							$ 390,000,000
Ownership interest percentage of limited partner interests							50.00%
Up-front cash consideration							$ 1,050,000,000
Additional deferred consideration, subject to increase for interest cost effective payable upon purchaser's availability of cash							150,000,000
Blue Racer | Scenario, Forecast
Schedule of Equity Method Investments [Line Items]
Aggregate amount of contingent consideration, maximum													$ 300,000,000
Blue Racer | Oil and Gas Properties
Schedule of Equity Method Investments [Line Items]
Amount paid to repurchase portion of Western System from Blue Racer			$ 10,000,000
NedPower Mount Storm LLC
Schedule of Equity Method Investments [Line Items]
Liabilities, other deferred credits and other liabilities							1,000,000	17,000,000		$ 1,000,000	$ 17,000,000
NedPower Mount Storm LLC | Property, Plant and Equipment [Member]
Schedule of Equity Method Investments [Line Items]
Impairment charge								126,000,000
Impairment charge, after tax								$ 76,000,000
Fowler I Holdings LLC
Schedule of Equity Method Investments [Line Items]
Impairment charge							32,000,000
Impairment charge, after tax							20,000,000
Fair value of investment							$ 81,000,000			$ 81,000,000
Catalyst Old River Hydroelectric Limited Partnership
Schedule of Equity Method Investments [Line Items]
Ownership interest percentage of limited partner interests		25.00%
Limited partnership interest sale transaction, proceeds received		$ 91,000,000
Catalyst Old River Hydroelectric Limited Partnership | Other Income [Member]
Schedule of Equity Method Investments [Line Items]
Amount of gain from sale		87,000,000
Amount of after tax gain from sale		$ 63,000,000

[1] See Note 9 for amounts attributable to related parties.

[2] See Note 24 for amounts attributable to related parties.

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Investments (Equity and Debt Securities and Cash Equivalents and Cost Method Investments in Decommissioning Trust Funds) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017
Investment Holdings [Line Items]
Amortized Cost, Total		$ 3,348		$ 3,200
Total Unrealized Gains		1,662		1,899
Total Unrealized Losses	[1]	(72)		(6)
Fair Value, Total		4,938		5,093
Fixed income securities Fair Value		1,604
Equity securities Total Unrealized Losses		(245)
Fixed Income
Investment Holdings [Line Items]
Cash equivalents and other Amortized Cost		4		34
Cash equivalents and other Fair Value		4		34
Common/collective trust funds | Fixed Income
Investment Holdings [Line Items]
Fixed income securities Amortized Cost, Total	[2]	76		60
Fixed income securities Fair Value	[2]	76		60
Cost Method Investments [Member]
Investment Holdings [Line Items]
Amortized Cost, Total				68
Fair Value, Total				68
Equity securities: | U.S.
Investment Holdings [Line Items]
Equity securities Amortized Cost,	[3]	1,741		1,569
Equity securities Total Unrealized Gains	[3]	1,640		1,857
Equity securities Total Unrealized Losses	[3]	(51)
Equity securities Fair Value	[3]	3,330		3,426
Corporate debt instruments | Fixed Income
Investment Holdings [Line Items]
Fixed income securities Amortized Cost, Total	[2]	435		430
Fixed income securities Total Unrealized Gains	[2]	5		15
Fixed income securities Total Unrealized Losses	[2]	(9)		(1)
Fixed income securities Fair Value	[2]	431		444
Government Securities | Fixed Income
Investment Holdings [Line Items]
Fixed income securities Amortized Cost, Total	[2]	1,092		1,039
Fixed income securities Total Unrealized Gains	[2]	17		27
Fixed income securities Total Unrealized Losses	[2]	(12)		(5)
Fixed income securities Fair Value	[2]	1,097		1,061
Virginia Electric and Power Company
Investment Holdings [Line Items]
Amortized Cost, Total		1,643		1,549
Total Unrealized Gains		760		852
Total Unrealized Losses	[4]	(34)
Fair Value, Total		2,369		2,399
Fixed income securities Fair Value		778
Equity securities Total Unrealized Losses		(105)
Virginia Electric and Power Company | Common/collective trust funds | Fixed Income
Investment Holdings [Line Items]
Fixed income securities Amortized Cost, Total	[2]	51		27
Fixed income securities Fair Value	[2]	51		27
Virginia Electric and Power Company | Cash Equivalents and Other [Member]
Investment Holdings [Line Items]
Cash equivalents and other Amortized Cost	[5]	6		22
Cash equivalents and other Fair Value		6		22
Virginia Electric and Power Company | Cost Method Investments [Member]
Investment Holdings [Line Items]
Amortized Cost, Total				68
Fair Value, Total				68
Virginia Electric and Power Company | Equity securities: | U.S.
Investment Holdings [Line Items]
Equity securities Amortized Cost,		858	[3]	734	[2]
Equity securities Total Unrealized Gains		751	[3]	831	[2]
Equity securities Total Unrealized Losses	[3]	(24)
Equity securities Fair Value		1,585	[3]	1,565	[2]
Virginia Electric and Power Company | Corporate debt instruments | Fixed Income
Investment Holdings [Line Items]
Fixed income securities Amortized Cost, Total	[2]	224		216
Fixed income securities Total Unrealized Gains	[2]	2		8
Fixed income securities Fair Value	[2]	221		224
Virginia Electric and Power Company | Government Securities | Fixed Income
Investment Holdings [Line Items]
Fixed income securities Amortized Cost, Total	[2]	504		482
Fixed income securities Total Unrealized Gains	[2]	7		13
Fixed income securities Fair Value	[2]	$ 506		$ 493

[1] The fair value of securities in an unrealized loss position was $833 million and $565 million at December 31, 2018 and 2017, respectively.

[2] Unrealized gains and losses on equity securities (for 2017) and fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

[3] Effective January 2018, unrealized gains and losses on equity securities, including those previously classified as cost method investments, are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

[4] The fair value of securities in an unrealized loss position was $404 million and $234 million at December 31, 2018 and 2017, respectively.

[5] Includes pending sales of securities of $6 million at both December 31, 2018 and 2017.

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Investments (Equity and Debt Securities and Cash Equivalents and Cost Method Investments in Decommissioning Trust Funds) (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Investment Holdings [Line Items]
Net assets related to pending sales and purchases of securities		$ 5
Fair value of securities in an unrealized loss position	$ 833	565
Virginia Electric and Power Company
Investment Holdings [Line Items]
Net assets related to pending sales and purchases of securities	6	6
Fair value of securities in an unrealized loss position	$ 404	$ 234

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Investments (Portion of Unrealized Gains and Losses Relates to Equity Securities) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Investment Holdings [Line Items]
Net losses recognized during the period	$ (245)
Less: Net gains recognized during the period on securities sold during the period	(58)
Unrealized losses recognized during the period on securities still held at the end of the year	(303)	[1]
Virginia Electric and Power Company
Investment Holdings [Line Items]
Net losses recognized during the period	(105)
Less: Net gains recognized during the period on securities sold during the period	(32)
Unrealized losses recognized during the period on securities still held at the end of the year	$ (137)	[1]

[1] Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

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Investments (Fair Value of our Marketable Debt Securities by Contractual Maturity) (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Schedule of Held-to-maturity Securities [Line Items]
Due in one year or less	$ 167
Due after one year through five years	389
Due after five years through ten years	376
Due after ten years	672
Total	1,604
Virginia Electric and Power Company
Schedule of Held-to-maturity Securities [Line Items]
Due in one year or less	54
Due after one year through five years	156
Due after five years through ten years	210
Due after ten years	358
Total	$ 778

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Investments (Selected Information Regarding Marketable Equity and Debt Securities) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Proceeds from sales		$ 1,804	$ 1,831	$ 1,422
Realized gains	[1]	140	166	128
Realized losses	[1]	91	71	55
Virginia Electric and Power Company
Schedule of Available-for-sale Securities [Line Items]
Proceeds from sales		887	849	733
Realized gains	[1]	60	75	63
Realized losses	[1]	$ 27	$ 30	$ 27

[1] Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.

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Investments (Recorded Other-Than-Temporary Impairment Losses on Investments) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Total other-than-temporary impairment losses	[1]	$ 30	$ 44	$ 51
Losses recorded to the nuclear decommissioning trust regulatory liability			(16)	(16)
Losses recognized in other comprehensive income (before taxes)		(30)	(5)	(12)
Net impairment losses recognized in earnings			23	23
Virginia Electric and Power Company
Schedule of Available-for-sale Securities [Line Items]
Total other-than-temporary impairment losses	[2]	15	20	26
Losses recorded to the nuclear decommissioning trust regulatory liability			(16)	(16)
Losses recognized in other comprehensive income (before taxes)		$ (15)	(2)	(7)
Net impairment losses recognized in earnings			$ 2	$ 3

[1] Amounts include other-than-temporary impairment losses for debt securities of $5 million and $13 million at December 31, 2017 and 2016, respectively.

[2] Amounts include other-than-temporary impairment losses for debt securities of $2 million and $8 million at December 31, 2017 and 2016 , respectively.

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Investments (Recorded Other-Than-Temporary Impairment Losses on Investments) (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Other-than-temporary impairment losses for debt securities	$ 5	$ 13
Virginia Electric and Power Company
Schedule of Available-for-sale Securities [Line Items]
Other-than-temporary impairment losses for debt securities	$ 2	$ 8

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Investments (Investments Under Equity Method of Accounting) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Investment Balance		$ 1,278	$ 1,544
Iroquois
Schedule of Equity Method Investments [Line Items]
Ownership%	[1]	50.00%
Investment Balance		$ 302	311
Description		Gas transmission system
Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Ownership%		48.00%
Investment Balance		$ 820	382
Description		Gas transmission system
Blue Racer
Schedule of Equity Method Investments [Line Items]
Ownership%		50.00%
Investment Balance			691
Description		Midstream gas and related services
Fowler I Holdings LLC
Schedule of Equity Method Investments [Line Items]
Ownership%		50.00%
Investment Balance		$ 82	81
Description		Wind-powered merchant generation facility
Other Investment
Schedule of Equity Method Investments [Line Items]
Investment Balance	[2]	$ 74	79
Dominion Energy Gas Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Investment Balance		$ 91	95
Dominion Energy Gas Holdings, LLC | Iroquois
Schedule of Equity Method Investments [Line Items]
Ownership%		24.07%
Investment Balance		$ 91	$ 95
Description		Gas transmission system

[1] Comprised of Dominion Energy Midstream's interest of 25.93% and Dominion Energy Gas' interest of 24.07%. See Note 15 for more information.

[2] Liability of less than $1 million and $17 million associated with NedPower recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets as of December 31, 2018 and 2017, respectively. See additional discussion of NedPower below.

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Investments (Investments Under Equity Method of Accounting) (Parenthetical) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Liabilities, other deferred credits and other liabilities		$ 17,075	$ 16,631
Iroquois
Schedule of Equity Method Investments [Line Items]
Ownership%	[1]	50.00%
NedPower Mount Storm LLC
Schedule of Equity Method Investments [Line Items]
Liabilities, other deferred credits and other liabilities		$ 1	17
Dominion Energy Midstream Partners, LP | Iroquois
Schedule of Equity Method Investments [Line Items]
Ownership%		25.93%
Dominion Energy Gas Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Liabilities, other deferred credits and other liabilities		$ 2,944	$ 2,866
Dominion Energy Gas Holdings, LLC | Iroquois
Schedule of Equity Method Investments [Line Items]
Ownership%		24.07%

[1] Comprised of Dominion Energy Midstream's interest of 25.93% and Dominion Energy Gas' interest of 24.07%. See Note 15 for more information.

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Property, Plant and Equipment (Property, Plant and Equipment) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Utility:
Generation	$ 19,250	$ 17,602
Transmission	16,669	15,335
Distribution	18,549	17,408
Storage	2,905	2,887
Nuclear fuel	1,626	1,599
Gas gathering and processing	307	219
Oil and gas	1,763	1,720
General and other	1,476	1,514
Plant under construction	2,385	7,765
Total utility	64,930	66,049
Nonutility:
Merchant generation-nuclear	1,550	1,452
Merchant generation-other	3,802	4,992
Nuclear fuel	1,025	968
Gas gathering and processing	185	630
LNG facility	3,977
Other-including plant under construction	1,109	732
Total nonutility	11,648	8,774
Total property, plant and equipment	76,578	74,823
Virginia Electric and Power Company
Utility:
Generation	19,250	17,602
Transmission	9,392	8,332
Distribution	11,785	11,151
Nuclear fuel	1,626	1,599
General and other	821	794
Plant under construction	1,639	2,840
Total utility	44,513	42,318
Nonutility:
Other-including plant under construction	11	11
Total property, plant and equipment	44,524	42,329
Dominion Energy Gas Holdings, LLC
Utility:
Transmission	4,758	4,732
Distribution	3,527	3,267
Storage	1,691	1,688
Gas gathering and processing	210	202
General and other	233	216
Plant under construction	494	293
Total utility	10,913	10,398
Nonutility:
Gas gathering and processing	185	630
Other-including plant under construction	140	145
Total nonutility	325	775
Total property, plant and equipment	$ 11,238	$ 11,173

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Property, Plant and Equipment (Share of Jointly-Owned Power Stations) (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Millstone Unit
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	93.50%	[1]
Plant in service	$ 1,231	[1]
Accumulated depreciation	(400)	[1]
Nuclear fuel	571	[1]
Accumulated amortization of nuclear fuel	(423)	[1]
Plant under construction	$ 66	[1]
Virginia Electric and Power Company | Bath Country Pumped Storage Station
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	60.00%	[2]
Plant in service	$ 1,058	[2]
Accumulated depreciation	(639)	[2]
Plant under construction	$ 6	[2]
Virginia Electric and Power Company | North Anna
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	88.40%	[2]
Plant in service	$ 2,560	[2]
Accumulated depreciation	(1,305)	[2]
Nuclear fuel	721	[2]
Accumulated amortization of nuclear fuel	(608)	[2]
Plant under construction	$ 103	[2]
Virginia Electric and Power Company | Clover Power Station
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	50.00%	[2]
Plant in service	$ 590	[2]
Accumulated depreciation	(240)	[2]
Plant under construction	$ 9	[2]

[1] Unit jointly owned by Dominion Energy.

[2] Units jointly owned by Virginia Power.

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Property, Plant and Equipment (Narrative) (Detail) $ in Millions	1 Months Ended												3 Months Ended				12 Months Ended
	Sep. 30, 2018 USD ($)	Aug. 31, 2018 Project	Jun. 30, 2018 USD ($) a field	Mar. 31, 2018 USD ($) a field	Jan. 31, 2018 USD ($) a	Dec. 31, 2017 USD ($)	Sep. 30, 2017 Project	Aug. 31, 2017 USD ($) a	Jul. 31, 2017 USD ($) a	Apr. 30, 2016 a	Mar. 31, 2015 USD ($) a	Nov. 30, 2014 USD ($) a field	Mar. 31, 2019 USD ($) MW	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2020 USD ($) MW	Dec. 31, 2019 USD ($) MW	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($) a	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($) a	Oct. 31, 2018 USD ($)	Oct. 31, 2017 USD ($)	Mar. 31, 2017 USD ($)
Property, Plant and Equipment [Line Items]
Cost of project																			$ 151	$ 405	$ 40
Revenue recognized																			94
Virginia Electric and Power Company
Property, Plant and Equipment [Line Items]
Cost of project																			141	41	7
Revenue recognized																			25
Virginia Electric and Power Company | Two Solar Development Projects
Property, Plant and Equipment [Line Items]
Number of Projects | Project		2					2
Virginia Electric and Power Company | First Solar Development Project
Property, Plant and Equipment [Line Items]
Cost of project														$ 140
Dominion Energy Gas Holdings, LLC
Property, Plant and Equipment [Line Items]
Revenue recognized																			41
Dominion Energy Gas Holdings, LLC | Marcellus Shale | Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Amount of consideration			$ 6		$ 28				$ 5			$ 120									$ 10		$ 200
Number of natural gas producers																							2
Development rights (number of acres) | a			9,000		18,000				2,000			24,000									4,000		100,000
Period for payments related to conveyance of natural gas storage fields												4 years											9 years
Proceeds from assignment of Shale Development Rights												$ 60										$ 16	$ 100
Gas and oil area developed net remaining interest conveyed percentage					50.00%				50.00%			50.00%									50.00%
Number of natural gas storage fields | field			1									1
Number of acres included in initial conveyance | a												12,000
Dominion Energy Gas Holdings, LLC | Marcellus Shale | Amended Agreement to Extend Conveyance of Development Rights | Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Gain on sale															$ 9	$ 56
After tax gain on sale															5	$ 33
Development rights (number of acres) | a								70,000		70,000	9,000
Period for payments related to conveyance of natural gas storage fields											2 years
Gas and oil area developed net remaining interest conveyed percentage								68.00%		32.00%
Total consideration	$ 65							$ 130							65
Dominion Energy Gas Holdings, LLC | Marcellus Shale | Final Conveyance | Amended Agreement to Extend Conveyance of Development Rights | Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Gain on sale	65
After tax gain on sale	47
Dominion Energy Gas Holdings, LLC | Utica and Point Pleasant Shale | Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Amount of consideration				$ 16
Development rights (number of acres) | a				11,000
Proceeds from assignment of Shale Development Rights				$ 16
Number of natural gas storage fields | field				1
Dominion Energy Gas Holdings, LLC | Other operations and maintenance | Marcellus Shale | Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Gain on sale			$ 6		$ 28				$ 5												$ 10
After tax gain on sale			$ 4		$ 20				$ 3												$ 6
Dominion Energy Gas Holdings, LLC | Other operations and maintenance | Marcellus Shale | Amended Agreement to Extend Conveyance of Development Rights | Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Revenue recognized	35										$ 43
Revenue recognized net of tax	$ 21										$ 27
Dominion Energy Gas Holdings, LLC | Other operations and maintenance | Utica and Point Pleasant Shale | Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Gain on sale				$ 16
After tax gain on sale				$ 12
Scenario, Forecast | Virginia Electric and Power Company
Property, Plant and Equipment [Line Items]
Cost of project													$ 37
MW capacity | MW													20
Scenario, Forecast | Virginia Electric and Power Company | Two Solar Development Projects
Property, Plant and Equipment [Line Items]
MW capacity | MW																	155	155
Scenario, Forecast | Virginia Electric and Power Company | First Solar Development Project
Property, Plant and Equipment [Line Items]
Cost of project																		$ 120
Scenario, Forecast | Virginia Electric and Power Company | Second Solar Development Project
Property, Plant and Equipment [Line Items]
Cost of project																	$ 130	$ 140
Retail Energy Marketing Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Property, Plant and Equipment [Line Items]
Amount of consideration																									$ 143
Contractual term of agreement to use brand						10 years
Gain on sale						$ 78								65
After tax gain on sale						48								49
Retail Energy Marketing Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations | First Phase of Agreements to Sell Certain Assets
Property, Plant and Equipment [Line Items]
Amount of consideration						$ 79									$ 79					79
Retail Energy Marketing Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Second Phase of Agreements to Sell Certain Assets
Property, Plant and Equipment [Line Items]
Amount of consideration																								$ 63
Fairless and Manchester
Property, Plant and Equipment [Line Items]
Amount of consideration														1,200					1,200
Gain on sale of equity method investment																			210
Gain on sale of equity method investments, net of tax																			198
Assignment of Tower Rental Portfolio | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Virginia Electric and Power Company
Property, Plant and Equipment [Line Items]
Amount of consideration																										$ 91
Amount recognized in operating revenue and other income from sale																			6	$ 11
Amount to be recognized in other income ratably through 2023														$ 29					$ 29

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Goodwill and Intangible Assets (Goodwill) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Goodwill [Roll Forward]
Goodwill, Beginning Balance	[1]	$ 6,405	$ 6,399
Purchase Accounting Adjustment		5
Dominion Questar Combination			6
Goodwill, Ending Balance	[1]	6,410	6,405
Dominion Energy Gas Holdings, LLC
Goodwill [Roll Forward]
Goodwill, Beginning Balance	[1]	542	542
Purchase Accounting Adjustment		5
No events affecting goodwill			0
Goodwill, Ending Balance	[1]	547	542
Operating Segments | Power Generation
Goodwill [Roll Forward]
Goodwill, Beginning Balance	[1]	1,422	1,422
Goodwill, Ending Balance	[1]	1,422	1,422
Operating Segments | Gas Infrastructure
Goodwill [Roll Forward]
Goodwill, Beginning Balance	[1]	4,057	4,051
Purchase Accounting Adjustment		5
Dominion Questar Combination	[2]		6
Goodwill, Ending Balance	[1]	4,062	4,057
Operating Segments | Power Delivery
Goodwill [Roll Forward]
Goodwill, Beginning Balance	[1]	926	926
Goodwill, Ending Balance	[1]	926	926
Operating Segments | Dominion Energy Gas Holdings, LLC | Power Generation
Goodwill [Roll Forward]
No events affecting goodwill			0
Operating Segments | Dominion Energy Gas Holdings, LLC | Gas Infrastructure
Goodwill [Roll Forward]
Goodwill, Beginning Balance	[1]	542	542
Purchase Accounting Adjustment		5
No events affecting goodwill			0
Goodwill, Ending Balance	[1]	$ 547	542
Operating Segments | Dominion Energy Gas Holdings, LLC | Power Delivery
Goodwill [Roll Forward]
No events affecting goodwill			0
Operating Segments | Dominion Energy Gas Holdings, LLC | Corporate and Other
Goodwill [Roll Forward]
No events affecting goodwill	[3]		$ 0

[1] Goodwill amounts do not contain any accumulated impairment losses.

[2] See Note 3.

[3] Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.

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Goodwill and Intangible Assets (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Amortization expense for intangible assets	$ 82	$ 80	$ 73
Acquisition of intangible assets	$ 127
Weighted-average amortization period (years)	15 years
Virginia Electric and Power Company
Goodwill [Line Items]
Amortization expense for intangible assets	$ 31	31	29
Acquisition of intangible assets	$ 49
Weighted-average amortization period (years)	11 years
Dominion Energy Gas Holdings, LLC
Goodwill [Line Items]
Amortization expense for intangible assets	$ 14	$ 14	$ 6
Acquisition of intangible assets	$ 14
Weighted-average amortization period (years)	10 years

XML

Goodwill and Intangible Assets (Components of Intangible Assets) (Detail) - Computer Software, Intangible Asset [Member] - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 1,033	$ 1,043
Accumulated Amortization	363	358
Virginia Electric and Power Company
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	384	347
Accumulated Amortization	134	114
Dominion Energy Gas Holdings, LLC
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	174	165
Accumulated Amortization	$ 65	$ 56

XML

Goodwill and Intangible Assets (Annual Amortization Expense of Intangible Assets) (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Finite-Lived Intangible Assets [Line Items]
2019	$ 67
2020	56
2021	44
2022	34
2023	23
Virginia Electric and Power Company
Finite-Lived Intangible Assets [Line Items]
2019	29
2020	23
2021	16
2022	12
2023	6
Dominion Energy Gas Holdings, LLC
Finite-Lived Intangible Assets [Line Items]
2019	14
2020	13
2021	12
2022	8
2023	$ 7

XML

Regulatory Assets and Liabilities (Schedule of Regulatory Assets) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Regulatory assets-current		$ 496	$ 294
Regulatory assets-noncurrent		2,676	2,480
Total regulatory assets		3,172	2,774
Virginia Electric and Power Company
Regulatory Assets [Line Items]
Regulatory assets-current		424	205
Regulatory assets-noncurrent		737	810
Total regulatory assets		1,161	1,015
Dominion Energy Gas Holdings, LLC
Regulatory Assets [Line Items]
Regulatory assets-current	[1]	29	26
Regulatory assets-noncurrent		727	511
Total regulatory assets		756	537
Deferred nuclear refueling outage costs
Regulatory Assets [Line Items]
Regulatory assets-current	[2]	$ 69	54
Deferred nuclear refueling outage costs | Maximum
Regulatory Assets [Line Items]
Amortization period for deferred costs		18 months
Deferred nuclear refueling outage costs | Virginia Electric and Power Company
Regulatory Assets [Line Items]
Regulatory assets-current	[2]	$ 69	54
Deferred cost of fuel used in electric generation
Regulatory Assets [Line Items]
Regulatory assets-current	[3]	174	23
Regulatory assets-noncurrent	[3]	83
Deferred cost of fuel used in electric generation | Virginia Electric and Power Company
Regulatory Assets [Line Items]
Regulatory assets-current	[3]	174	23
Regulatory assets-noncurrent	[3]	83
Deferred rate adjustment clause costs
Regulatory Assets [Line Items]
Regulatory assets-current	[3]	96	70
Regulatory assets-noncurrent	[4]	329	401
Deferred rate adjustment clause costs | Virginia Electric and Power Company
Regulatory Assets [Line Items]
Regulatory assets-current	[4]	78	56
Regulatory assets-noncurrent	[4]	230	312
Deferred rate adjustment clause costs | Dominion Energy Gas Holdings, LLC
Regulatory Assets [Line Items]
Regulatory assets-current	[4]	18	14
Regulatory assets-noncurrent	[4]	99	89
Unrecovered gas costs
Regulatory Assets [Line Items]
Regulatory assets-current	[5]	14	38
Unrecovered gas costs | Dominion Energy Gas Holdings, LLC
Regulatory Assets [Line Items]
Regulatory assets-current	[5]	9	8
Other
Regulatory Assets [Line Items]
Regulatory assets-current		143	109
Regulatory assets-noncurrent		187	151
Other | Virginia Electric and Power Company
Regulatory Assets [Line Items]
Regulatory assets-current		103	72
Regulatory assets-noncurrent		81	86
Other | Dominion Energy Gas Holdings, LLC
Regulatory Assets [Line Items]
Regulatory assets-current		2	4
Regulatory assets-noncurrent		32	17
Unrecognized pension and other postretirement benefit costs
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	[6]	1,497	1,336
Unrecognized pension and other postretirement benefit costs | Dominion Energy Gas Holdings, LLC
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	[6]	392	258
Utility reform legislation
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	[7]	204	147
Utility reform legislation | Dominion Energy Gas Holdings, LLC
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	[7]	204	147
PJM transmission rates
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	[8]	192	222
PJM transmission rates | Virginia Electric and Power Company
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	[8]	192	222
Derivatives
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	[9]	184	223
Derivatives | Virginia Electric and Power Company
Regulatory Assets [Line Items]
Regulatory assets-noncurrent	[9]	$ 151	$ 190

[1] Current regulatory assets are presented in other current assets in Dominion Energy Gas' Consolidated Balance Sheets.

[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] Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Dominion Energy and Virginia Power's generation operations. See Note 13 for more information.

[4] Primarily reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects net of income taxes refundable from the 2017 Tax Reform Act for Virginia Power and deferrals of costs associated with certain current and prospective rider projects for Dominion Energy Gas. See Note 13 for more information.

[5] Reflects unrecovered or overrecovered gas costs at regulated gas operations, which are recovered or refunded through filings with the applicable regulatory authority.

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

[7] Ohio legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future.

[8] Reflects amounts related to the PJM transmission cost allocation matter. See Note 13 for more information.

[9] As discussed under Derivative Instruments in Note 2, 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.

XML

Regulatory Assets and Liabilities (Schedule of Regulatory Liabilities) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[1]	$ 356	$ 193
Regulatory liabilities-noncurrent		6,840	6,916
Total regulatory liabilities		7,196	7,109
Provision for future cost of removal and AROs
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[2]	117	101
Regulatory liabilities-noncurrent	[2]	1,409	1,384
Reserve for rate credits to customers
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[3]	71
Other
Regulatory Liabilities [Line Items]
Regulatory liabilities-current		64	92
Regulatory liabilities-noncurrent		265	284
Nuclear decommissioning trust
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent	[4]	1,070	1,121
Income taxes refundable through future rates
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent	[5]	4,071	4,058
Cost-of-service impact of 2017 Tax Reform Act
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[6]	104
Derivatives
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent	[7]	25	69
Virginia Electric and Power Company
Regulatory Liabilities [Line Items]
Regulatory liabilities-current		299	127
Regulatory liabilities-noncurrent		4,647	4,760
Total regulatory liabilities		4,946	4,887
Virginia Electric and Power Company | Reserve for rate credits to customers
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[3]	71
Virginia Electric and Power Company | Other
Regulatory Liabilities [Line Items]
Regulatory liabilities-current		41	47
Regulatory liabilities-noncurrent		33	74
Virginia Electric and Power Company | Nuclear decommissioning trust
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent	[4]	1,070	1,121
Virginia Electric and Power Company | Income taxes refundable through future rates
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent	[5]	2,579	2,581
Virginia Electric and Power Company | Cost-of-service impact of 2017 Tax Reform Act
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[6]	95
Virginia Electric and Power Company | Provision for future cost of removal
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[2]	92	80
Regulatory liabilities-noncurrent	[2]	940	915
Virginia Electric and Power Company | Derivatives
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent	[7]	25	69
Dominion Energy Gas Holdings, LLC
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[1]	21	38
Regulatory liabilities-noncurrent		1,285	1,227
Total regulatory liabilities		1,306	1,265
Dominion Energy Gas Holdings, LLC | Provision for future cost of removal and AROs
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[2]	14	13
Regulatory liabilities-noncurrent	[2]	158	160
Dominion Energy Gas Holdings, LLC | Other
Regulatory Liabilities [Line Items]
Regulatory liabilities-current		4	5
Regulatory liabilities-noncurrent		97	69
Dominion Energy Gas Holdings, LLC | Income taxes refundable through future rates
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent	[5]	1,011	998
Dominion Energy Gas Holdings, LLC | Cost-of-service impact of 2017 Tax Reform Act
Regulatory Liabilities [Line Items]
Regulatory liabilities-noncurrent	[6]	19
Dominion Energy Gas Holdings, LLC | PIPP
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[8]	$ 3	$ 20

[1] Current regulatory liabilities are presented in other current liabilities in Dominion Energy and Dominion Energy Gas' Consolidated Balance Sheets.

[2] 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.

[3] Charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers. See Note 13 for more information.

[4] 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.

[5] Amounts recorded to pass the effect of reduced income tax rates from the 2017 Tax Reform Act to customers in future periods, which will reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity.

[6] Balance refundable to customers related to the decrease in revenue requirements for recovery of income taxes at the Companies' regulated electric generation and electric and natural gas distribution operations. See Note 13 for more information.

[7] As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

[8] 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 rider according to East Ohio tariff provisions. See Note 13 for more information.

XML

Regulatory Assets and Liabilities (Narrative) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Public Utilities General Disclosures [Line Items]
Regulatory assets past expenditures not earning return	$ 396
Period for which expenditures are expected to be recovered	2 years
Virginia Electric and Power Company
Public Utilities General Disclosures [Line Items]
Regulatory assets past expenditures not earning return	$ 300
Dominion Energy Gas Holdings, LLC
Public Utilities General Disclosures [Line Items]
Regulatory assets past expenditures not earning return	$ 12

XML

Regulatory Matters (Narrative) (Detail) MMcf in Millions, Customer in Millions, $ in Millions		1 Months Ended																				12 Months Ended
	Feb. 01, 2020	Jan. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Nov. 30, 2018 USD ($) Project MW mi	Oct. 31, 2018 USD ($) Program	Oct. 30, 2018 MMcf	Sep. 30, 2018 USD ($)	Aug. 31, 2018 USD ($) MMBTU	Jul. 31, 2018 USD ($) Facility	Jun. 30, 2018 USD ($) kV Segment	May 31, 2018 USD ($)	Apr. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	May 31, 2017 USD ($)	Nov. 30, 2015 USD ($) kV mi	Jun. 30, 2015 USD ($) Buildings	Mar. 31, 2015 USD ($)	Nov. 30, 2013 kV mi	Aug. 31, 2009 kV	Dec. 31, 2007 Customer	Apr. 30, 2007 kV	Jan. 31, 2020	Dec. 31, 2019 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($) kV Segments mi	Aug. 31, 2018 USD ($) MMBTU	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Jul. 31, 2017 USD ($)
Public Utilities General Disclosures [Line Items]
Regulatory assets-noncurrent			$ 2,676.0																						$ 2,676.0			$ 2,480.0
Reduction in regulatory liabilities																									35.0			4,200.0
Annual regulatory liability deferral amount			0.4																						$ 0.4
Separate segments | Segments																									3
Asset impairment pre tax charge																									$ 403.0			15.0	$ 4.0
Virginia Electric and Power Company
Public Utilities General Disclosures [Line Items]
Regulatory assets-noncurrent			737.0																						737.0			810.0
Tax reform benefit								$ 100.0
Reduction in regulatory liabilities					$ 14.0																				$ 31.0			2,600.0
Regulatory liabilities one time bill credit amount					13.0
Separate segments | Segments																									2
Virginia Electric and Power Company | Minimum
Public Utilities General Disclosures [Line Items]
Facility operating capacity (kV) | kV																					500
Virginia Electric and Power Company | Minimum | Judicial Ruling
Public Utilities General Disclosures [Line Items]
Facility operating capacity (kV) | kV																			500
Virginia Electric and Power Company | Scenario, Forecast
Public Utilities General Disclosures [Line Items]
Asset impairment pre tax charge																							$ 190.0
Virginia Electric and Power Company | FERC-regulated | Settled Litigation | Order Regarding Transmission Rate Design for Allocation of Costs among PJM Interconnect LLC Transmission Customers | Unfavorable Regulatory Action | Other Deferred Credits And Other Liabilities
Public Utilities General Disclosures [Line Items]
Amount of contingent liability			50.0																						$ 50.0
Virginia Electric and Power Company | FERC-regulated | Settled Litigation | Order Regarding Transmission Rate Design for Allocation of Costs among PJM Interconnect LLC Transmission Customers | Unfavorable Regulatory Action | Current Liabilities
Public Utilities General Disclosures [Line Items]
Amount of contingent liability			126.0																						126.0
Virginia Electric and Power Company | FERC-regulated | Settled Litigation | Order Regarding Transmission Rate Design for Allocation of Costs among PJM Interconnect LLC Transmission Customers | Unfavorable Regulatory Action | PJM transmission rates
Public Utilities General Disclosures [Line Items]
Regulatory assets-noncurrent								$ 265.0																		$ 265.0
Duration of payment under settlement agreement								10 years
Amount required to pay under settlement agreement								$ 276.0
Virginia Electric and Power Company | Virginia Regulation
Public Utilities General Disclosures [Line Items]
Proposed annual revenue reduction amount					151.0																				190.0
Interim rate reduction amount									$ 125.0
Rate reduction																									50.0
One-time bill credit, provisions for current customers																									200.0
Charge associated with legislation																									215.0
Charge associated with legislation, after tax																									$ 160.0
Legislation amount credited in customer bill									138.0
Proposed revenue requirement											$ 1,500.0
Increase in fuel revenue								209.0			222.0
Capacity of transmission line (kV) | kV																									115
Obligated to make payments to fund improvement for historical and cultural resources																														$ 90.0
Payments made to fund improvement for historical and cultural resources																												90.0
Virginia Electric and Power Company | Virginia Regulation | Operating Segments
Public Utilities General Disclosures [Line Items]
Proposed revenue requirement				$ 628.0				636.0						$ 755.0
Virginia Electric and Power Company | Virginia Regulation | Transmission Component of Virginia Power's | Operating Segments
Public Utilities General Disclosures [Line Items]
Proposed revenue requirement														468.0
Virginia Electric and Power Company | Virginia Regulation | Coastal Virginia Offshore Wind Project
Public Utilities General Disclosures [Line Items]
The total estimated capital investment				$ 300.0
Capacity of wind turbine generators | MW				6
Public utilities length of wind project | mi				27
Number of wind projects | Project				2
Virginia Electric and Power Company | Virginia Regulation | Surry Switching Station Transmission Line
Public Utilities General Disclosures [Line Items]
Length of kV line (miles) | mi																		7
Capacity of transmission line (kV) | kV																		500
Virginia Electric and Power Company | Virginia Regulation | Transmission Line from Skiffes Creek Switching Station to Wheaton Substation
Public Utilities General Disclosures [Line Items]
Length of kV line (miles) | mi																		20
Capacity of transmission line (kV) | kV																		230
Virginia Electric and Power Company | Virginia Regulation | Transmission Line Near Gainesville Substation And Haymarket Substation
Public Utilities General Disclosures [Line Items]
The total estimated capital investment															$ 180.0
Length of kV line (miles) | mi															5
Capacity of transmission line (kV) | kV															230
Virginia Electric and Power Company | Virginia Regulation | Double Circuit Transmission Line Between Near Gainesville Substation And Haymarket Substation
Public Utilities General Disclosures [Line Items]
Capacity of transmission line (kV) | kV															230
Virginia Electric and Power Company | Virginia Regulation | Transmission Line Between Idylwood and Tysons Substations
Public Utilities General Disclosures [Line Items]
The total estimated capital investment			125.0							$ 30.0															$ 125.0
Length of kV line (miles) | mi																									4.0
Capacity of transmission line (kV) | kV										230															230
Separate segments | Segment										4
Virginia Electric and Power Company | Virginia Regulation | Transmission Line Between The Idylwood And Tysons Substations
Public Utilities General Disclosures [Line Items]
The total estimated capital investment			816.0																						$ 816.0
Operations and maintenance expenses																									102.0
Virginia Electric and Power Company | Virginia Regulation | Rider T1 | Operating Segments
Public Utilities General Disclosures [Line Items]
Proposed revenue requirement								630.0						287.0
Increase (decrease) in revenue requirement														$ (146.0)
Virginia Electric and Power Company | Virginia Regulation | Rider U
Public Utilities General Disclosures [Line Items]
Approved revenue required			70.0										$ 73.0
Virginia Electric and Power Company | Virginia Regulation | Riders C1A and C2A | Energy Efficiency Program | Operating Segments
Public Utilities General Disclosures [Line Items]
Increase (decrease) in revenue requirement					18.0
Approved revenue required					$ 49.0
Number of new energy efficiency programs | Program					10
Period for cost cap					5 years
Number of new demand response programs | Program					1
Amount of cost recovery					$ 262.0
Virginia Electric and Power Company | Virginia Regulation | Solar Development Project
Public Utilities General Disclosures [Line Items]
The total estimated capital investment									$ 410.0
Number of solar facility | Facility									2
Virginia Electric and Power Company | Virginia Regulation | Solar Development Project | Rider US-3 | Operating Segments
Public Utilities General Disclosures [Line Items]
Proposed revenue requirement									$ 10.0
Virginia Electric and Power Company | Virginia Regulation | Subsequent Event
Public Utilities General Disclosures [Line Items]
Proposed annual revenue reduction amount		$ 171.0
Expected annual revenue reduction on one-time bill credit		120.0
Interim rate reduction amount		120.0
Legislation amount credited in customer bill		77.0
Virginia Electric and Power Company | Virginia Regulation | Subsequent Event | Transmission Line Between The Idylwood And Tysons Substations
Public Utilities General Disclosures [Line Items]
The total estimated capital investment		$ 68.0
Virginia Electric and Power Company | Virginia Regulation | Subsequent Event | Solar Development Project | Rider US-3 | Operating Segments
Public Utilities General Disclosures [Line Items]
Performance guarantee of the facilities		20 years
Solar capacity factor when normalized for force majeure events		25.00%
Virginia Electric and Power Company | Virginia Regulation | Third Phase | Rider U
Public Utilities General Disclosures [Line Items]
Projected capital investment			179.0										179.0
Virginia Electric and Power Company | Virginia Regulation | Second Phase | Rider U
Public Utilities General Disclosures [Line Items]
Projected capital investment			64.0										65.0
Virginia Electric and Power Company | North Carolina Regulation | Annual Base Fuel Revenues
Public Utilities General Disclosures [Line Items]
Increase (decrease) in revenue requirement								$ 24.0
Virginia Electric and Power Company | North Carolina Regulation | Subsequent Event | Annual Base Fuel Revenues
Public Utilities General Disclosures [Line Items]
Increase (decrease) in revenue requirement		$ 24.0
Virginia Electric and Power Company | North Carolina Regulation | Scenario, Forecast
Public Utilities General Disclosures [Line Items]
Mitigation recoverable percentage																						50.00%
Mitigation recoverable remaining percentage	50.00%
DETI
Public Utilities General Disclosures [Line Items]
Expected cost of project																										$ 95.0
Agreement to provide Dths per day of transportation service | MMBTU								150,000																		150,000
DETI | FERC-regulated | Supply Header Project | Atlantic Coast Pipeline
Public Utilities General Disclosures [Line Items]
Annual electric power cost rate adjustment, approval amount requested to recover amount							$ 7.0
Annual transportation cost rate adjustment, approval amount requested to recover amount							$ 37.0
DETI | FERC-regulated | Preliminary recommendation one | Other operations and maintenance
Public Utilities General Disclosures [Line Items]
Audit compliance charge recognized in connection with preliminary recommendation																									129.0			15.0
Audit compliance after-tax charge recognized in connection with preliminary recommendation																									94.0			9.0
Questar Gas | Cost-of-service impact of 2017 Tax Reform Act
Public Utilities General Disclosures [Line Items]
Reduction in regulatory liabilities											$ 15.0
Refund to customers related to deferred corporate income tax reduction									$ 9.0
Regulatory liability, amortization period											1 year
Questar Gas | Utah and Wyoming Regulation | Pipeline Infrastructure Replacement Program
Public Utilities General Disclosures [Line Items]
Projected capital investment																									85.0
Questar Gas | Utah and Wyoming Regulation | Fuel Deferral [Member]
Public Utilities General Disclosures [Line Items]
Proposed cost increase (decrease) amount					$ 48.0						$ 86.0
LNG peaking storage facility, liquefaction rate per day | MMcf						8.2
Questar Gas | Utah and Wyoming Regulation | Scenario, Forecast | Pipeline Infrastructure Replacement Program
Public Utilities General Disclosures [Line Items]
Public utilities additional revenue to be collected																							11.0
East Ohio | Ohio Regulation | Pipeline Infrastructure Replacement Program
Public Utilities General Disclosures [Line Items]
Proposed revenue requirement																									165.0
Percentage replacement of pipeline system																	25.00%
Period for capital investment																	5 years
Actual cumulative PREP Investment																	$ 200.0
Annual percentage increase in capital investment																	3.00%
Total estimated cost			1,400.0																						1,400.0			204.0
East Ohio | Ohio Regulation | Automated Meter Reading Program
Public Utilities General Disclosures [Line Items]
Proposed revenue requirement												$ 5.0
Number of customers with automated meter reading technology | Customer																				1.2
East Ohio | Ohio Regulation | Percentage Of Income Payment Plan Rider
Public Utilities General Disclosures [Line Items]
Refund of over-recovery of accumulated arrearages											10.0
Recovery of projected deferred program costs											$ 4.0
East Ohio | Ohio Regulation | UEX Rider
Public Utilities General Disclosures [Line Items]
Elimination of over-recovered balance of accumulated bad debt expense													$ 11.0
East Ohio | Ohio Regulation | Demand Side Management Costs
Public Utilities General Disclosures [Line Items]
Annual electric power cost rate adjustment, approval amount requested to recover amount				$ 4.0
East Ohio | Ohio Regulation | Scenario, Forecast | UEX Rider
Public Utilities General Disclosures [Line Items]
Recovery of prospective net bad debt expense																								$ 16.0
Hope Gas, Inc. | West Virginia Regulation | PREP
Public Utilities General Disclosures [Line Items]
Projected capital investment																									31.0
Amount of cost recovery				$ 8.0																								28.0
Actual cumulative PREP Investment																												48.0
Annual PREP costs recovered																												$ 7.0
Projected PREP investment			31.0																						31.0
Hope Gas, Inc. | West Virginia Regulation | Scenario, Forecast | PREP
Public Utilities General Disclosures [Line Items]
Projected capital investment																							36.0
Projected PREP investment																							$ 29.0
Cove Point | FERC-regulated | Supply Header Project | Atlantic Coast Pipeline
Public Utilities General Disclosures [Line Items]
Annual transportation cost rate adjustment, approval amount requested to recover amount																											$ 30.0
Public utilities expected cost to acquire productive assets																$ 150.0
Public utilities number of binding precedent agreements for project facilities | Buildings																2
Estimated Cost of project																									45.0
Asset impairment pre tax charge																									37.0
Asset impairment after tax charge			$ 28.0																						$ 28.0

XML

Regulatory Matters - Additional Significant Riders (Detail) - Virginia Electric and Power Company $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Rider S
Public Utilities General Disclosures [Line Items]
Application Date	2018-06
Approval Date	February 2019
Rate Year Beginning	2019-04
Total Revenue Requirement (millions)	$ 215
Increase (Decrease) Over Previous Year (millions)	$ (3)
Rider GV
Public Utilities General Disclosures [Line Items]
Application Date	2018-06
Approval Date	February 2019
Rate Year Beginning	2019-04
Total Revenue Requirement (millions)	$ 120
Increase (Decrease) Over Previous Year (millions)	$ 38
Rider W
Public Utilities General Disclosures [Line Items]
Application Date	2018-06
Approval Date	February 2019
Rate Year Beginning	2019-04
Total Revenue Requirement (millions)	$ 105
Increase (Decrease) Over Previous Year (millions)	$ (4)
Rider R
Public Utilities General Disclosures [Line Items]
Application Date	2018-06
Approval Date	February 2019
Rate Year Beginning	2019-04
Total Revenue Requirement (millions)	$ 57
Increase (Decrease) Over Previous Year (millions)	$ (9)
Rider B
Public Utilities General Disclosures [Line Items]
Application Date	2018-06
Approval Date	February 2019
Rate Year Beginning	2019-04
Total Revenue Requirement (millions)	$ 38
Increase (Decrease) Over Previous Year (millions)	$ (9)
Rider BW
Public Utilities General Disclosures [Line Items]
Application Date	2018-10
Approval Date	Pending
Rate Year Beginning	2019-09
Total Revenue Requirement (millions)	$ 123
Increase (Decrease) Over Previous Year (millions)	$ 7
Rider US-2
Public Utilities General Disclosures [Line Items]
Application Date	2018-10
Approval Date	Pending
Rate Year Beginning	2019-09
Total Revenue Requirement (millions)	$ 16
Increase (Decrease) Over Previous Year (millions)	$ 3
Rider E
Public Utilities General Disclosures [Line Items]
Application Date	2018-12
Approval Date	Pending
Rate Year Beginning	2019-11
Total Revenue Requirement (millions)	$ 114

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Regulatory Matters - Summary of Additional Significant Virginia Power Electric Transmission Projects Approved and Applied (Detail) - Virginia Electric and Power Company - Virginia Regulation $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2018 USD ($) kV	Dec. 31, 2018 USD ($) kV mi
Public Utilities General Disclosures [Line Items]
Capacity of transmission line (kV)		115
Transmission Lines Between Possum Point Switching Station And Novec's Smoketown Delivery Point [Member]
Public Utilities General Disclosures [Line Items]
Application Date		2017-06
Approval Date		2018-02
Capacity of transmission line (kV)		230
Length of kV line (miles) | mi		9.0
Total estimated cost of project | $		$ 20
Transmission Line Between Dooms Substation And Valley Substation [Member]
Public Utilities General Disclosures [Line Items]
Application Date		2017-09
Approval Date		2018-09
Capacity of transmission line (kV)		500
Length of kV line (miles) | mi		18.0
Total estimated cost of project | $		$ 65
Transmission Line Between Idylwood and Tysons Substations
Public Utilities General Disclosures [Line Items]
Application Date		2017-11
Approval Date		2018-09
Capacity of transmission line (kV)	230	230
Length of kV line (miles) | mi		4.0
Total estimated cost of project | $	$ 30	$ 125
Transmission Lines Between Chesterfield and Hopewell Substations
Public Utilities General Disclosures [Line Items]
Application Date		2018-05
Approval Date		2018-11
Capacity of transmission line (kV)		230
Length of kV line (miles) | mi		8.0
Total estimated cost of project | $		$ 30
Transmission Lines Between Chesterfield and Lakeside Substations
Public Utilities General Disclosures [Line Items]
Application Date		2018-05
Approval Date		2018-12
Capacity of transmission line (kV)		230
Length of kV line (miles) | mi		21.0
Total estimated cost of project | $		$ 35
Transmission Lines Between Landstown and Thrasher Substations
Public Utilities General Disclosures [Line Items]
Application Date		2018-06
Approval Date		2018-12
Capacity of transmission line (kV)		230
Length of kV line (miles) | mi		8.5
Total estimated cost of project | $		$ 20
Transmission Line In Alleghany Country Virginia And Covington Virginia
Public Utilities General Disclosures [Line Items]
Application Date		2018-08
Capacity of transmission line (kV)		138
Length of kV line (miles) | mi		5.0
Total estimated cost of project | $		$ 15
Build a new substation and connect three existing transmission lines thereto in Fluvanna County, Virginia
Public Utilities General Disclosures [Line Items]
Application Date		2018-10
Capacity of transmission line (kV)		230
Total estimated cost of project | $		$ 30
Maximum | Build a new substation and connect three existing transmission lines thereto in Fluvanna County, Virginia
Public Utilities General Disclosures [Line Items]
Length of kV line (miles) | mi		1

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Asset Retirement Obligations (Changes to AROs) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
AROs, Beginning balance		$ 2,432	[1]	$ 2,485
Obligations incurred during the period		20		37
Obligations settled during the period		(159)		(214)
Revisions in estimated cash flows		120	[2]	7
Accretion		119		117
AROs, Ending balance	[1]	2,532		2,432
Virginia Electric and Power Company
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
AROs, Beginning balance		1,365		1,443
Obligations incurred during the period		14		11
Obligations settled during the period		(119)		(152)
Revisions in estimated cash flows		120	[2]	(1)
Accretion		65		64
AROs, Ending balance		1,445		1,365
Dominion Energy Gas Holdings, LLC
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
AROs, Beginning balance		160	[3]	156
Obligations incurred during the period		4		2
Obligations settled during the period		(6)		(7)
Accretion		9		9
AROs, Ending balance	[3]	$ 167		$ 160

[1] Includes $263 million and $282 million reported in other current liabilities at December 31, 2017, and 2018, respectively.

[2] Reflects future ash pond and landfill closure costs at certain utility generation facilities. See Note 22 for further information.

[3] Includes $146 million and $153 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities, at December 31, 2017 and 2018, respectively.

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Asset Retirement Obligations (Changes to AROs) (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations [Line Items]
Asset retirement obligations, non current	$ 2,250	$ 2,169
Current Liabilities
Asset Retirement Obligations [Line Items]
Asset retirement obligation, current	282	263
Other Deferred Credits And Other Liabilities | Dominion Energy Gas Holdings, LLC
Asset Retirement Obligations [Line Items]
Asset retirement obligations, non current	$ 153	$ 146

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Asset Retirement Obligations (Narrative) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds	$ 4,938	$ 5,093
Virginia Electric and Power Company
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds	$ 2,369	$ 2,399

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Variable Interest Entities (Narrative) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($) MW Generators	Dec. 31, 2016 USD ($)
Virginia Electric and Power Company
Variable Interest Entity [Line Items]
Securities due within one year	$ 350	$ 850
Long term debt	11,321	10,496
Payables to affiliates	209	125
Dominion Energy Gas Holdings, LLC
Variable Interest Entity [Line Items]
Securities due within one year	449
Long term debt	3,609	3,570
Payables to affiliates	$ 65	62
Variable Interest Entity, Primary Beneficiary | Partnership Interest | Merchant Solar Projects
Variable Interest Entity [Line Items]
Initial membership interest percentage	67.00%
Variable Interest Entity, Primary Beneficiary | Dominion Energy Midstream Partners, LP | Partnership Interest | Limited Partner
Variable Interest Entity [Line Items]
Percentage of limited partner interests in Dominion Midstream Partners, LP	60.90%
Variable Interest Entity, Primary Beneficiary | Dominion Energy Midstream Partners, LP | Partnership Interest | Preferred Partner
Variable Interest Entity [Line Items]
Percentage of limited partner interests in Dominion Midstream Partners, LP	37.50%
Variable Interest Entity, Primary Beneficiary | SBL Holdco
Variable Interest Entity [Line Items]
Securities due within one year	$ 31
Long term debt	$ 299
Variable Interest Entity, Not Primary Beneficiary | Distribution | Atlantic Coast Pipeline | Pipelines | Jointly Owned Natural Gas Pipeline
Variable Interest Entity [Line Items]
Initial membership interest percentage	48.00%
Variable Interest Entity, Not Primary Beneficiary | Virginia Electric and Power Company | DES
Variable Interest Entity [Line Items]
Shared services purchased	$ 335	340	$ 346
Payables to affiliates	107	36
Variable Interest Entity, Not Primary Beneficiary | Dominion Energy Gas Holdings, LLC | DES
Variable Interest Entity [Line Items]
Shared services purchased	126	126	123
Payables to affiliates	46	$ 14
Variable Interest Entity (VIE) or Potential VIE, Information Unavailability | Virginia Electric and Power Company
Variable Interest Entity [Line Items]
Long term capacity contract non utility generators (generators) | Generators		3
Number of expired non-utility generators | Generators		2
Aggregate generation capacity from long-term power and capacity contracts (MW) | MW		218
Remaining purchase commitments	150
Payment for electric capacity	50	$ 86	144
Payment for electric energy	$ 18	$ 24	$ 31

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Short-Term Debt and Credit Agreements (Narrative) (Detail) - USD ($)	1 Months Ended		12 Months Ended
	Jun. 30, 2018	Feb. 28, 2018	Dec. 31, 2018		Oct. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Facility Limit			$ 6,000,000,000	[1]			$ 5,500,000,000
Short-term debt			334,000,000				3,298,000,000
Dominion Energy Gas Holdings, LLC
Debt Instrument [Line Items]
Facility Limit			1,500,000,000	[2]			1,500,000,000
Short-term debt			10,000,000				629,000,000
Virginia Electric and Power Company
Debt Instrument [Line Items]
Facility Limit			6,000,000,000	[3]			5,500,000,000
Short-term debt			314,000,000				$ 542,000,000
Credit facility			100,000,000
Dominion Energy Midstream Partners, LP
Debt Instrument [Line Items]
Facility Limit						$ 500,000,000
Credit facility, outstanding amount			73,000,000
Six Billion Joint Revolving Credit Facility
Debt Instrument [Line Items]
Facility Limit			6,000,000,000			6,000,000,000
Six Billion Joint Revolving Credit Facility | Questar Gas
Debt Instrument [Line Items]
Facility Limit			250,000,000
Six Billion Joint Revolving Credit Facility | Virginia Electric and Power Company
Debt Instrument [Line Items]
Facility Limit			1,500,000,000
Credit Facilities, Maturing in December 2018 with 1 year Automatic Renewals through 2023 | SBL Holdco
Debt Instrument [Line Items]
Facility Limit			$ 30,000,000
Automatic renewal period			1 year
Short-term debt			$ 0
Credit Facilities, Maturing in May 2018 with 1 year Automatic Renewals through 2024 | Dominion Solar Projects III, Inc
Debt Instrument [Line Items]
Facility Limit			$ 25,000,000
Automatic renewal period			1 year
Short-term debt			$ 0
Term Loan Credit Agreement [Member]
Debt Instrument [Line Items]
Credit facility, outstanding amount	$ 500,000,000	$ 950,000,000
Duration of credit facilities	364 days	364 days
Letter of Credit | Dominion Energy Gas Holdings, LLC
Debt Instrument [Line Items]
Facility Limit			1,500,000,000		$ 21,000,000
Credit facility, outstanding amount			21,000,000
Letter of Credit | Dominion Energy Midstream Partners, LP
Debt Instrument [Line Items]
Facility Limit						$ 250,000,000
Letter of Credit | Six Billion Joint Revolving Credit Facility
Debt Instrument [Line Items]
Facility Limit			2,000,000,000
Letter of Credit | Six Billion Joint Revolving Credit Facility | Virginia Electric and Power Company
Debt Instrument [Line Items]
Facility Limit			$ 2,000,000,000

[1] This credit facility matures in March 2023 and can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

[2] A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. The sub-limit for Dominion Energy Gas is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Dominion Energy Gas was $750 million. If Dominion Energy 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

[3] The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Virginia Power was $1.5 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

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Short-Term Debt and Credit Agreements (Commercial Paper, Bank Loans and Letters of Credit Outstanding) (Detail) - USD ($)		Dec. 31, 2018		Dec. 31, 2017
Line of Credit Facility [Line Items]
Facility Limit		$ 6,000,000,000	[1]	$ 5,500,000,000
Outstanding Commercial Paper	[2]	324,000,000	[1]	3,298,000,000
Outstanding Letters of Credit		88,000,000	[1]	76,000,000
Facility capacity available		5,588,000,000	[1]	2,126,000,000
Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Facility Limit		6,000,000,000	[3]	5,500,000,000
Outstanding Commercial Paper	[4]	314,000,000	[3]	542,000,000
Outstanding Letters of Credit	[3]	16,000,000
Dominion Energy Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit		1,500,000,000	[5]	1,500,000,000
Outstanding Commercial Paper	[6]	$ 10,000,000	[5]	629,000,000
Previous Credit Facility Five Billion [Member]
Line of Credit Facility [Line Items]
Facility Limit	[7]			5,000,000,000
Outstanding Commercial Paper	[2],[7]			3,298,000,000
Facility capacity available	[7]			1,702,000,000
Previous Credit Facility Five Billion [Member] | Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Facility Limit	[8]			5,000,000,000
Outstanding Commercial Paper	[4],[8]			542,000,000
Previous Credit Facility Five Hundred Million [Member]
Line of Credit Facility [Line Items]
Facility Limit	[7]			500,000,000
Outstanding Letters of Credit	[7]			76,000,000
Facility capacity available	[7]			424,000,000
Previous Credit Facility Five Hundred Million [Member] | Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Facility Limit	[8]			500,000,000
Previous Credit Facility Five Hundred Million [Member] | Dominion Energy Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit	[9]			500,000,000
Previous Credit Facility One Billion [Member] | Dominion Energy Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit	[9]			1,000,000,000
Outstanding Commercial Paper	[6],[9]			$ 629,000,000

[1] This credit facility matures in March 2023 and can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

[2] The weighted-average interest rates of the outstanding commercial paper supported by Dominion Energy's credit facilities were 2.93% and 1.61% at December 31, 2018 and 2017, respectively.

[3] The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Virginia Power was $1.5 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

[4] The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 2.94% and 1.65% at December 31, 2018 and 2017, respectively.

[5] A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. The sub-limit for Dominion Energy Gas is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Dominion Energy Gas was $750 million. If Dominion Energy 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

[6] The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 2.58% and 1.57% at December 31, 2018 and 2017, respectively.

[7] These credit facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. The facilities were scheduled to mature in April 2020 and were 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.

[8] These facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. The full amount of the facilities was available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. These facilities were scheduled to mature in April 2020 and were 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.

[9] These facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. A maximum of a combined $1.5 billion of the facilities was available to Dominion Energy Gas, assuming adequate capacity was available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. These credit facilities were scheduled to mature in April 2020 and were used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

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Short-Term Debt and Credit Agreements (Commercial Paper, Bank Loans and Letters of Credit Outstanding) (Parenthetical) (Detail) - USD ($)	Dec. 31, 2018		Oct. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Facility Limit	$ 6,000,000,000	[1]			$ 5,500,000,000
Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Facility Limit	6,000,000,000	[2]			5,500,000,000
Dominion Energy Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit	1,500,000,000	[3]			$ 1,500,000,000
Six Billion Joint Revolving Credit Facility
Line of Credit Facility [Line Items]
Facility Limit	6,000,000,000			$ 6,000,000,000
Six Billion Joint Revolving Credit Facility | Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Facility Limit	1,500,000,000
Credit Facility One Point Five Billion [Member] | Dominion Energy Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit	$ 1,500,000,000
Commercial Paper | 5 Billion, 500 Million And 6 Billion joint Revolving Credit Facilities [Member]
Line of Credit Facility [Line Items]
Weighted-average percentage interest rates	2.93%				1.61%
Commercial Paper | 5 Billion, 500 Million And 6 Billion joint Revolving Credit Facilities [Member] | Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Weighted-average percentage interest rates	2.94%				1.65%
Commercial Paper | 1 Billion, 500 Million And 1.5 Billion Joint Revolving Credit Facilities [Member] | Dominion Energy Gas Holdings, LLC
Line of Credit Facility [Line Items]
Weighted-average percentage interest rates	2.58%				1.57%
Letter of Credit | Dominion Energy Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit	$ 1,500,000,000		$ 21,000,000
Letter of Credit | Joint Revolving Credit Facility 5 Billion and Joint Revolving Credit Facility 500 Million
Line of Credit Facility [Line Items]
Facility Limit	2,000,000,000
Letter of Credit | Joint Revolving Credit Facility 5 Billion and Joint Revolving Credit Facility 500 Million | Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Facility Limit	2,000,000,000
Letter of Credit | Six Billion Joint Revolving Credit Facility
Line of Credit Facility [Line Items]
Facility Limit	2,000,000,000
Letter of Credit | Six Billion Joint Revolving Credit Facility | Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Facility Limit	2,000,000,000
Line of Credit | Credit Facility One Point Five Billion [Member] | Dominion Energy Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit	$ 750,000,000

[1] This credit facility matures in March 2023 and can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

[2] The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Virginia Power was $1.5 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

[3] A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. The sub-limit for Dominion Energy Gas is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Dominion Energy Gas was $750 million. If Dominion Energy 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

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Long-Term Debt (Total Long Term Debt) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Securities due within one year	[1],[2]	$ (3,624)	$ (3,078)
Unamortized discount and debt issuance costs		(248)	(245)
Dominion Energy, Inc. total principal		35,109	34,293
Fair value hedge valuation	[3]	(20)	(22)
Credit facility borrowings	[4]	(73)
Dominion Energy, Inc. total long-term debt		$ 31,144	30,948
Capital leases, 4.14% to 6.04%, due 2019 to 2029
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5]	5.99%
Capital leases, 4.14% to 6.04%, due 2019 to 2029		$ 39
Long Term Debt Due Within One Year [Member]
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[1],[2],[5]	3.23%
Credit facility borrowings
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[4],[5]	3.55%
Senior Notes | Variable rates, due 2019 and 2020
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5],[6]	3.23%
Total principal	[6]	$ 800	800
Senior Notes | 1.5% to 6.4%, due 2018 to 2022
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5],[6]	2.75%
Total principal	[6]	$ 2,550	5,800
Senior Notes | 2.85% to 7.0%, due 2024 to 2044
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5],[6]	4.81%
Total principal	[6]	$ 4,849	5,049
Senior Notes | 6.8% and 6.875%, due 2026 and 2027
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5],[7]	6.81%
Total principal	[7]	$ 89	89
Senior Notes | 5.31% to 6.3%, due 2018
Debt Instrument [Line Items]
Total principal	[8]		120
Senior Notes | 2.98% to 7.20%, due 2024 to 2051
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5],[8]	4.25%
Total principal	[8]	$ 750	600
Senior Notes | 4.82%, due 2042
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5],[9]	4.82%
Total principal	[9]	$ 362
Unsecured Junior Subordinated Notes
Debt Instrument [Line Items]
Dominion Energy, Inc. total principal		$ 2,100
Unsecured Junior Subordinated Notes | 2.579% to 4.104%, due 2019 to 2021
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5]	3.08%
Total principal		$ 2,100	2,100
Unsecured Junior Subordinated Notes | 8.4% due 2031
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5]	8.40%
Total principal		$ 10	10
Unsecured Junior Subordinated Notes | 5.25% and 5.75%, due 2054 and 2076
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5]	5.48%
Total principal		$ 1,485	1,485
Unsecured Junior Subordinated Notes | Variable rates, due 2066
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5]	5.26%
Total principal		$ 422	422
Remarketable Subordinated Notes
Debt Instrument [Line Items]
Dominion Energy, Inc. total principal		$ 1,400
Remarketable Subordinated Notes | 2.0%, due 2021 and 2024
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5]	2.00%
Total principal		$ 1,400	1,400
Term Loans
Debt Instrument [Line Items]
Dominion Energy, Inc. total principal	[4],[10]	$ 3,882
Term Loans | Term Loans, variable rates, due 2023 and 2024
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5],[11]	4.85%
Total principal	[11]	$ 582	638
Term Loans | Tax-Exempt Financing, 1.55%, due 2033
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5],[12]	1.55%
Total principal	[12]	$ 27	27
Dominion Energy Gas Holdings, LLC
Debt Instrument [Line Items]
Total principal		4,087	3,600
Securities due within one year		(449)
Unamortized discount and debt issuance costs		(29)	(30)
Total long term debt		3,609	3,570
Dominion Energy, Inc. total principal		$ 4,087
Dominion Energy Gas Holdings, LLC | Long Term Debt Due Within One Year [Member]
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5]	2.50%
Dominion Energy Gas Holdings, LLC | Senior Notes | Unsecured Senior Notes Variable rate, due 2021 [Member]
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5]	3.39%
Total principal		$ 500
Dominion Energy Gas Holdings, LLC | Senior Notes | 2.5% to 3.55%, due 2019 to 2023
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5]	2.90%
Total principal		$ 1,800	1,800
Dominion Energy Gas Holdings, LLC | Senior Notes | 3.317% to 4.8%, due 2024 to 2044
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5],[13]	4.12%
Total principal	[13]	$ 1,787	1,800
Virginia Electric and Power Company
Debt Instrument [Line Items]
Total principal		11,754	11,418
Securities due within one year		(350)	(850)
Unamortized discount and debt issuance costs		(83)	(72)
Total long term debt		11,321	10,496
Dominion Energy, Inc. total principal		$ 11,754
Virginia Electric and Power Company | Long Term Debt Due Within One Year [Member]
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5]	5.00%
Virginia Electric and Power Company | Senior Notes | 1.2% to 5.4%, due 2018 to 2023
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5]	3.35%
Total principal		$ 1,800	2,650
Virginia Electric and Power Company | Senior Notes | 2.95% to 8.875%, due 2024 to 2048
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5]	4.61%
Total principal		$ 9,290	7,990
Virginia Electric and Power Company | Tax Exempt Financing | Utility Tax Exempt Loan Variable Rate Due 2024 To 2027 [Member]
Debt Instrument [Line Items]
Total principal	[14]		100
Virginia Electric and Power Company | Tax Exempt Financing | 1.75% to 5.6%, due 2023 to 2041
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5],[14]	2.18%
Total principal	[14]	$ 664	678
Dominion Energy Midstream Partners, LP | Senior Notes | Unsecured Senior and Medium Term Notes, 5.83% and 6.48%, due 2018
Debt Instrument [Line Items]
Total principal	[15]		255
Dominion Energy Midstream Partners, LP | Senior Notes | Unsecured Senior Notes, 3.53% to 4.875%, due 2028 to 2041
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[5],[15]	4.23%
Total principal	[15]	$ 430	180
Dominion Energy Midstream Partners, LP | Term Loans | Term Loan Variable Rate Due 2019 and 2021
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[4],[5],[16]	4.13%
Total principal	[4],[16]	$ 3,300	$ 300
Dominion Energy Midstream Partners, LP | Term Loans | Revolving Credit Agreement Variable Rates Due 2021
Debt Instrument [Line Items]
2018 Weighted- average Coupon (percentage)	[4],[5]	3.55%
Total principal	[4]	$ 73

[1] 2017 excludes $250 million of Dominion Energy Questar Pipeline's senior notes that matured in February 2018 using proceeds from the January 2018 issuance, through private placements, of $100 million and $150 million of senior notes that mature in 2028 and 2038, respectively.

[2] Includes $20 million of estimated mandatory prepayments due within one year based on estimated cash flows in excess of debt service at SBL Holdco and Dominion Solar Projects III, Inc.

[3] Represents the valuation of certain fair value hedges associated with Dominion Energy's fixed rate debt.

[4] In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy's Consolidated Balance Sheets at December 31, 2018.

[5] Represents weighted-average coupon rates for debt outstanding as of December 31, 2018.

[6] In November and December 2018, Dominion Energy redeemed certain senior notes prior to their stated maturity. See below for a discussion of the senior note redemptions.

[7] Represents debt assumed by Dominion Energy from the merger of its former CNG subsidiary.

[8] Represents debt obligations of Questar Gas. See Note 3 for more information.

[9] Represents debt obligations of Eagle Solar. The debt is nonrecourse to Dominion Energy and is secured by Eagle Solar's interest in certain merchant solar facilities.

[10] Excludes mandatory prepayments associated with SBL Holdco and Dominion Solar Projects III, Inc. based on cash flows in excess of debt service. At December 31, 2018, $20 million of estimated mandatory prepayments due within one year were included in securities due within one year in Dominion Energy's Consolidated Balance Sheets.

[11] Represents debt associated with SBL Holdco and Dominion Solar Projects III, Inc. The debt is nonrecourse to Dominion Energy and is secured by SBL Holdco and Dominion Solar Projects III, Inc.'s interest in certain merchant solar facilities.

[12] Represents debt obligations of a DGI subsidiary.

[13] Amount includes foreign currency remeasurement adjustments.

[14] These financings relate to certain pollution control equipment at Virginia Power's generating facilities. In March 2018, Virginia Power redeemed certain variable rate tax-exempt financings supported by its $100 million credit facility and terminated the facility. In December 2018, Virginia Power redeemed its $14 million Economic Development Authority of the County of Chesterfield Solid Waste and Sewage Disposal Revenue Bonds due in 2031.

[15] Represents debt obligations of Dominion Energy Questar Pipeline. See Note 3 for more information.

[16] Includes debt obligations of Cove Point that are secured by Dominion Energy's common equity interest in Cove Point.

XML

Long-Term Debt (Total Long Term Debt) (Parenthetical) (Detail) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Feb. 28, 2019	Feb. 28, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Repayment of Debt			$ 5,682	$ 1,572	$ 1,610
Term Loans
Debt Instrument [Line Items]
Estimated mandatory prepayments due within one year			20
Dominion Energy Gas Holdings, LLC
Debt Instrument [Line Items]
Repayment of Debt					400
Virginia Electric and Power Company
Debt Instrument [Line Items]
Repayment of Debt			$ 964	$ 681	$ 517
Dominion Energy Midstream Partners, LP
Debt Instrument [Line Items]
Repayment of Debt		$ 250
Dominion Energy Midstream Partners, LP | Subsequent Event
Debt Instrument [Line Items]
Repayment of outstanding credit facility balance	$ 73
2.5% to 3.55%, due 2019 to 2023 | Dominion Energy Gas Holdings, LLC | Senior Notes | Minimum
Debt Instrument [Line Items]
Interest rate			2.50%
2.5% to 3.55%, due 2019 to 2023 | Dominion Energy Gas Holdings, LLC | Senior Notes | Maximum
Debt Instrument [Line Items]
Interest rate			3.55%
3.317% to 4.8%, due 2024 to 2044 | Dominion Energy Gas Holdings, LLC | Senior Notes | Minimum
Debt Instrument [Line Items]
Interest rate			3.317%
3.317% to 4.8%, due 2024 to 2044 | Dominion Energy Gas Holdings, LLC | Senior Notes | Maximum
Debt Instrument [Line Items]
Interest rate			4.80%
1.2% to 5.4%, due 2018 to 2023 | Virginia Electric and Power Company | Senior Notes | Minimum
Debt Instrument [Line Items]
Interest rate			1.20%
1.2% to 5.4%, due 2018 to 2023 | Virginia Electric and Power Company | Senior Notes | Maximum
Debt Instrument [Line Items]
Interest rate			5.40%
2.95% to 8.875%, due 2024 to 2048 | Virginia Electric and Power Company | Senior Notes | Minimum
Debt Instrument [Line Items]
Interest rate			2.95%
2.95% to 8.875%, due 2024 to 2048 | Virginia Electric and Power Company | Senior Notes | Maximum
Debt Instrument [Line Items]
Interest rate			8.875%
1.75% to 5.6%, due 2023 to 2041 | Virginia Electric and Power Company | Tax Exempt Financing | Minimum
Debt Instrument [Line Items]
Interest rate			1.75%
1.75% to 5.6%, due 2023 to 2041 | Virginia Electric and Power Company | Tax Exempt Financing | Maximum
Debt Instrument [Line Items]
Interest rate			5.60%
1.5% to 6.4%, due 2018 to 2022 | Senior Notes | Minimum
Debt Instrument [Line Items]
Interest rate			1.50%
1.5% to 6.4%, due 2018 to 2022 | Senior Notes | Maximum
Debt Instrument [Line Items]
Interest rate			6.40%
2.85% to 7.0%, due 2024 to 2044 | Senior Notes | Minimum
Debt Instrument [Line Items]
Interest rate			2.85%
2.85% to 7.0%, due 2024 to 2044 | Senior Notes | Maximum
Debt Instrument [Line Items]
Interest rate			7.00%
2.579% to 4.104%, due 2019 to 2021 | Unsecured Junior Subordinated Notes | Minimum
Debt Instrument [Line Items]
Interest rate			2.579%
2.579% to 4.104%, due 2019 to 2021 | Unsecured Junior Subordinated Notes | Maximum
Debt Instrument [Line Items]
Interest rate			4.104%
8.4% due 2031 | Unsecured Junior Subordinated Notes
Debt Instrument [Line Items]
Interest rate			8.40%
5.25% and 5.75%, due 2054 and 2076 | Unsecured Junior Subordinated Notes | Minimum
Debt Instrument [Line Items]
Interest rate			5.25%
5.25% and 5.75%, due 2054 and 2076 | Unsecured Junior Subordinated Notes | Maximum
Debt Instrument [Line Items]
Interest rate			5.75%
2.0%, due 2021 and 2024 | Remarketable Subordinated Notes
Debt Instrument [Line Items]
Interest rate			2.00%
6.8% and 6.875%, due 2026 and 2027 | Senior Notes | Minimum
Debt Instrument [Line Items]
Interest rate			6.80%
6.8% and 6.875%, due 2026 and 2027 | Senior Notes | Maximum
Debt Instrument [Line Items]
Interest rate			6.875%
5.31% to 6.3%, due 2018 | Senior Notes | Minimum
Debt Instrument [Line Items]
Interest rate			5.31%
5.31% to 6.3%, due 2018 | Senior Notes | Maximum
Debt Instrument [Line Items]
Interest rate			6.30%
2.98% to 7.20%, due 2024 to 2051 | Senior Notes | Minimum
Debt Instrument [Line Items]
Interest rate			2.98%
2.98% to 7.20%, due 2024 to 2051 | Senior Notes | Maximum
Debt Instrument [Line Items]
Interest rate			7.20%
4.82%, due 2042 | Senior Notes
Debt Instrument [Line Items]
Interest rate			4.82%
Tax-Exempt Financing, 1.55%, due 2033 | Term Loans
Debt Instrument [Line Items]
Interest rate			1.55%
Capital leases, 4.14% to 6.04%, due 2019 to 2029 | Minimum
Debt Instrument [Line Items]
Interest rate			4.14%
Capital leases, 4.14% to 6.04%, due 2019 to 2029 | Maximum
Debt Instrument [Line Items]
Interest rate			6.04%
Unsecured Senior and Medium Term Notes, 5.83% and 6.48%, due 2018 | Dominion Energy Midstream Partners, LP | Senior Notes | Minimum
Debt Instrument [Line Items]
Interest rate			5.83%
Unsecured Senior and Medium Term Notes, 5.83% and 6.48%, due 2018 | Dominion Energy Midstream Partners, LP | Senior Notes | Maximum
Debt Instrument [Line Items]
Interest rate			6.48%
Unsecured Senior Notes, 3.53% to 4.875%, due 2028 to 2041 | Dominion Energy Midstream Partners, LP | Senior Notes | Minimum
Debt Instrument [Line Items]
Interest rate			3.53%
Unsecured Senior Notes, 3.53% to 4.875%, due 2028 to 2041 | Dominion Energy Midstream Partners, LP | Senior Notes | Maximum
Debt Instrument [Line Items]
Interest rate			4.875%
3.53% Due 2028 | Dominion Energy Midstream Partners, LP | Private Placement
Debt Instrument [Line Items]
Repayment of Debt		100
3.91% Due 2038 | Dominion Energy Midstream Partners, LP | Private Placement
Debt Instrument [Line Items]
Repayment of Debt		$ 150
Variable Rate Term Loan | Dominion Energy Midstream Partners, LP | Subsequent Event
Debt Instrument [Line Items]
Repayment of Debt	$ 300
Economic Development Authority of the County of Chesterfield Solid Waste and Sewage Disposal Revenue Bonds due in 2031 | Virginia Electric and Power Company
Debt Instrument [Line Items]
Debt, amount redeemed			$ 14

XML

Long-Term Debt (Based on Stated Maturity Dates Rather than Early Redemption Dates that Could be Elected by Instrument Holders) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
2019		$ 3,607
2020		2,054
2021		5,279
2022		1,556
2023		1,682
Thereafter		20,931
Total		$ 35,109	$ 34,293
Weighted- average Coupon, 2019		3.23%
Weighted- average Coupon, 2020		2.80%
Weighted- average Coupon, 2021		3.64%
Weighted- average Coupon, 2022		3.02%
Weighted- average Coupon, 2023		3.41%
Weighted- average Coupon, Thereafter		4.51%
Unsecured Senior Notes
Debt Instrument [Line Items]
2019		$ 2,700
2020		1,000
2021		900
2022		1,500
2023		1,350
Thereafter		17,195
Total		24,645
Tax-Exempt Financings
Debt Instrument [Line Items]
2023		40
Thereafter		651
Total		691
Term Loans
Debt Instrument [Line Items]
2019	[1],[2]	336
2020	[1],[2]	35
2021	[1],[2]	3,035
2022	[1],[2]	34
2023	[1],[2]	273
Thereafter	[1],[2]	169
Total	[1],[2]	3,882
Credit facility borrowings
Debt Instrument [Line Items]
2021	[2]	73
Total	[2]	73
Secured Senior Notes
Debt Instrument [Line Items]
2019		17
2020		15
2021		17
2022		19
2023		16
Thereafter		278
Total		362
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts
Debt Instrument [Line Items]
Thereafter		10
Total		10
Unsecured Junior Subordinated Notes
Debt Instrument [Line Items]
2019		550
2020		1,000
2021		550
Total		2,100
Enhanced Junior Subordinated Notes
Debt Instrument [Line Items]
Thereafter		1,907
Total		1,907
Remarketable Subordinated Notes
Debt Instrument [Line Items]
2021		700
Thereafter		700
Total		1,400
Capital Lease Obligations [Member]
Debt Instrument [Line Items]
2019		4
2020		4
2021		4
2022		3
2023		3
Thereafter		21
Total		39
Dominion Energy Gas Holdings, LLC
Debt Instrument [Line Items]
2019		450
2020		700
2021		500
2023		650
Thereafter		1,787
Total		$ 4,087
Weighted- average Coupon, 2019		2.50%
Weighted- average Coupon, 2020		2.80%
Weighted- average Coupon, 2021		3.39%
Weighted- average Coupon, 2023		3.29%
Weighted- average Coupon, Thereafter		4.12%
Virginia Electric and Power Company
Debt Instrument [Line Items]
2019		$ 350
2022		750
2023		740
Thereafter		9,914
Total		$ 11,754
Weighted- average Coupon, 2019		5.00%
Weighted- average Coupon, 2022		3.15%
Weighted- average Coupon, 2023		2.87%
Weighted- average Coupon, Thereafter		4.45%
Virginia Electric and Power Company | Unsecured Senior Notes
Debt Instrument [Line Items]
2019		$ 350
2022		750
2023		700
Thereafter		9,290
Total		11,090
Virginia Electric and Power Company | Tax-Exempt Financings
Debt Instrument [Line Items]
2023		40
Thereafter		624
Total		$ 664

[1] Excludes mandatory prepayments associated with SBL Holdco and Dominion Solar Projects III, Inc. based on cash flows in excess of debt service. At December 31, 2018, $20 million of estimated mandatory prepayments due within one year were included in securities due within one year in Dominion Energy's Consolidated Balance Sheets.

[2] In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy's Consolidated Balance Sheets at December 31, 2018.

XML

Long-Term Debt (Based on Stated Maturity Dates Rather than Early Redemption Dates that Could be Elected by Instrument Holders) (Parenthetical) (Detail) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Feb. 28, 2019	Feb. 28, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Repayment of Debt			$ 5,682	$ 1,572	$ 1,610
Term Loans
Debt Instrument [Line Items]
Estimated mandatory prepayments due within one year			$ 20
Dominion Energy Midstream Partners, LP
Debt Instrument [Line Items]
Repayment of Debt		$ 250
Dominion Energy Midstream Partners, LP | Subsequent Event
Debt Instrument [Line Items]
Repayment of outstanding credit facility balance	$ 73
Variable Rate Term Loan | Dominion Energy Midstream Partners, LP | Subsequent Event
Debt Instrument [Line Items]
Repayment of Debt	$ 300

XML

Long-Term Debt (Narrative) (Detail) - USD ($)				1 Months Ended								12 Months Ended
	Oct. 01, 2024	Aug. 15, 2016		Aug. 31, 2019	Jul. 31, 2017	Jul. 31, 2016	Apr. 30, 2016	Oct. 31, 2014	Sep. 30, 2011	Sep. 30, 2006	Jun. 30, 2006	Dec. 31, 2018	May 31, 2017	Aug. 31, 2016	Jun. 29, 2016	May 31, 2016	Mar. 31, 2016	Jul. 31, 2014	Jun. 30, 2013
Debt Instrument [Line Items]
Aggregate outstanding principal of senior notes												$ 2,200,000,000
Aggregate redemption price paid												2,200,000,000
Make-whole premium												$ 34,000,000
Period of deferral								10 years
Period for consideration of proceeds (days)									180 days			365 days
Interest in RSN issued by Dominion (percentage)												5.00%
Common Stock
Debt Instrument [Line Items]
Purchase price to be paid under stock purchase contracts (in dollars per unit)												$ 50
Shares reserved and available for issuance												23,100,000
Capital Unit, Class A
Debt Instrument [Line Items]
Principal amount of notes														$ 1,400,000,000
Payment percentage rate on Equity Units														6.75%				6.375%	6.125%
Purchase price to be paid under stock purchase contracts (in dollars per unit)												$ 50
Issuance of common stock (in shares)		28,000,000	[1]		12,500,000
Capital Unit, Class B
Debt Instrument [Line Items]
Payment percentage rate on Equity Units																			6.00%
Scenario, Forecast | Maximum
Debt Instrument [Line Items]
Shares to be issued under purchase contracts				18,900,000
Scenario, Forecast | Minimum
Debt Instrument [Line Items]
Shares to be issued under purchase contracts				15,100,000
Senior Note Redemptions [Member]
Debt Instrument [Line Items]
Interest expense												$ 69,000,000
Senior Note Redemptions [Member] | Series A 4.45% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Interest rate (percentage)												4.45%
Senior Note Redemptions [Member] | Series B 2.50% Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Interest rate (percentage)												2.50%
Senior Note Redemptions [Member] | Series C 3.625% Senior Notes Due 2024 [Member]
Debt Instrument [Line Items]
Interest rate (percentage)												3.625%
June 2006 and September 2006 hybrids | Unsecured Junior Subordinated Notes | Maximum
Debt Instrument [Line Items]
Amount purchased and cancelled						$ 200,000,000
July 2016 Hybrids | Unsecured Junior Subordinated Notes
Debt Instrument [Line Items]
Interest rate (percentage)						5.25%
Principal amount of notes						$ 800,000,000
Remarketable Subordinated Notes | Capital Unit, Class A
Debt Instrument [Line Items]
Interest rate (percentage)		2.00%	[1],[2]										1.50%				1.07%
Principal amount of notes		$ 1,400,000,000	[1]										$ 1,000,000,000				$ 550,000,000	$ 1,000,000,000	$ 550,000,000
Issuance of common stock (in shares)					12,500,000	8,500,000	8,500,000
Remarketable Subordinated Notes | Capital Unit, Class B
Debt Instrument [Line Items]
Interest rate (percentage)																1.18%
Principal amount of notes																$ 550,000,000			$ 550,000,000
Series A Junior Subordinated Notes | Unsecured Junior Subordinated Notes
Debt Instrument [Line Items]
Interest rate (percentage)													2.579%				4.104%
Series B Junior Subordinated Notes | Unsecured Junior Subordinated Notes
Debt Instrument [Line Items]
Interest rate (percentage)																2.962%
Remarketable Subordinated Notes, 2016 Series A-1, due August 15, 2021
Debt Instrument [Line Items]
Interest in RSN issued by Dominion (percentage)												2.50%
Remarketable Subordinated Notes, 2016 Series A-1, due August 15, 2021 | Capital Unit, Class A
Debt Instrument [Line Items]
Principal amount of notes		700,000,000
Remarketable Subordinated Notes, 2016 Series A-2, due August 15, 2024
Debt Instrument [Line Items]
Interest in RSN issued by Dominion (percentage)												2.50%
Remarketable Subordinated Notes, 2016 Series A-2, due August 15, 2024 | Capital Unit, Class A
Debt Instrument [Line Items]
Principal amount of notes		$ 700,000,000
June 2006 hybrids
Debt Instrument [Line Items]
Aggregate redemption price paid																	$ 38,000,000
Interest rate (percentage)															7.50%
Junior subordinated notes											$ 300,000,000
June 2006 hybrids | Unsecured Junior Subordinated Notes
Debt Instrument [Line Items]
Amount purchased and cancelled						$ 125,000,000
June 2006 hybrids | LIBOR [Member]
Debt Instrument [Line Items]
Spread on variable percentage rate											2.825%
September 2006 hybrids
Debt Instrument [Line Items]
Aggregate redemption price paid																	$ 4,000,000
Junior subordinated notes										$ 500,000,000
September 2006 hybrids | Unsecured Junior Subordinated Notes
Debt Instrument [Line Items]
Amount purchased and cancelled						$ 74,000,000
September 2006 hybrids | LIBOR [Member]
Debt Instrument [Line Items]
Spread on variable percentage rate										2.30%
October 2014 Hybrids [Member] | Unsecured Junior Subordinated Notes
Debt Instrument [Line Items]
Interest rate (percentage)								5.75%
Principal amount of notes								$ 685,000,000
October 2014 Hybrids [Member] | LIBOR [Member] | Unsecured Junior Subordinated Notes | Scenario, Forecast
Debt Instrument [Line Items]
Spread on variable percentage rate	3.057%

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

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

XML

Long-Term Debt Long Term Debt (Schedule of Equity Units) (Detail) - USD ($) shares in Millions				1 Months Ended
		Aug. 15, 2016		Jul. 31, 2017	Jul. 31, 2016	Apr. 30, 2016	Dec. 31, 2018	Dec. 31, 2017	May 31, 2017	Aug. 31, 2016	Mar. 31, 2016	Jul. 31, 2014	Jun. 30, 2013
Capital Unit [Line Items]
Stock Purchase Contract Liability							$ 47,000,000	$ 111,000,000
Capital Unit, Class A
Capital Unit [Line Items]
Units Issued		28.0	[1]	12.5
Total Net Proceeds	[1]	$ 1,374,800,000
Total Long-term Debt										$ 1,400,000,000
Stock Purchase Contract Annual Rate (Percentage)	[1]	4.75%
Stock Purchase Contract Liability	[1],[2]	$ 190,600,000
Stock Purchase Settlement Date	[1]	Aug. 15, 2019
Capital Unit, Class A | Remarketable Subordinated Notes
Capital Unit [Line Items]
Units Issued				12.5	8.5	8.5
Total Long-term Debt		$ 1,400,000,000	[1]						$ 1,000,000,000		$ 550,000,000	$ 1,000,000,000	$ 550,000,000
RSN Annual Interest Rate		2.00%	[1],[3]						1.50%		1.07%

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

[2] Payments of $64 million and $101 million were made in 2018 and 2017, respectively, including payments for the remarketed 2014 Series A notes. The stock purchase contract liability was $47 million and $111 million at December 31, 2018 and 2017, respectively.

[3] Annual interest rate applies to each of the Series A-1 RSNs and Series A-2 RSNs.

XML

Long-Term Debt Long Term Debt (Schedule of Equity Units) (Parenthetical) (Detail) - USD ($)		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Aug. 31, 2016	Aug. 15, 2016
Capital Unit [Line Items]
Stock Purchase Contract Liability		$ 47,000,000	$ 111,000,000
Total payments		$ 64,000,000	$ 101,000,000
Capital Unit, Class A
Capital Unit [Line Items]
Stock Purchase Contract Liability	[1],[2]				$ 190,600,000
Total Long-term Debt				$ 1,400,000,000
Capital Unit, Class A | Remarketable Subordinated Notes, 2016 Series A-1, due August 15, 2021
Capital Unit [Line Items]
Total Long-term Debt					700,000,000
Capital Unit, Class A | Remarketable Subordinated Notes, 2016 Series A-2, due August 15, 2024
Capital Unit [Line Items]
Total Long-term Debt					$ 700,000,000

[1] Payments of $64 million and $101 million were made in 2018 and 2017, respectively, including payments for the remarketed 2014 Series A notes. The stock purchase contract liability was $47 million and $111 million at December 31, 2018 and 2017, respectively.

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

XML

Preferred Stock (Narrative) (Detail) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Preferred stock shares authorized	20,000,000	20,000,000
Preferred stock shares issued	0	0
Preferred stock shares outstanding	0	0
Virginia Electric and Power Company
Class of Stock [Line Items]
Preferred stock shares authorized	10,000,000	10,000,000
Preferred stock shares issued	0	0
Preferred stock shares outstanding	0	0
Liquidation preference (in dollars per share)	$ 100

XML

Equity (Narrative) (Detail)			1 Months Ended											2 Months Ended	3 Months Ended	12 Months Ended
	Aug. 15, 2016 shares	[1]	Jan. 31, 2019 USD ($) shares	Dec. 31, 2018 USD ($) shares	Jun. 30, 2018 USD ($) shares	May 31, 2018	Apr. 30, 2018 shares	Feb. 28, 2018 USD ($) Agreement	Jan. 31, 2018 USD ($) Performance_Factor shares	Jul. 31, 2017 USD ($) shares	Jun. 30, 2017 USD ($) Agreement	Jul. 31, 2016 shares	Apr. 30, 2016 USD ($) shares	Apr. 30, 2018 shares	Dec. 31, 2018 USD ($) shares	Dec. 31, 2019 shares	Dec. 31, 2018 USD ($) Performance_Factor shares	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($) shares	Sep. 30, 2015 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Issuance of common stock																	$ 2,461,000,000	$ 1,302,000,000	$ 2,152,000,000
Common stock, shares outstanding | shares				681,000,000											681,000,000		681,000,000	645,000,000
Issuance of common stock (in shares)																	$ 2,461,000,000	$ 1,302,000,000	2,152,000,000
Net proceeds from issuance of Dominion Midstream common units																	$ 4,000,000	18,000,000	482,000,000
Net proceeds from issuance of Dominion Midstream convertible preferred units																			490,000,000
Conversion basis				1											1		1
Subordinated unit conversion						1
Number of shares received | shares					26,700,000
Increase (decrease) Non-controlling interest					$ 375,000,000
Compensation cost related to stock-based compensation																	$ 48,000,000	45,000,000	33,000,000
Tax benefit from stock awards and stock options exercised																	$ 12,000,000	16,000,000	11,000,000
Vesting period																	3 years
Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of common stock issued in acquisition | shares			22,500,000
Shares of common stock issued in acquisition, value			$ 1,600,000,000
Cash Based Performance Grant | Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash-based performance grants minimum percentage																	0.00%
Cash-based performance grants maximum percentage																	200.00%
February 2016 Cash Based Performance Grant | Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of performance metrics achieved | Performance_Factor									2
Expected award under grant									$ 12,000,000
February 2017 Cash Based Performance Grant [Member] | Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of performance metrics achieved | Performance_Factor																	2
February 2017 Cash Based Performance Grant [Member] | Officer | Two-year grant
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Targeted amount of the grant				$ 13,000,000											$ 13,000,000		$ 13,000,000
Liability accrued for award				13,000,000											13,000,000		13,000,000
February 2017 Cash Based Performance Grant [Member] | Officer | Three-year grant
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Targeted amount of the grant				14,000,000											14,000,000		14,000,000
Liability accrued for award				10,000,000											10,000,000		$ 10,000,000
February 2018 Cash Based Performance Grant [Member] | Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of performance metrics achieved | Performance_Factor																	2
February 2018 Cash Based Performance Grant [Member] | Officer | Three-year grant
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Targeted amount of the grant				16,000,000											16,000,000		$ 16,000,000
Liability accrued for award				$ 5,000,000											$ 5,000,000		$ 5,000,000
Dominion Direct Employee Stock Awards Employee Savings Plans Director Stock Compensation Plans and Contingent Convertible Senior Notes
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares for future agreement | shares				76,000,000											76,000,000		76,000,000
Stock Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares were available for future grants | shares				22,000,000											22,000,000		22,000,000
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to nonvested awards				$ 49,000,000											$ 49,000,000		$ 49,000,000
Fair value of restricted stock awards that vested																	$ 23,000,000	$ 21,000,000	$ 21,000,000
Virginia Electric and Power Company
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Issuance of common stock (in shares | shares																	0	0	0
Common stock, shares outstanding | shares				274,723											274,723		274,723	274,723
Repurchase of common stock, shares | shares																	0	0
Virginia Electric and Power Company | Scenario, Forecast
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Repurchase of common stock, shares | shares																0
Dominion Midstream Partners, LP | Limited Partner
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net proceeds from issuance of Dominion Midstream common units																		$ 18,000,000	$ 482,000,000
Dominion Midstream Partners, LP | Limited Partner | Convertible Preferred Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net proceeds from issuance of Dominion Midstream convertible preferred units																			$ 490,000,000
Dominion Midstream Partners, LP | Dominion Midstream Limited Partner Common Unit Purchase Program | Limited Partner
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Authorized purchase amount																				$ 50,000,000
Stock repurchase program expiration date																	Sep. 30, 2016
Number of common units purchased | shares																			658,000
Value of common units purchased																			$ 17,000,000
Maximum | Stock Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum term of stock based awards																	8 years
Weighted Average | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected weighted-average period recognized for the unrecognized compensation cost																	2 years 1 month 6 days
Noncontrolling Interests
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase (decrease) Non-controlling interest					$ (375,000,000)
Goldman Sachs & Co. and Credit Suisse LLC.
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Issuance of common stock				$ 1,400,000,000
Issuance of common stock (in shares | shares				22,100,000
Number of shares for future agreement | shares							20,000,000							20,000,000
Capital Unit, Class A
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Issuance of common stock										$ 1,000,000,000
Issuance of common stock (in shares | shares	28,000,000									12,500,000
Capital Unit, Class A | Remarketable Subordinated Notes
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Issuance of common stock																	$ 1,100,000,000
Issuance of common stock (in shares | shares										12,500,000		8,500,000	8,500,000
Underwritten Public Offering
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Issuance of common stock													$ 756,000,000
Issuance of common stock (in shares | shares													10,200,000
Various Programs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Issuance of common stock																	$ 2,500,000,000
Issuance of common stock (in shares | shares																	36,000,000
Common stock, shares outstanding | shares				681,000,000											681,000,000		681,000,000
Employee Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash proceeds received from issuance of shares through Dominion Direct and employee savings plans																	$ 315,000,000
Number of shares issued through Dominion Direct and employee savings plans | shares																	4,500,000
Shelf Registration for Sale of Common Stock through At-the-market Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Issuance of common stock									$ 495,000,000						$ 197,000,000
Issuance of common stock (in shares | shares									6,600,000						2,700,000
Number of sales agency agreements | Agreement								6			3
Issuance of common stock (in shares)											$ 0
Fees and commissions paid									$ 5,000,000						$ 2,000,000
Remaining ability to issue stock under the sales agency agreements				$ 801,000,000											$ 801,000,000		$ 801,000,000
Shelf Registration for Sale of Common Stock through At-the-market Program | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Sale of stock authorized amount								$ 1,000,000,000			$ 500,000,000
Underwriting Agreement | Goldman Sachs & Co. and Credit Suisse LLC.
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option exercised | shares							2,100,000
Underwriting Agreement | Goldman Sachs & Co. and Credit Suisse LLC. | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted for service | shares														3,000,000

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

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Equity (Accumulated Other Comprehensive Income (Loss)) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total AOCI, including noncontrolling interest	$ (1,699)	$ (658)
Less other comprehensive income attributable to noncontrolling interest	1	1
Total AOCI	(1,700)	(659)
Deferred Gains and Losses on Derivatives-Hedging Activities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total AOCI	(234)	(301)
Amount of tax	79	188
Unrealized Gains and Losses on Investment Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total AOCI	2	747
Amount of tax		(419)
Unrecognized Pension and Other Postretirement Benefit Costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total AOCI	(1,465)	(1,101)
Amount of tax	519	692
Other Comprehensive Loss From Equity Method Investee
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total AOCI	(2)	(3)
Amount of tax		2
Virginia Electric and Power Company
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total AOCI	(12)	62
Virginia Electric and Power Company | Deferred Gains and Losses on Derivatives-Hedging Activities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total AOCI	(13)	(12)
Amount of tax	4	8
Virginia Electric and Power Company | Unrealized Gains and Losses on Investment Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total AOCI	1	74
Amount of tax		(47)
Dominion Energy Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total AOCI	(169)	(98)
Dominion Energy Gas Holdings, LLC | Deferred Gains and Losses on Derivatives-Hedging Activities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total AOCI	(25)	(23)
Amount of tax	8	15
Dominion Energy Gas Holdings, LLC | Unrecognized Pension and Other Postretirement Benefit Costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total AOCI	(144)	(75)
Amount of tax	$ 56	$ 59

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Equity (Schedule of Changes in AOCI by Component Net of Tax) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		$ 17,142
Ending balance		20,107	$ 17,142
Virginia Electric and Power Company
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		12,224
Ending balance		13,047	12,224
Deferred Gains and Losses on Derivatives-Hedging Activities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(302)	(280)
Other comprehensive income before reclassifications: gains (losses)		30	8
Amounts reclassified from AOCI: (gains) losses	[1]	102	(29)
Net current period other comprehensive income (loss)		132	(21)
Cumulative-effect of changes in accounting principle		(64)
Less other comprehensive income (loss) attributable to noncontrolling interest		1	1
Ending balance		(235)	(302)
Deferred Gains and Losses on Derivatives-Hedging Activities | Virginia Electric and Power Company
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(12)	(8)
Other comprehensive income before reclassifications: gains (losses)		1	(5)
Amounts reclassified from AOCI: (gains) losses	[1]	1	1
Net current period other comprehensive income (loss)		2	(4)
Cumulative-effect of changes in accounting principle		(3)
Ending balance		(13)	(12)
Deferred Gains and Losses on Derivatives-Hedging Activities | Dominion Energy Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(23)	(24)
Other comprehensive income before reclassifications: gains (losses)		(17)	5
Amounts reclassified from AOCI: (gains) losses	[1]	20	(4)
Net current period other comprehensive income (loss)		3	1
Cumulative-effect of changes in accounting principle		(5)
Ending balance		(25)	(23)
Unrealized Gains and Losses on Investment Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		747	569
Other comprehensive income before reclassifications: gains (losses)		(18)	215
Amounts reclassified from AOCI: (gains) losses	[1]	5	(37)
Net current period other comprehensive income (loss)		(13)	178
Cumulative-effect of changes in accounting principle		(732)
Ending balance		2	747
Unrealized Gains and Losses on Investment Securities | Virginia Electric and Power Company
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		74	54
Other comprehensive income before reclassifications: gains (losses)			24
Amounts reclassified from AOCI: (gains) losses	[1]		(4)
Net current period other comprehensive income (loss)			20
Cumulative-effect of changes in accounting principle		(73)
Ending balance		1	74
Unrecognized Pension and Other Postretirement Benefit Costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(1,101)	(1,082)
Other comprehensive income before reclassifications: gains (losses)		(215)	(69)
Amounts reclassified from AOCI: (gains) losses	[1]	78	50
Net current period other comprehensive income (loss)		(137)	(19)
Cumulative-effect of changes in accounting principle		(227)
Ending balance		(1,465)	(1,101)
Unrecognized Pension and Other Postretirement Benefit Costs | Dominion Energy Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(75)	(99)
Other comprehensive income before reclassifications: gains (losses)		(52)	20
Amounts reclassified from AOCI: (gains) losses	[1]	4	4
Net current period other comprehensive income (loss)		(48)	24
Cumulative-effect of changes in accounting principle		(21)
Ending balance		(144)	(75)
Other Comprehensive Loss From Equity Method Investee
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(3)	(6)
Other comprehensive income before reclassifications: gains (losses)		1	3
Net current period other comprehensive income (loss)		1	3
Ending balance		(2)	(3)
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(659)	(799)
Other comprehensive income before reclassifications: gains (losses)		(202)	157
Amounts reclassified from AOCI: (gains) losses	[1]	185	(16)
Net current period other comprehensive income (loss)		(17)	141
Cumulative-effect of changes in accounting principle		(1,023)
Less other comprehensive income (loss) attributable to noncontrolling interest		1	1
Ending balance		(1,700)	(659)
Accumulated Other Comprehensive Income (Loss) | Virginia Electric and Power Company
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		62	46
Other comprehensive income before reclassifications: gains (losses)		1	19
Amounts reclassified from AOCI: (gains) losses	[1]	1	(3)
Net current period other comprehensive income (loss)		2	16
Cumulative-effect of changes in accounting principle		(76)
Ending balance		(12)	62
Accumulated Other Comprehensive Income (Loss) | Dominion Energy Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(98)	(123)
Other comprehensive income before reclassifications: gains (losses)		(69)	25
Amounts reclassified from AOCI: (gains) losses	[1]	24
Net current period other comprehensive income (loss)		(45)	25
Cumulative-effect of changes in accounting principle		(26)
Ending balance		$ (169)	$ (98)

[1] See table below for details about these reclassifications.

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Equity (Schedule of Reclassifications out of AOCI by Component Net of Tax) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Electric fuel and other energy related purchases		$ (2,814)	$ (2,301)	$ (2,333)
Purchased gas		(645)	(701)	(459)
Interest and related charges		(1,493)	(1,205)	(1,010)
Other income	[1]	1,021	358	429
Income from operations before income tax expense		3,129	3,090	2,867
Income tax expense		(580)	30	(655)
Virginia Electric and Power Company
Accumulated Other Comprehensive Income (Loss) [Line Items]
Electric fuel and other energy related purchases	[2]	(2,318)	(1,909)	(1,973)
Interest and related charges	[2]	(511)	(494)	(461)
Other income		22	76	56
Income from operations before income tax expense		1,582	2,314	1,945
Income tax expense		(300)	(774)	(727)
Dominion Energy Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss) [Line Items]
Purchased gas	[3]	(40)	(132)	(109)
Interest and related charges	[3]	(105)	(97)	(94)
Other income		133	104	87
Income from operations before income tax expense		387	666	607
Income tax expense		(86)	(51)	$ (215)
Deferred (gains) and losses on derivatives-hedging activities: | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Income from operations before income tax expense		137	(47)
Income tax expense		(35)	18
Income from continuing operations including noncontrolling interests		102	(29)
Deferred (gains) and losses on derivatives-hedging activities: | Commodity | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating revenue		90	(81)
Electric fuel and other energy related purchases		(14)
Purchased gas			2
Deferred (gains) and losses on derivatives-hedging activities: | Interest rate | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Interest and related charges		48	52
Deferred (gains) and losses on derivatives-hedging activities: | Foreign currency | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other income		13	(20)
Deferred (gains) and losses on derivatives-hedging activities: | Virginia Electric and Power Company | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Income from operations before income tax expense		1	1
Income from continuing operations including noncontrolling interests		1	1
Deferred (gains) and losses on derivatives-hedging activities: | Virginia Electric and Power Company | Interest rate | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Interest and related charges		1	1
Deferred (gains) and losses on derivatives-hedging activities: | Dominion Energy Gas Holdings, LLC | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Income from operations before income tax expense		27	(7)
Income tax expense		(7)	3
Income from continuing operations including noncontrolling interests		20	(4)
Deferred (gains) and losses on derivatives-hedging activities: | Dominion Energy Gas Holdings, LLC | Commodity | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating revenue		8	8
Deferred (gains) and losses on derivatives-hedging activities: | Dominion Energy Gas Holdings, LLC | Interest rate | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Interest and related charges		6	5
Deferred (gains) and losses on derivatives-hedging activities: | Dominion Energy Gas Holdings, LLC | Foreign currency | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other income		13	(20)
Unrealized (gains) and losses on investment securities: | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Realized (gain) loss on sale of securities		7	(81)
Impairment			23
Income from operations before income tax expense		7	(58)
Income tax expense		(2)	21
Income from continuing operations including noncontrolling interests		5	(37)
Unrealized (gains) and losses on investment securities: | Virginia Electric and Power Company | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Realized (gain) loss on sale of securities			(9)
Impairment			2
Income from operations before income tax expense			(7)
Income tax expense			3
Income from continuing operations including noncontrolling interests			(4)
Unrecognized pension and other postretirement benefit costs: | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other income		(21)	(21)
Other income		120	103
Unrecognized pension and other postretirement benefit costs, before tax		99	82
Unrecognized pension and other postretirement benefit costs, income tax expense		(21)	(32)
Unrecognized pension and other postretirement benefit costs, net of tax		78	50
Unrecognized pension and other postretirement benefit costs: | Dominion Energy Gas Holdings, LLC | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other income		6	6
Unrecognized pension and other postretirement benefit costs, before tax		6	6
Unrecognized pension and other postretirement benefit costs, income tax expense		(2)	(2)
Unrecognized pension and other postretirement benefit costs, net of tax		$ 4	$ 4

[1] See Note 9 for amounts attributable to related parties.

[2] See Note 24 for amounts attributable to affiliates.

[3] See Note 24 for amounts attributable to related parties.

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Equity (Summary of Restricted Stock and Goal-Based Stock Activity) (Detail) - Restricted Stock - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Nonvested beginning (in shares)	1,043	886	855
Granted (in shares)	534	454	372
Vested (in shares)	(316)	(287)	(301)
Cancelled and forfeited (in shares)	(53)	(10)	(40)
Nonvested ending (in shares)	1,208	1,043	886
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Nonvested beginning, Weighted Average Grant Date Fair Value (in dollars per share)	$ 73.32	$ 71.40	$ 66.16
Granted, Weighted Average Grant Date Fair Value (in dollars per share)	72.92	74.24	71.67
Vested, Weighted Average Grant Date Fair Value (in dollars per share)	73.59	68.90	56.83
Cancelled and forfeited, Weighted Average Grant Date Fair Value (in dollars per share)	74.25	72.37	71.75
Nonvested ending, Weighted Average Grant Date Fair Value (in dollars per share)	$ 73.03	$ 73.32	$ 71.40

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Employee Benefit Plans (Narrative) (Detail) - USD ($)				3 Months Ended			12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Jan. 31, 2017	Dec. 31, 2017	Mar. 31, 2017	Sep. 30, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2019
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual return (loss) on plan assets							$ (605,000,000)	$ 1,600,000,000
Expected return on pension and other postretirement plan assets							806,000,000	767,000,000
Accumulated benefit obligation				$ 8,200,000,000			7,800,000,000	8,200,000,000
Contributions to qualified defined benefit pension plans							0
Contributions to qualified defined benefit pension plans in 2019							21,000,000
Contribution to voluntary employees beneficiary association							12,000,000	12,000,000
Defined contribution plan, employer matching contributions							$ 51,000,000	45,000,000	$ 44,000,000
Special Termination Benefits | Organizational Design Initiative
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Organizational design initiative									65,000,000
Organizational design initiative, after tax									40,000,000
Common and Preferred Stocks
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined benefit plan, actual plan asset allocation percentages							28.00%
Non-U.S.Equity
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined benefit plan, actual plan asset allocation percentages							18.00%
Fixed Income
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined benefit plan, actual plan asset allocation percentages							35.00%
Real Estate Funds
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined benefit plan, actual plan asset allocation percentages							3.00%
Other Alternative Investments
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined benefit plan, actual plan asset allocation percentages							16.00%
Scenario, Forecast
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension or other postretirement plan assets to be returned										$ 0
Pension Benefits
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual return (loss) on plan assets							$ (513,000,000)	1,327,000,000
Expected return on pension and other postretirement plan assets							663,000,000	639,000,000	573,000,000
Net periodic benefit cost							25,000,000	7,000,000	$ (25,000,000)
Decrease in accumulated postretirement benefit obligation				75,000,000
Discount rate percentage	4.05%	4.05%	4.51%						4.46%
Contributions to qualified defined benefit pension plans							6,000,000	118,000,000
Other Postretirement Benefits
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual return (loss) on plan assets							(92,000,000)	236,000,000
Expected return on pension and other postretirement plan assets							143,000,000	128,000,000	$ 118,000,000
Net periodic benefit cost							$ (101,000,000)	$ (80,000,000)	$ (49,000,000)
Decrease in accumulated postretirement benefit obligation				$ 2,000,000
Discount rate percentage							3.76%
Discount rate percentage				3.76%				3.76%
Contributions to qualified defined benefit pension plans							$ 12,000,000	$ 13,000,000
Medical Coverage for Local retirees
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Decrease in accumulated postretirement benefit obligation					$ 73,000,000	$ 37,000,000
Discount rate percentage					4.30%	3.71%
Charge recorded from plan amendment and remeasurement						$ 9,000,000
Collective Bargaining Agreement
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Period for experience study of employee demographics									5 years
Net periodic benefit cost								42,000,000
Charge recorded from plan amendment and remeasurement					$ 7,000,000
Charge recorded from plan amendment and remeasurement, after tax					4,000,000
Collective Bargaining Agreement | Pension Benefits
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Increase in the pension and postretirement benefit obligations									$ 290,000,000
Collective Bargaining Agreement | Other Postretirement Benefits
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Increase in the pension and postretirement benefit obligations									38,000,000
Dominion Energy Gas Holdings, LLC
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual return (loss) on plan assets							(129,000,000)	335,000,000
Expected return on pension and other postretirement plan assets							178,000,000	165,000,000
Accumulated benefit obligation				$ 724,000,000			689,000,000	724,000,000
Contributions to qualified defined benefit pension plans							0
Contributions to qualified defined benefit pension plans in 2019							0
Expected contribution to voluntary employees beneficiary association							12,000,000
Defined contribution plan, employer matching contributions							8,000,000	7,000,000	7,000,000
Dominion Energy Gas Holdings, LLC | Other operations and maintenance | Dominion Energy Retiree Health And Welfare Plan [Member] | Multiemployer Plans, Postretirement Benefit
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost							(7,000,000)	(5,000,000)	(4,000,000)
Dominion Energy Gas Holdings, LLC | Special Termination Benefits | Organizational Design Initiative
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Organizational design initiative									8,000,000
Organizational design initiative, after tax									5,000,000
Dominion Energy Gas Holdings, LLC | Scenario, Forecast
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension or other postretirement plan assets to be returned										$ 0
Dominion Energy Gas Holdings, LLC | Pension Benefits
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual return (loss) on plan assets							(113,000,000)	294,000,000
Expected return on pension and other postretirement plan assets							150,000,000	141,000,000	134,000,000
Net periodic benefit cost							$ (84,000,000)	$ (80,000,000)	$ (78,000,000)
Discount rate percentage							3.81%	4.50%	4.99%
Discount rate percentage				3.81%			4.42%	3.81%
Dominion Energy Gas Holdings, LLC | Pension Benefits | Other operations and maintenance
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost							$ (38,000,000)	$ (37,000,000)	$ (45,000,000)
Dominion Energy Gas Holdings, LLC | Other Postretirement Benefits
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual return (loss) on plan assets							(16,000,000)	41,000,000
Expected return on pension and other postretirement plan assets							28,000,000	24,000,000	23,000,000
Net periodic benefit cost							$ (14,000,000)	$ (9,000,000)	$ (2,000,000)
Discount rate percentage							3.81%	4.47%	4.93%
Discount rate percentage				3.76%			4.37%	3.76%
Contributions to qualified defined benefit pension plans							$ 12,000,000	$ 12,000,000
Dominion Energy Gas Holdings, LLC | Medical Coverage for Local retirees
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Decrease in accumulated postretirement benefit obligation					61,000,000
Dominion Energy Gas Holdings, LLC | Collective Bargaining Agreement
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Charge recorded from plan amendment and remeasurement					6,000,000
Charge recorded from plan amendment and remeasurement, after tax					$ 4,000,000
Dominion Energy Gas Holdings, LLC | Collective Bargaining Agreement | Pension Benefits
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Increase in the pension and postretirement benefit obligations									$ 24,000,000
Dominion Energy Gas Holdings, LLC | Collective Bargaining Agreement | Other Postretirement Benefits
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Increase in the pension and postretirement benefit obligations									9,000,000
Virginia Electric and Power Company
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined contribution plan, employer matching contributions							20,000,000	19,000,000	19,000,000
Virginia Electric and Power Company | Other operations and maintenance | Dominion Energy Retiree Health And Welfare Plan [Member] | Multiemployer Plans, Postretirement Benefit
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost							(51,000,000)	(42,000,000)	(29,000,000)
Virginia Electric and Power Company | Special Termination Benefits | Organizational Design Initiative
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Organizational design initiative									33,000,000
Organizational design initiative, after tax									20,000,000
Virginia Electric and Power Company | Pension Benefits | Other operations and maintenance
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit cost							$ 126,000,000	$ 110,000,000	$ 79,000,000

XML

Employee Benefit Plans (Summary of Changes in Pension and Other Postretirement Benefit Plans) (Detail) - USD ($)		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Changes in fair value of plan assets:
Actual return (loss) on plan assets		$ (605,000,000)	$ 1,600,000,000
Employer contributions		0
Dominion Energy Gas Holdings, LLC
Changes in fair value of plan assets:
Actual return (loss) on plan assets		(129,000,000)	335,000,000
Employer contributions		0
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at beginning of year		9,052,000,000	8,132,000,000
Service cost		157,000,000	138,000,000	$ 118,000,000
Interest cost		337,000,000	345,000,000	317,000,000
Benefits paid		(358,000,000)	(323,000,000)
Actuarial (gains) losses during the year		(688,000,000)	830,000,000
Plan amendments	[1]		5,000,000
Settlements and curtailments	[2]		(75,000,000)
Benefit obligation at end of year		8,500,000,000	9,052,000,000	8,132,000,000
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year		8,062,000,000	7,016,000,000
Actual return (loss) on plan assets		(513,000,000)	1,327,000,000
Employer contributions		6,000,000	118,000,000
Benefits paid		(358,000,000)	(323,000,000)
Settlements	[2]		(76,000,000)
Fair value of plan assets at end of year		7,197,000,000	8,062,000,000	7,016,000,000
Funded status at end of year		(1,303,000,000)	(990,000,000)
Noncurrent pension and other postretirement benefit assets		1,003,000,000	1,117,000,000
Other current liabilities		(34,000,000)	(8,000,000)
Noncurrent pension and other postretirement benefit liabilities		(2,272,000,000)	(2,099,000,000)
Net amount recognized		$ (1,303,000,000)	$ (990,000,000)
Significant assumptions used to determine benefit obligations
Weighted average rate of increase for compensation		4.32%	4.09%
Pension Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at beginning of year		$ 773,000,000	$ 683,000,000
Service cost		18,000,000	15,000,000	13,000,000
Interest cost		29,000,000	30,000,000	30,000,000
Benefits paid		(34,000,000)	(33,000,000)
Actuarial (gains) losses during the year		(56,000,000)	78,000,000
Benefit obligation at end of year		730,000,000	773,000,000	683,000,000
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year		1,803,000,000	1,542,000,000
Actual return (loss) on plan assets		(113,000,000)	294,000,000
Benefits paid		(34,000,000)	(33,000,000)
Fair value of plan assets at end of year		1,656,000,000	1,803,000,000	1,542,000,000
Funded status at end of year		926,000,000	1,030,000,000
Noncurrent pension and other postretirement benefit assets		926,000,000	1,030,000,000
Net amount recognized		$ 926,000,000	$ 1,030,000,000
Significant assumptions used to determine benefit obligations
Discount rate		4.42%	3.81%
Weighted average rate of increase for compensation		4.55%	4.11%
Pension Benefits | Minimum
Significant assumptions used to determine benefit obligations
Discount rate		4.42%	3.80%
Pension Benefits | Maximum
Significant assumptions used to determine benefit obligations
Discount rate		4.43%	3.81%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at beginning of year		$ 1,529,000,000	$ 1,478,000,000
Service cost		27,000,000	26,000,000	31,000,000
Interest cost		56,000,000	60,000,000	65,000,000
Benefits paid		(87,000,000)	(83,000,000)
Actuarial (gains) losses during the year		(158,000,000)	119,000,000
Plan amendments	[1]	(4,000,000)	(73,000,000)
Settlements and curtailments	[2]		2,000,000
Benefit obligation at end of year		1,363,000,000	1,529,000,000	1,478,000,000
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year		1,729,000,000	1,512,000,000
Actual return (loss) on plan assets		(92,000,000)	236,000,000
Employer contributions		12,000,000	13,000,000
Benefits paid		(68,000,000)	(32,000,000)
Fair value of plan assets at end of year		1,581,000,000	1,729,000,000	1,512,000,000
Funded status at end of year		218,000,000	200,000,000
Noncurrent pension and other postretirement benefit assets		276,000,000	261,000,000
Other current liabilities		(2,000,000)
Noncurrent pension and other postretirement benefit liabilities		(56,000,000)	(61,000,000)
Net amount recognized		218,000,000	$ 200,000,000
Significant assumptions used to determine benefit obligations
Discount rate			3.76%
Other Postretirement Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at beginning of year		290,000,000	$ 320,000,000
Service cost		4,000,000	4,000,000	5,000,000
Interest cost		11,000,000	12,000,000	14,000,000
Benefits paid		(18,000,000)	(19,000,000)
Actuarial (gains) losses during the year		(27,000,000)	34,000,000
Plan amendments	[1]	(4,000,000)	(61,000,000)
Benefit obligation at end of year		256,000,000	290,000,000	320,000,000
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year		333,000,000	299,000,000
Actual return (loss) on plan assets		(16,000,000)	41,000,000
Employer contributions		12,000,000	12,000,000
Benefits paid		(18,000,000)	(19,000,000)
Fair value of plan assets at end of year		311,000,000	333,000,000	$ 299,000,000
Funded status at end of year		55,000,000	43,000,000
Noncurrent pension and other postretirement benefit assets		63,000,000	57,000,000
Noncurrent pension and other postretirement benefit liabilities	[3]	(8,000,000)	(14,000,000)
Net amount recognized		$ 55,000,000	$ 43,000,000
Significant assumptions used to determine benefit obligations
Discount rate		4.37%	3.76%
Other Postretirement Benefits | Minimum
Significant assumptions used to determine benefit obligations
Discount rate		4.37%
Weighted average rate of increase for compensation		4.30%	3.95%
Other Postretirement Benefits | Maximum
Significant assumptions used to determine benefit obligations
Discount rate		4.38%
Weighted average rate of increase for compensation		4.55%	4.11%

[1] 2017 amounts relate primarily to a plan amendment that changed post-65 retiree medical coverage for certain current and future Local 69 retirees effective July 1, 2017.

[2] 2017 amount relates primarily to settlement and curtailment as a result of the voluntary and involuntary separation programs at Dominion Energy Questar.

[3] Reflected in other deferred credits and other liabilities in Dominion Energy Gas' Consolidated Balance Sheets.

XML

Employee Benefit Plans (Benefit Obligation in Excess of Plan Assets) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	$ 7,705	$ 8,209
Fair value of plan assets	5,398	6,103
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	164	191
Fair value of plan assets	136	156
Other Postretirement Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	134	157
Fair value of plan assets	$ 126	$ 143

XML

Employee Benefit Plans (Accumulated Benefit Obligation in Excess of Plan Assets) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
General Discussion Of Pension And Other Postretirement Benefits [Abstract]
Accumulated benefit obligation	$ 7,056	$ 7,392
Fair value of plan assets	$ 5,398	$ 6,103

XML

Employee Benefit Plans (Benefit Payments Expected Future Service) (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2019	$ 407
2020	405
2021	426
2022	442
2023	465
2024-2028	2,548
Pension Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
2019	37
2020	39
2021	40
2022	42
2023	43
2024-2028	223
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2019	98
2020	99
2021	99
2022	99
2023	98
2024-2028	461
Other Postretirement Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
2019	19
2020	19
2021	19
2022	19
2023	19
2024-2028	$ 90

XML

Employee Benefit Plans (Fair values of pension and post retirement plan assets by asset category) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Total investments		$ 1,279	$ 1,378
Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total investments	[1]	1,775	1,828
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		7,197	8,062	$ 7,016
Pension Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1,656	1,803	1,542
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1,581	1,729	1,512
Other Postretirement Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		311	333	$ 299
Collective Bargaining Agreement | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		4,424	4,878
Total recorded at NAV	[2]	2,762	3,169
Total investments	[3]	7,186	8,047
Collective Bargaining Agreement | Pension Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1,017	1,090
Total recorded at NAV	[2]	636	709
Total investments	[4]	1,653	1,799
Collective Bargaining Agreement | Pension Benefits | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		18	18
Collective Bargaining Agreement | Pension Benefits | Cash equivalents and other | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		4	4
Collective Bargaining Agreement | Pension Benefits | US Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1,645	1,902
Collective Bargaining Agreement | Pension Benefits | US Equity Securities | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		378	425
Collective Bargaining Agreement | Pension Benefits | Foreign Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1,061	1,151
Collective Bargaining Agreement | Pension Benefits | Foreign Equity Securities | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		244	257
Collective Bargaining Agreement | Pension Benefits | Insurance contracts
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		318	352
Collective Bargaining Agreement | Pension Benefits | Insurance contracts | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		73	79
Collective Bargaining Agreement | Pension Benefits | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		752	770
Collective Bargaining Agreement | Pension Benefits | Corporate debt instruments | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		173	172
Collective Bargaining Agreement | Pension Benefits | Government securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		630	685
Collective Bargaining Agreement | Pension Benefits | Government securities | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		145	153
Collective Bargaining Agreement | Pension Benefits | Common/collective trust funds
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	1,849	2,272
Collective Bargaining Agreement | Pension Benefits | Common/collective trust funds | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	425	509
Collective Bargaining Agreement | Pension Benefits | Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	108	111
Collective Bargaining Agreement | Pension Benefits | Real Estate Funds | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	25	25
Collective Bargaining Agreement | Pension Benefits | Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	633	606
Collective Bargaining Agreement | Pension Benefits | Private Equity Funds | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	146	135
Collective Bargaining Agreement | Pension Benefits | Fixed Income Funds
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	155	161
Collective Bargaining Agreement | Pension Benefits | Fixed Income Funds | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	36	36
Collective Bargaining Agreement | Pension Benefits | Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	17	19
Collective Bargaining Agreement | Pension Benefits | Hedge Funds | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	4	4
Collective Bargaining Agreement | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		829	944
Total recorded at NAV	[2]	751	783
Total investments	[5]	1,580	1,727
Collective Bargaining Agreement | Other Postretirement Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		143	163
Total recorded at NAV	[2]	168	170
Total investments		311	333
Collective Bargaining Agreement | Other Postretirement Benefits | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		2	3
Collective Bargaining Agreement | Other Postretirement Benefits | US Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		554	636
Collective Bargaining Agreement | Other Postretirement Benefits | US Equity Securities | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		113	130
Collective Bargaining Agreement | Other Postretirement Benefits | Foreign Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		170	196
Collective Bargaining Agreement | Other Postretirement Benefits | Foreign Equity Securities | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		30	33
Collective Bargaining Agreement | Other Postretirement Benefits | Insurance contracts
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		19	21
Collective Bargaining Agreement | Other Postretirement Benefits | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		45	46
Collective Bargaining Agreement | Other Postretirement Benefits | Government securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		39	42
Collective Bargaining Agreement | Other Postretirement Benefits | Common/collective trust funds
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	650	689
Collective Bargaining Agreement | Other Postretirement Benefits | Common/collective trust funds | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	148	154
Collective Bargaining Agreement | Other Postretirement Benefits | Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	10	9
Collective Bargaining Agreement | Other Postretirement Benefits | Real Estate Funds | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	2	1
Collective Bargaining Agreement | Other Postretirement Benefits | Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	80	73
Collective Bargaining Agreement | Other Postretirement Benefits | Private Equity Funds | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	18	15
Collective Bargaining Agreement | Other Postretirement Benefits | Fixed Income Funds
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	10	11
Collective Bargaining Agreement | Other Postretirement Benefits | Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Total recorded at NAV	[2]	1	1
Level 1 | Collective Bargaining Agreement | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		2,771	3,121
Level 1 | Collective Bargaining Agreement | Pension Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		637	697
Level 1 | Collective Bargaining Agreement | Pension Benefits | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		17	18
Level 1 | Collective Bargaining Agreement | Pension Benefits | Cash equivalents and other | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		4	4
Level 1 | Collective Bargaining Agreement | Pension Benefits | US Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1,645	1,902
Level 1 | Collective Bargaining Agreement | Pension Benefits | US Equity Securities | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		378	425
Level 1 | Collective Bargaining Agreement | Pension Benefits | Foreign Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1,061	1,151
Level 1 | Collective Bargaining Agreement | Pension Benefits | Foreign Equity Securities | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		244	257
Level 1 | Collective Bargaining Agreement | Pension Benefits | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		23	41
Level 1 | Collective Bargaining Agreement | Pension Benefits | Corporate debt instruments | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		5	9
Level 1 | Collective Bargaining Agreement | Pension Benefits | Government securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		25	9
Level 1 | Collective Bargaining Agreement | Pension Benefits | Government securities | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		6	2
Level 1 | Collective Bargaining Agreement | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		728	836
Level 1 | Collective Bargaining Agreement | Other Postretirement Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		143	163
Level 1 | Collective Bargaining Agreement | Other Postretirement Benefits | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1	1
Level 1 | Collective Bargaining Agreement | Other Postretirement Benefits | US Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		554	636
Level 1 | Collective Bargaining Agreement | Other Postretirement Benefits | US Equity Securities | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		113	130
Level 1 | Collective Bargaining Agreement | Other Postretirement Benefits | Foreign Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		170	196
Level 1 | Collective Bargaining Agreement | Other Postretirement Benefits | Foreign Equity Securities | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		30	33
Level 1 | Collective Bargaining Agreement | Other Postretirement Benefits | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1	2
Level 1 | Collective Bargaining Agreement | Other Postretirement Benefits | Government securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		2	1
Level 2 | Collective Bargaining Agreement | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1,653	1,757
Level 2 | Collective Bargaining Agreement | Pension Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		380	393
Level 2 | Collective Bargaining Agreement | Pension Benefits | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1
Level 2 | Collective Bargaining Agreement | Pension Benefits | Insurance contracts
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		318	352
Level 2 | Collective Bargaining Agreement | Pension Benefits | Insurance contracts | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		73	79
Level 2 | Collective Bargaining Agreement | Pension Benefits | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		729	729
Level 2 | Collective Bargaining Agreement | Pension Benefits | Corporate debt instruments | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		168	163
Level 2 | Collective Bargaining Agreement | Pension Benefits | Government securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		605	676
Level 2 | Collective Bargaining Agreement | Pension Benefits | Government securities | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		139	151
Level 2 | Collective Bargaining Agreement | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		101	108
Level 2 | Collective Bargaining Agreement | Other Postretirement Benefits | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1	2
Level 2 | Collective Bargaining Agreement | Other Postretirement Benefits | Insurance contracts
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		19	21
Level 2 | Collective Bargaining Agreement | Other Postretirement Benefits | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		44	44
Level 2 | Collective Bargaining Agreement | Other Postretirement Benefits | Government securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		$ 37	$ 41

[1] See Note 24 for amounts attributable to related parties.

[2] These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

[3] Excludes net assets related to pending sales of securities of $12 million, net accrued income of $21 million, and includes net assets related to pending purchases of securities of $22 million at December 31, 2018. Excludes net assets related to pending sales of securities of $11 million, net accrued income of $19 million, and includes net assets related to pending purchases of securities of $15 million at December 31, 2017.

[4] Excludes net assets related to pending sales of securities of $3 million, net accrued income of $5 million, and includes net assets related to pending purchases of securities of $5 million at December 31, 2018. Excludes net assets related to pending sales of securities of $3 million, net accrued income of $4 million, and includes net assets related to pending purchases of securities of $3 million at December 31, 2017.

[5] Excludes net assets related to pending sales of securities of $1 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $2 million at December 31, 2018. Excludes net assets related to pending sales of securities of $1 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $1 million at December 31, 2017.

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Employee Benefit Plans (Fair values of pension and post retirement plan assets by asset category) (Parenthetical) (Detail) - Collective Bargaining Agreement - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pending sales of securities	$ 12	$ 11
Net accrued income	21	19
Pending purchases of securities	22	15
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Pending sales of securities	1	1
Net accrued income	2	2
Pending purchases of securities	2	1
Dominion Energy Gas Holdings, LLC | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pending sales of securities	3	3
Net accrued income	5	4
Pending purchases of securities	$ 5	$ 3

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Employee Benefit Plans (Net Periodic Benefit (Credit) Cost and Amounts Recognized in Other Comprehensive Income and Regulatory Assets and Liabilities) (Detail) - USD ($) $ in Millions					12 Months Ended
		Sep. 30, 2017	Jun. 30, 2017	Jan. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Expected return on plan assets					$ (806)	$ (767)
Dominion Energy Gas Holdings, LLC
Expected return on plan assets					(178)	(165)
Pension Benefits
Service cost					157	138	$ 118
Interest cost					337	345	317
Expected return on plan assets					(663)	(639)	(573)
Amortization of prior service (credit) cost					1	1	1
Amortization of net actuarial loss					193	162	111
Settlements and curtailments							1
Net periodic benefit (credit) cost					25	7	(25)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss					490	142	931
Prior service (credit) cost						5
Settlements and curtailments						1	(1)
Amortization of net actuarial loss					(193)	(162)	(111)
Amortization of prior service credit (cost)					(1)	(1)	(1)
Total recognized in other comprehensive income and regulatory assets and liabilities					$ 296	$ (15)	$ 818
Significant assumptions used to determine periodic cost:
Discount rate		4.05%	4.05%	4.51%			4.46%
Expected long-term rate of return on plan assets					8.75%	8.75%	8.75%
Weighted average rate of increase for compensation					4.09%	4.09%	4.22%
Pension Benefits | Dominion Energy Gas Holdings, LLC
Service cost					$ 18	$ 15	$ 13
Interest cost					29	30	30
Expected return on plan assets					(150)	(141)	(134)
Amortization of net actuarial loss					19	16	13
Net periodic benefit (credit) cost					(84)	(80)	(78)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss					207	(75)	91
Amortization of net actuarial loss					(19)	(16)	(13)
Total recognized in other comprehensive income and regulatory assets and liabilities					$ 188	$ (91)	$ 78
Significant assumptions used to determine periodic cost:
Discount rate					3.81%	4.50%	4.99%
Expected long-term rate of return on plan assets					8.75%	8.75%	8.75%
Weighted average rate of increase for compensation					4.11%	4.11%	3.93%
Pension Benefits | Minimum
Significant assumptions used to determine periodic cost:
Discount rate					3.80%	3.31%	2.87%
Pension Benefits | Maximum
Significant assumptions used to determine periodic cost:
Discount rate					3.81%	4.50%	4.99%
Other Postretirement Benefits
Service cost					$ 27	$ 26	$ 31
Interest cost					56	60	65
Expected return on plan assets					(143)	(128)	(118)
Amortization of prior service (credit) cost					(52)	(51)	(35)
Amortization of net actuarial loss					11	13	8
Net periodic benefit (credit) cost					(101)	(80)	(49)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss					78	12	178
Prior service (credit) cost					(4)	(73)	(216)
Settlements and curtailments						2
Amortization of net actuarial loss					(11)	(13)	(8)
Amortization of prior service credit (cost)					52	51	35
Total recognized in other comprehensive income and regulatory assets and liabilities					$ 115	$ (21)	$ (11)
Significant assumptions used to determine periodic cost:
Discount rate					3.76%
Expected long-term rate of return on plan assets					8.50%	8.50%	8.50%
Weighted average rate of increase for compensation						3.29%	4.22%
Healthcare cost trend rate	[1]				7.00%	7.00%	7.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	[1]				5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	[1],[2]				2022	2021	2020
Other Postretirement Benefits | Dominion Energy Gas Holdings, LLC
Service cost					$ 4	$ 4	$ 5
Interest cost					11	12	14
Expected return on plan assets					(28)	(24)	(23)
Amortization of prior service (credit) cost					(4)	(3)	1
Amortization of net actuarial loss					3	2	1
Net periodic benefit (credit) cost					(14)	(9)	(2)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss					16	18	28
Prior service (credit) cost					(4)	(61)
Amortization of net actuarial loss					(3)	(2)	(1)
Amortization of prior service credit (cost)					4	3	(1)
Total recognized in other comprehensive income and regulatory assets and liabilities					$ 13	$ (42)	$ 26
Significant assumptions used to determine periodic cost:
Discount rate					3.81%	4.47%	4.93%
Expected long-term rate of return on plan assets					8.50%	8.50%	8.50%
Weighted average rate of increase for compensation					4.55%	4.11%	3.93%
Healthcare cost trend rate	[1]				7.00%	7.00%	7.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	[1]				5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	[1]				2022	2021	2020
Other Postretirement Benefits | Minimum
Significant assumptions used to determine periodic cost:
Discount rate						3.92%	3.56%
Weighted average rate of increase for compensation					3.95%
Other Postretirement Benefits | Maximum
Significant assumptions used to determine periodic cost:
Discount rate						4.47%	4.94%
Weighted average rate of increase for compensation					4.11%

[1] Assumptions used to determine net periodic cost for the following year.

[2] The Society of Actuaries model used to determine healthcare cost trend rates was updated in 2014. The new model converges to the ultimate trend rate much more quickly than previous models.

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Employee Benefit Plans (AOCI and regulatory assets and liabilities that have not been recognized as components of periodic benefit (credit) cost) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss		$ 1,700	$ 659
Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss		169	98
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss		3,477	3,181
Prior service (credit) cost		7	8
Total	[1]	3,484	3,189
Pension Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss		555	367
Total	[2]	555	367
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss		350	283
Prior service (credit) cost		(393)	(440)
Total	[1]	(43)	(157)
Other Postretirement Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss		89	76
Prior service (credit) cost		(52)	(52)
Total	[2]	$ 37	$ 24

[1] As of December 31, 2018, of the $3.5 billion and $(43) million related to pension benefits and other postretirement benefits, $2.0 billion and $(41) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2017, of the $3.2 billion and $(157) million related to pension benefits and other postretirement benefits, $1.9 billion and $(87) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.

[2] As of December 31, 2018, of the $555 million related to pension benefits, $200 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $37 million related to other postretirement benefits is included entirely in regulatory assets and liabilities. As of December 31, 2017, of the $367 million related to pension benefits, $134 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $24 million related to other postretirement benefits is included entirely in regulatory assets and liabilities.

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Employee Benefit Plans (AOCI and regulatory assets and liabilities that have not been recognized as components of periodic benefit (credit) cost) (Parenthetical) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total	[1]	$ 3,484	$ 3,189
Amount included in AOCI		2,000	1,900
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Total	[1]	(43)	(157)
Amount included in AOCI		(41)	(87)
Dominion Energy Gas Holdings, LLC | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total	[2]	555	367
Amount included in AOCI		200	134
Dominion Energy Gas Holdings, LLC | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Total	[2]	$ 37	$ 24

[1] As of December 31, 2018, of the $3.5 billion and $(43) million related to pension benefits and other postretirement benefits, $2.0 billion and $(41) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2017, of the $3.2 billion and $(157) million related to pension benefits and other postretirement benefits, $1.9 billion and $(87) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.

[2] As of December 31, 2018, of the $555 million related to pension benefits, $200 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $37 million related to other postretirement benefits is included entirely in regulatory assets and liabilities. As of December 31, 2017, of the $367 million related to pension benefits, $134 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $24 million related to other postretirement benefits is included entirely in regulatory assets and liabilities.

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Employee Benefit Plans (Components of AOCI and Regulatory Assets and Liabilities) (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ 155
Prior service (credit) cost	1
Pension Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	19
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	18
Prior service (credit) cost	(52)
Other Postretirement Benefits | Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	4
Prior service (credit) cost	$ (4)

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Employee Benefit Plans (Effect of One Percentage Point Change on Benefit Plans) (Detail) - Other Postretirement Benefits $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect of one percentage point increase on total of service and interest cost components	$ 20
Effect of one percentage point increase on other postretirement benefit obligation	130
Effect of one percentage point decrease on total of service and interest cost components	(16)
Effect of one percentage point decrease on other postretirement benefit obligation	(110)
Dominion Energy Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Effect of one percentage point increase on total of service and interest cost components	4
Effect of one percentage point increase on other postretirement benefit obligation	25
Effect of one percentage point decrease on total of service and interest cost components	(3)
Effect of one percentage point decrease on other postretirement benefit obligation	$ (22)

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Commitments and Contingencies (Narrative) (Detail) $ in Millions	1 Months Ended												3 Months Ended		12 Months Ended
	Dec. 31, 2018 USD ($) site Parties	Aug. 31, 2018 USD ($)	Jun. 30, 2018 USD ($)	Sep. 30, 2017	Jul. 31, 2017	Jun. 30, 2017	May 31, 2017 Counts	Apr. 30, 2017 Petition Station	Mar. 31, 2017 Counts	Aug. 31, 2016 T	Jul. 31, 2016 Parties	Apr. 30, 2015 Facilities	Dec. 31, 2018 USD ($) site	Jun. 30, 2018 USD ($)	Dec. 31, 2018 USD ($) site Facilities Facility Indicators gal	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Oct. 31, 2017 USD ($)	Oct. 31, 2015 PartsPerBillion	Jul. 31, 2015 Counts
Loss Contingencies [Line Items]
Environmental Remediation Expense															$ 81		$ 197
ARO incurred															20	$ 37
Regulatory liability	$ 7,196												$ 7,196		7,196	7,109
Virginia Electric and Power Company
Loss Contingencies [Line Items]
Environmental Remediation Expense															81		197
ARO incurred															14	11
Regulatory liability	4,946												4,946		4,946	4,887
Virginia Electric and Power Company | Future Ash Pond and Landfill Closure Costs
Loss Contingencies [Line Items]
ARO incurred														$ 131			238	$ 386
Virginia Electric and Power Company | Increase In Property Plant And Equipment
Loss Contingencies [Line Items]
ARO incurred														46			17
Virginia Electric and Power Company | Increase in Regulatory Assets
Loss Contingencies [Line Items]
ARO incurred														4			24
Virginia Electric and Power Company | Other operations and maintenance
Loss Contingencies [Line Items]
ARO incurred														81			$ 197
ARO incurred, after tax														60
Dominion Energy Gas Holdings, LLC
Loss Contingencies [Line Items]
ARO incurred															4	2
Regulatory liability	1,306												1,306		1,306	$ 1,265
FERC-regulated | Virginia Electric and Power Company | Pending Litigation [Member]
Loss Contingencies [Line Items]
Regulatory liability	$ 14												14		$ 14
CWA | Virginia Electric and Power Company | Minimum | Chesapeake power station [Member] | Judicial Ruling
Loss Contingencies [Line Items]
Additional specific sediment, water and aquatic life monitoring period					2 years
CWA | EPA | Final Rule to Revise Effluent Limitations Guidelines for Steam Electric Power Generating Category
Loss Contingencies [Line Items]
Compliance date				2023-12
CWA | EPA | 2015 Effluent Limitations Guidelines Rule for Steam Electric Power Generating Category
Loss Contingencies [Line Items]
Compliance date				2020-11
Unfavorable Regulatory Action | EPA
Loss Contingencies [Line Items]
Significant emission rate per rear CO2 equivalent | T										75,000
Electric generating station facilities heightened entrainment analysis per day | gal															125,000,000
Unfavorable Regulatory Action | MATS | EPA | Virginia Electric and Power Company
Loss Contingencies [Line Items]
Number of effective days to operate power station units						90 days
Unfavorable Regulatory Action | Ozone Standards | EPA
Loss Contingencies [Line Items]
Standard emission level prior to revision | PartsPerBillion																				75
Revised emission standard level | PartsPerBillion																				70
Unfavorable Regulatory Action | Ozone Standards | EPA | Minimum
Loss Contingencies [Line Items]
Estimated compliance costs																			$ 25
Unfavorable Regulatory Action | Ozone Standards | EPA | Maximum
Loss Contingencies [Line Items]
Estimated compliance costs																			$ 35
Unfavorable Regulatory Action | Regulations To Reduce Nitrogen Oxideand Volatile Organic Compounds Emissions [Member] | Pennsylvania Department Of Environmental Protection [Member] | Dominion Gas Holdings, LLC
Loss Contingencies [Line Items]
Estimated compliance costs													$ 35
Unfavorable Regulatory Action | CWA
Loss Contingencies [Line Items]
Number of facilities that may be subject to final regulations | Facility															13
Unfavorable Regulatory Action | CWA | Virginia Electric and Power Company
Loss Contingencies [Line Items]
Number of facilities that may be subject to final regulations | Facility															11
Number of mandatory facility-specific factors | Indicators															5
Number of optional facility-specific factors | Indicators															6
Number of facilities subject to regulations | Facilities															9
Unfavorable Regulatory Action | CWA | Virginia Electric and Power Company | Minimum
Loss Contingencies [Line Items]
Electric generating stations with water withdrawals per day | gal															2,000,000
Unfavorable Regulatory Action | CWA | EPA | Final Rule to Revise Effluent Limitations Guidelines for Steam Electric Power Generating Category
Loss Contingencies [Line Items]
Number of separate petitions for reconsideration granted | Petition								2
Unfavorable Regulatory Action | Coal Tar and Other Potentially Harmful Materials | EPA
Loss Contingencies [Line Items]
Number of former manufactured gas plant sites | site	22												22		22
Unfavorable Regulatory Action | Coal Tar and Other Potentially Harmful Materials | EPA | Former Gas Plant Site with Post Closure Groundwater Monitoring Program
Loss Contingencies [Line Items]
Number of former sites | site															1
Unfavorable Regulatory Action | Coal Tar and Other Potentially Harmful Materials | EPA | Virginia Electric and Power Company
Loss Contingencies [Line Items]
Number of former manufactured gas plant sites | site	3												3		3
Unfavorable Regulatory Action | Coal Tar and Other Potentially Harmful Materials | EPA | Virginia Electric and Power Company | Former Gas Plant Site with Post Closure Groundwater Monitoring Program
Loss Contingencies [Line Items]
Estimated compliance costs			$ 18											$ 18
Unfavorable Regulatory Action | Coal Tar and Other Potentially Harmful Materials | EPA | Virginia Electric and Power Company | Former Gas Plant Site with Post Closure Groundwater Monitoring Program | Other operations and maintenance
Loss Contingencies [Line Items]
Environmental Remediation Expense			16
Environmental Remediation Expense, net of tax			$ 12
Unfavorable Regulatory Action | Coal Tar and Other Potentially Harmful Materials | EPA | SCANA
Loss Contingencies [Line Items]
Estimated compliance costs	$ 10												$ 10		$ 10
Number of sites under investigation, remediation and monitoring | site															4
Number of sites with an updated remediation work plan | site															1
Updated remediation work plan, cost increase															$ 8
Unfavorable Regulatory Action | Coal Tar and Other Potentially Harmful Materials | EPA | Dominion Energy Gas Holdings, LLC
Loss Contingencies [Line Items]
Number of former manufactured gas plant sites | site	12												12		12
Unfavorable Regulatory Action | CCR | EPA | Facilities Subject to Coal Combustion Residual Final Rule | Environmental Protection Agency Final Rule Regulating Management of CCRs
Loss Contingencies [Line Items]
Number of facilities with CCR | Facilities												11
Unfavorable Regulatory Action | CCR | EPA | Virginia Electric and Power Company | Facilities Subject to Coal Combustion Residual Final Rule | Environmental Protection Agency Final Rule Regulating Management of CCRs
Loss Contingencies [Line Items]
Number of facilities with CCR | Facilities												8
Number of stations | Station								4
Breach of Contract Lawsuit | DETI | Pending Litigation [Member]
Loss Contingencies [Line Items]
Total number of counts in complaint | Counts																					8
Breach of Contract Lawsuit | DETI | Judicial Ruling
Loss Contingencies [Line Items]
Number of counts dismissed | Counts									3
Breach of Contract Lawsuit | DETI | Settled Litigation
Loss Contingencies [Line Items]
Number of claims withdrew | Counts							1
payment of litigation Settlement agreement		$ 14
Liquefaction Project | FERC-regulated | Cove Point | Pending Litigation [Member]
Loss Contingencies [Line Items]
Number of parties | Parties	2
Liquefaction Project | FERC-regulated | Cove Point | Judicial Ruling
Loss Contingencies [Line Items]
Number of parties | Parties											1

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Commitments and Contingencies (Nuclear Operations) (Narrative) (Detail) - USD ($)	3 Months Ended			12 Months Ended
	Dec. 31, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
NRC minimum requirement for nuclear power plant licensees	$ 1,060,000,000			$ 1,060,000,000
Maximum assessment for premiums on insurance policy				83,000,000
Maximum assessment for insurance policy				21,000,000
Spent Nuclear Fuel
Loss Contingencies [Line Items]
Receivables	49,000,000			49,000,000	$ 46,000,000
Maximum
Loss Contingencies [Line Items]
Amount that could be assessed for each licensed reactor	138,000,000			138,000,000
Amount that could be assessed for each licensed reactor per reactor	21,000,000			$ 21,000,000
Nuclear Obligations
Loss Contingencies [Line Items]
Maximum liability protection per nuclear incident amount	14,100,000,000	$ 13,100,000,000	$ 13,400,000,000
Inflationary provision adjustment period				5 years
Virginia Electric and Power Company
Loss Contingencies [Line Items]
Maximum assessment for premiums on insurance policy				$ 51,000,000
Maximum assessment for insurance policy				10,000,000
Virginia Electric and Power Company | Spent Nuclear Fuel
Loss Contingencies [Line Items]
Receivables	30,000,000			30,000,000	30,000,000
Dominion Energy and Virginia Electric and Power
Loss Contingencies [Line Items]
Amount of coverage purchased from commercial insurance pools	450,000,000			450,000,000
Surry and North Anna
Loss Contingencies [Line Items]
Settlement amount				16,000,000	22,000,000	$ 30,000,000
Millstone
Loss Contingencies [Line Items]
Settlement amount				13,000,000	$ 14,000,000	$ 22,000,000
Millstone Unit 1
Loss Contingencies [Line Items]
Minimum financial assurance	2,700,000,000			2,700,000,000
Kewaunee | Nuclear Obligations
Loss Contingencies [Line Items]
Maximum liability protection per nuclear incident amount				100,000,000
Kewaunee | Virginia Electric and Power Company
Loss Contingencies [Line Items]
Minimum financial assurance	$ 1,800,000,000			$ 1,800,000,000

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Commitments and Contingencies (Nuclear Insurance) (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Millstone
Guarantor Obligations [Line Items]
Property insurance coverage	$ 1,700
Kewaunee
Guarantor Obligations [Line Items]
Property insurance coverage	50
Surry | Virginia Electric and Power Company
Guarantor Obligations [Line Items]
Property insurance coverage	1,700	[1]
North Anna | Virginia Electric and Power Company
Guarantor Obligations [Line Items]
Property insurance coverage	$ 1,700	[1]

[1] Surry and North Anna share a blanket property limit of $200 million.

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Commitments and Contingencies (Nuclear Insurance) (Parenthetical) (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Surry and North Anna
Guarantor Obligations [Line Items]
Coverage amount	$ 200

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Commitment and Contingencies (Schedule of Long Term Purchase Commitments) (Detail) - Virginia Electric and Power Company - Purchased electric capacity $ in Millions	Dec. 31, 2018 USD ($)	[1]
Long-term Purchase Commitment [Line Items]
2019	$ 60
2020	52
2021	46
Thereafter	0
Total	$ 158

[1] Commitments represent estimated amounts payable for capacity under power purchase contracts with independent power producers, which end in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad based economic indices. At December 31, 2018, the present value of Virginia Power's total commitment for capacity payments is $142 million. Capacity payments totaled $50 million, $114 million and $248 million, and energy payments totaled $42 million, $72 million and $126 million for the years ended 2018, 2017 and 2016, respectively.

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Commitment and Contingencies (Schedule of Long Term Purchase Commitments) (Parenthetical) (Detail) - Virginia Electric and Power Company - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Long-term Purchase Commitment [Line Items]
Present value of total commitment for capacity payments	$ 142
Purchased electric capacity
Long-term Purchase Commitment [Line Items]
Payments	50	$ 114	$ 248
Energy payments
Long-term Purchase Commitment [Line Items]
Payments	$ 42	$ 72	$ 126

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Commitments and Contingencies (Lease Commitments) (Detail) $ in Millions	Dec. 31, 2018 USD ($)
Loss Contingencies [Line Items]
2019	$ 64
2020	61
2021	55
2022	47
2023	38
Thereafter	384
Total	649
Virginia Electric and Power Company
Loss Contingencies [Line Items]
2019	34
2020	32
2021	28
2022	22
2023	16
Thereafter	106
Total	238
Dominion Gas Holdings, LLC
Loss Contingencies [Line Items]
2019	12
2020	11
2021	9
2022	7
2023	4
Thereafter	3
Total	$ 46

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Commitments and Contingencies (Lease Commitments) (Narrative) (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jul. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Rental expense		$ 109	$ 113	$ 104
Corporate office | Agreement with Lessor to Construct and Lease Corporate Office Property
Loss Contingencies [Line Items]
Requested cash draws from lessor to fund project costs		281
Required percentage payment of funded amount under certain events of default	89.90%
Required percentage payment for specific full recourse events	100.00%
Lease term	5 years
Extension term of lease	5 years
Required percentage payment to lessor for difference between project costs and sales proceeds	87.00%
Virginia Electric and Power Company
Loss Contingencies [Line Items]
Rental expense		63	57	52
Dominion Gas Holdings, LLC
Loss Contingencies [Line Items]
Rental expense		$ 22	$ 34	$ 37
Lessor | Corporate office | Agreement with Lessor to Construct and Lease Corporate Office Property
Loss Contingencies [Line Items]
Amount of financing commitments to fund estimated project costs	$ 365

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Commitments and Contingencies (Guarantees, Surety Bonds and Letters of Credit) (Detail) - USD ($)		1 Months Ended	2 Months Ended	12 Months Ended
		Oct. 31, 2017	Feb. 28, 2019	Dec. 31, 2018		Dec. 31, 2017
Guarantor Obligations [Line Items]
Facility Limit				$ 6,000,000,000	[1]	$ 5,500,000,000
Maximum Exposure	[2]			5,344,000,000
Cove Point
Guarantor Obligations [Line Items]
Maximum Exposure	[3]			1,900,000,000
Virginia Electric and Power Company
Guarantor Obligations [Line Items]
Facility Limit				6,000,000,000	[4]	5,500,000,000
Dominion Energy Gas Holdings, LLC
Guarantor Obligations [Line Items]
Facility Limit				1,500,000,000	[5]	1,500,000,000
Nuclear Obligations
Guarantor Obligations [Line Items]
Maximum Exposure	[6]			179,000,000
Commodity Transactions
Guarantor Obligations [Line Items]
Maximum Exposure	[7]			2,186,000,000
Financial Guarantee [Member] | Revolving Credit Facility | Atlantic Coast Pipeline
Guarantor Obligations [Line Items]
Facility Limit		$ 3,400,000,000
Revolving credit facility stated maturity date		Oct. 31, 2021
Maximum potential loss exposure, limited guarantee percentage		48.00%
Guarantee liability				21,000,000		$ 28,000,000
Guarantee recorded amount				1,400,000,000
Financial Guarantee [Member] | Equity Method Investee [Member]
Guarantor Obligations [Line Items]
Maximum Exposure				48,000,000
Solar
Guarantor Obligations [Line Items]
Maximum Exposure	[8]			659,000,000
Other
Guarantor Obligations [Line Items]
Maximum Exposure	[9]			420,000,000
Surety Bond [Member]
Guarantor Obligations [Line Items]
Maximum Exposure				171,000,000
Surety Bond [Member] | Virginia Electric and Power Company
Guarantor Obligations [Line Items]
Maximum Exposure				72,000,000
Surety Bond [Member] | Dominion Energy Gas Holdings, LLC
Guarantor Obligations [Line Items]
Maximum Exposure				26,000,000
Financial Standby Letter of Credit [Member]
Guarantor Obligations [Line Items]
Maximum Exposure				88,000,000
Subsequent Event | Financial Guarantee [Member] | Revolving Credit Facility | Atlantic Coast Pipeline
Guarantor Obligations [Line Items]
Additional borrowing			$ 113,000,000
Minimum | Financial Guarantee [Member] | Affiliated Entity
Guarantor Obligations [Line Items]
Maximum annual future contributions				4,000,000
Maximum | Financial Guarantee [Member] | Affiliated Entity
Guarantor Obligations [Line Items]
Maximum annual future contributions				$ 4,000,000

[1] This credit facility matures in March 2023 and can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

[2] Excludes Dominion Energy's guarantee for the construction of the new corporate office property discussed further within Lease Commitments above.

[3] Guarantees related to Cove Point, in support of terminal services, transportation and construction. Cove Point has two guarantees that have no maximum limit and, therefore, are not included in this amount.

[4] The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Virginia Power was $1.5 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

[5] A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. The sub-limit for Dominion Energy Gas is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Dominion Energy Gas was $750 million. If Dominion Energy 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 Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

[6] Guarantees related to certain DGI subsidiaries' regarding all aspects of running a nuclear facility.

[7] Guarantees related to commodity commitments of certain subsidiaries. These guarantees were provided to counterparties in order to facilitate physical and financial transaction related commodities and services.

[8] Includes guarantees to facilitate the development of solar projects. Also includes guarantees entered into by DGI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.

[9] Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations, construction projects and insurance programs. Due to the uncertainty of worker's compensation claims, the parental guarantee has no stated limit. Also included are guarantees related to certain DGI subsidiaries' obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of December 31, 2018, Dominion Energy's maximum remaining cumulative exposure under these equity funding agreements is $4 million through 2019 and its maximum annual future contribution is approximately $4 million.

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Credit Risk (Narrative) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) Counterparty Customer	Dec. 31, 2017 USD ($)
Concentration Risk And Guarantor Obligations [Line Items]
Gross credit exposure	$ 145
Additional collateral to be posted if the credit related contingent features were triggered	1	$ 62
Aggregate fair value of all derivative instruments with credit contingent provisions that are in a liability position	1	$ 65
Virginia Electric and Power Company
Concentration Risk And Guarantor Obligations [Line Items]
Gross credit exposure	10
Dominion Energy Gas Holdings, LLC
Concentration Risk And Guarantor Obligations [Line Items]
Gross credit exposure	$ 8
Credit Concentration Risk
Concentration Risk And Guarantor Obligations [Line Items]
Number of counterparties | Counterparty	0
Amount of exposure for single counterparty	$ 47
Credit Concentration Risk | Virginia Electric and Power Company
Concentration Risk And Guarantor Obligations [Line Items]
Amount of exposure for single counterparty	$ 9
Credit Concentration Risk | Dominion Energy Gas Holdings, LLC
Concentration Risk And Guarantor Obligations [Line Items]
Number of counterparties | Counterparty	0
Amount of exposure for single counterparty	$ 5
Credit Concentration Risk | Investment Grade | Investment Grade Counterparty
Concentration Risk And Guarantor Obligations [Line Items]
Concentration risk, percentage (percentage)	69.00%
Credit Concentration Risk | Investment Grade | Investment Grade Counterparty | Dominion Energy Gas Holdings, LLC
Concentration Risk And Guarantor Obligations [Line Items]
Concentration risk, percentage (percentage)	93.00%
Customer Concentration Risk | Sales Revenue, Net | Dominion Energy Gas Holdings, LLC
Concentration Risk And Guarantor Obligations [Line Items]
Concentration risk, percentage (percentage)	96.00%
Number of customers | Customer	307
Customer Concentration Risk | Sales Revenue, Net | Dominion Energy Gas Holdings, LLC | Ten Largest Customers
Concentration Risk And Guarantor Obligations [Line Items]
Concentration risk, percentage (percentage)	38.00%
Number of customers | Customer	10
Customer Concentration Risk | Sales Revenue, Net | Dominion Energy Gas Holdings, LLC | Thirty Largest Customers
Concentration Risk And Guarantor Obligations [Line Items]
Concentration risk, percentage (percentage)	71.00%
Number of customers | Customer	30
Customer Concentration Risk | Sales Revenue, Net | East Ohio
Concentration Risk And Guarantor Obligations [Line Items]
Concentration risk, percentage (percentage)	99.00%

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Related-Party Transactions (Narrative) (Detail) - USD ($) shares in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Related Party Transaction [Line Items]
Derivative Asset	$ 294,000,000	$ 307,000,000
Derivative Liabilities	279,000,000	284,000,000
Dominion Energy Gas Holdings, LLC
Related Party Transaction [Line Items]
Derivative Asset	29,000,000	32,000,000	[1]
Derivative Liabilities	19,000,000	8,000,000
Short term demand note	218,000,000	18,000,000
Dominion Energy Gas Holdings, LLC | Revolving Credit Facility | IRCA
Related Party Transaction [Line Items]
Short term demand note	$ 218,000,000	$ 18,000,000
Weighted- average interest rate percentage	2.78%	1.60%
Dominion Energy Gas Holdings, LLC | Pension Benefits | Amounts Associated with the Dominion Pension Plan
Related Party Transaction [Line Items]
Amounts due from Dominion, noncurrent	$ 772,000,000	$ 734,000,000
Dominion Energy Gas Holdings, LLC | Medical Coverage for Local retirees | Amounts Associated with the Dominion Retiree Health and Welfare Plan
Related Party Transaction [Line Items]
Amounts due from Dominion, noncurrent	14,000,000	7,000,000
Virginia Electric and Power Company
Related Party Transaction [Line Items]
Derivative Asset	93,000,000	166,000,000
Derivative Liabilities	103,000,000	66,000,000
Short term demand note	224,000,000	33,000,000
Outstanding borrowings, net of repayments, under money pool for non-regulated subsidiaries	$ 0	$ 0
Issuance of common stock (in shares)	0	0		0
Virginia Electric and Power Company | Affiliated Entity
Related Party Transaction [Line Items]
Derivative Asset	$ 26,000,000	$ 11,000,000
Derivative Liabilities	10,000,000	5,000,000
Virginia Electric and Power Company | Principal Owner
Related Party Transaction [Line Items]
Short term demand note	$ 224,000,000	$ 33,000,000
Weighted- average interest rate percentage	2.94%	1.65%
Virginia Electric and Power Company | Pension Benefits | Amounts Associated with the Dominion Pension Plan
Related Party Transaction [Line Items]
Amounts due to Dominion, noncurrent	$ 632,000,000	$ 505,000,000
Virginia Electric and Power Company | Medical Coverage for Local retirees | Amounts Associated with the Dominion Retiree Health and Welfare Plan
Related Party Transaction [Line Items]
Amounts due from Dominion, noncurrent	$ 254,000,000	$ 199,000,000

[1] Current derivative liabilities are presented in other current liabilities in Virginia Power's Consolidated Balance Sheets.

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Related-Party Transactions (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Virginia Electric and Power Company
Related Party Transaction [Line Items]
Commodity purchases from affiliates		$ 930	$ 674	$ 571
Services provided by affiliates	[1]	450	453	454
Virginia Electric and Power Company | Affiliated Entity
Related Party Transaction [Line Items]
Services provided to related parties		24	25	22
Dominion Energy Gas Holdings, LLC
Related Party Transaction [Line Items]
Services provided to related parties	[2]	216	156	128
Commodity purchases from affiliates		58	70	69
Services provided by affiliates	[3]	131	143	141
Other receivables	[4]	13	12
Customer receivables from related parties		1	1
Affiliated notes receivable	[5]	16	20
Dominion Energy Gas Holdings, LLC | Affiliated Entity
Related Party Transaction [Line Items]
Services provided to related parties		6	5	$ 9
Imbalances receivable from affiliates		1	$ 1
Imbalances payable to affiliates	[6]	$ 13

[1] Includes capitalized expenditures of $145 million, $144 million and $144 million for the year ended December 31, 2018, 2017 and 2016, respectively.

[2] Amounts primarily attributable to Atlantic Coast Pipeline, a related party VIE.

[3] Includes capitalized expenditures of $37 million, $45 million and $49 million for the year ended December 31, 2018, 2017 and 2016, respectively.

[4] Represents amounts due from Atlantic Coast Pipeline, a related party VIE.

[5] Amounts are presented in other deferred charges and other assets in Dominion Energy Gas' Consolidated Balance Sheets.

[6] Amounts are presented in other current liabilities in Dominion Energy Gas' Consolidated Balance Sheets.

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Related-Party Transactions (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Capital expenditures	$ 4,254	$ 5,504	$ 6,085
Virginia Electric and Power Company
Related Party Transaction [Line Items]
Capital expenditures	2,228	2,496	2,489
Virginia Electric and Power Company | Services provided by affiliates | Affiliated Entity
Related Party Transaction [Line Items]
Capital expenditures	145	144	144
Dominion Energy Gas Holdings, LLC
Related Party Transaction [Line Items]
Capital expenditures	772	778	854
Dominion Energy Gas Holdings, LLC | Services provided by affiliates | Affiliated Entity
Related Party Transaction [Line Items]
Capital expenditures	$ 37	$ 45	$ 49

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Operating Segments (Narrative) (Detail) - USD ($) $ in Millions	3 Months Ended			12 Months Ended
	Dec. 31, 2018	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
After-tax charge related to the impairment of gathering and processing assets	$ 164
Net loss related to investments in nuclear decommissioning trust funds, after tax				$ (17)	$ 141	$ (325)
Charge for disallowance of FERC-regulated plant, after tax		$ 89
Charge associated with asset retirement obligations for ash ponds and landfills at certain utility generation facilities				81		197
Tax benefit resulting from remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act			$ (851)	46	(851)	0
Charges associated with equity method investments in wind-powered generation facilities					158
Charges associated with equity method investments in wind-powered generation facilities, after tax					96
Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Net loss related to investments in nuclear decommissioning trust funds, after tax				2	16	6
Charge associated with asset retirement obligations for ash ponds and landfills at certain utility generation facilities				81		197
Tax benefit resulting from remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act			(93)	21	(93)	0
Dominion Energy Gas Holdings, LLC
Segment Reporting Information [Line Items]
Net loss related to investments in nuclear decommissioning trust funds, after tax				(45)	25	(24)
Charge for disallowance of FERC-regulated plant, after tax		$ 89
Tax benefit resulting from remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act			$ (197)	(11)	(197)	0
Operating Segments
Segment Reporting Information [Line Items]
After-tax net (expenses) benefit				88	861	(180)
Benefit associated with sale of certain merchant generation facilities and equity method investments				828
Benefit associated with sale of certain merchant generation facilities and equity method investments, after tax				619
Operating Segments | Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Tax benefit resulting from remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act					(93)
Operating Segments | Dominion Energy Gas Holdings, LLC
Segment Reporting Information [Line Items]
After-tax net (expenses) benefit				(244)	(174)	(7)
Charge related to impairment of certain gathering and processing assets				219
After-tax charge related to the impairment of gathering and processing assets				165
Tax benefit resulting from remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act					185
Charge for disallowance of FERC-regulated plant				124
After-tax charge for disallowance of FERC-regulated plant				88
Operating Segments | Organizational Design Initiative
Segment Reporting Information [Line Items]
Organizational design initiative						59
Organizational design initiative charges, after tax						36
Operating Segments | Organizational Design Initiative | Dominion Energy Gas Holdings, LLC
Segment Reporting Information [Line Items]
Organizational design initiative						8
Organizational design initiative charges, after tax						5
Operating Segments | Virginia Legislation [Member]
Segment Reporting Information [Line Items]
One-time rate credit amount				215
One-time rate credit amount after tax				160
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
After-tax net (expenses) benefit				608	389	(484)
Operating Segments | Corporate and Other | Virginia Electric and Power Company
Segment Reporting Information [Line Items]
After-tax net (expenses) benefit				(312)	74	(173)
Operating Segments | Corporate and Other | Dominion Energy Gas Holdings, LLC
Segment Reporting Information [Line Items]
After-tax net (expenses) benefit				(251)	(179)	(3)
Operating Segments | Gas Infrastructure
Segment Reporting Information [Line Items]
Charge related to impairment of certain gathering and processing assets				219
After-tax charge related to the impairment of gathering and processing assets				164
Benefit associated with sale of certain merchant generation facilities and equity method investments, after tax				390
Operating Segments | Gas Infrastructure | FERC-Regulated Plant
Segment Reporting Information [Line Items]
Charge for disallowance of FERC-regulated plant				124
Charge for disallowance of FERC-regulated plant, after tax				88
Operating Segments | Gas Infrastructure | Organizational Design Initiative
Segment Reporting Information [Line Items]
Organizational design initiative charges, after tax						12
Operating Segments | Power Generation
Segment Reporting Information [Line Items]
Net loss related to investments in nuclear decommissioning trust funds				(170)
Net loss related to investments in nuclear decommissioning trust funds, after tax				(134)
Charges associated with equity method investments in wind-powered generation facilities					158
Charges associated with equity method investments in wind-powered generation facilities, after tax					96
Operating Segments | Power Generation | Organizational Design Initiative
Segment Reporting Information [Line Items]
Organizational design initiative charges, after tax						19
Operating Segments | Power Generation | Virginia Legislation [Member]
Segment Reporting Information [Line Items]
Charge associated with one-time rate credits of certain amounts to utility customers, after tax				109
Operating Segments | Power Generation | Virginia Regulation
Segment Reporting Information [Line Items]
Charge associated with asset retirement obligations for ash ponds and landfills at certain utility generation facilities				81
Charge associated with asset retirement obligations for ash ponds and landfills at certain utility generation facilities, after tax				60
Operating Segments | Power Generation | Facilities Subject to Coal Combustion Residual Final Rule
Segment Reporting Information [Line Items]
Charge associated with asset retirement obligations for ash ponds and landfills at certain utility generation facilities						197
Charge associated with asset retirement obligations for ash ponds and landfills at certain utility generation facilities, after tax						122
Operating Segments | Power Generation | Facilities Subject to Coal Combustion Residual Final Rule | Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Charge associated with asset retirement obligations for ash ponds and landfills at certain utility generation facilities						197
Charge associated with asset retirement obligations for ash ponds and landfills at certain utility generation facilities, after tax						121
Operating Segments | Power Delivery
Segment Reporting Information [Line Items]
Charge associated with major storm damage and service restoration				70
Charge associated with major storm damage and service restoration, after tax				52
Benefit associated with sale of certain merchant generation facilities and equity method investments, after tax				229
Operating Segments | Power Delivery | Organizational Design Initiative
Segment Reporting Information [Line Items]
Organizational design initiative charges, after tax						$ 5
Operating Segments | Power Delivery | Virginia Legislation [Member]
Segment Reporting Information [Line Items]
Charge associated with one-time rate credits of certain amounts to utility customers, after tax				$ 51
Operating Segments | Remeasured Subsequent To Initial Recognition [Member]
Segment Reporting Information [Line Items]
Tax benefit resulting from remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act					(979)
Operating Segments | Remeasured Subsequent To Initial Recognition [Member] | Gas Infrastructure
Segment Reporting Information [Line Items]
Tax benefit resulting from remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act					(324)
Operating Segments | Remeasured Subsequent To Initial Recognition [Member] | Power Generation
Segment Reporting Information [Line Items]
Tax benefit resulting from remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act					$ (655)

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Operating Segments (Schedule of Segment Reporting Information, by Segment) (Detail) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Segment Reporting Information [Line Items]
Operating revenue		$ 3,361.0	$ 3,451.0	$ 3,088.0	$ 3,466.0	$ 3,210.0	$ 3,179.0	$ 2,813.0	$ 3,384.0	$ 13,366.0	[1]	$ 12,586.0	[1]	$ 11,737.0	[1]
Depreciation and amortization										2,000.0		1,905.0		1,559.0
Impairment of assets and related charges										403.0		15.0		4.0
Gains on sales of assets										(380.0)		(147.0)		(40.0)
Equity in earnings of equity method investees										197.0		(18.0)		111.0
Interest income										84.0		82.0		66.0
Interest and related charges										1,493.0		1,205.0		1,010.0
Income tax expense (benefit)										580.0		(30.0)		655.0
Net income		641.0	854.0	449.0	503.0	1,312.0	665.0	390.0	632.0	2,447.0		2,999.0		2,123.0
Investment in equity method investees		1,278.0				1,544.0				1,278.0		1,544.0
Capital expenditures										4,405.0		5,909.0		6,125.0
Capital expenditures										4,254.0		5,504.0		6,085.0
Total assets		77,914.0				76,585.0				77,914.0		76,585.0
Total assets		77,914.0				76,585.0				77,914.0		76,585.0
Dominion Energy Gas Holdings, LLC
Segment Reporting Information [Line Items]
Operating revenue		532.0	423.0	459.0	526.0	501.0	401.0	422.0	490.0	1,940.0	[2]	1,814.0	[2]	1,638.0	[2]
Depreciation and amortization										244.0		227.0		204.0
Impairment of assets and related charges		219.0								346.0		16.0
Gains on sales of assets										(119.0)		(70.0)		(45.0)
Equity in earnings of equity method investees										24.0		21.0		21.0
Interest income										2.0		2.0		1.0
Interest and related charges	[2]									105.0		97.0		94.0
Income tax expense (benefit)										86.0		51.0		215.0
Net income		(16.0)	136.0	15.0	166.0	313.0	117.0	77.0	108.0	301.0		615.0		392.0
Investment in equity method investees		91.0				95.0				91.0		95.0
Capital expenditures										772.0		778.0		854.0
Total assets		12,351.0				11,940.0				12,351.0		11,940.0
Total assets		12,351.0				11,940.0				12,351.0		11,940.0
Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Operating revenue		1,810.0	2,232.0	1,829.0	1,748.0	1,824.0	2,154.0	1,747.0	1,831.0	7,619.0	[3]	7,556.0	[3]	7,588.0	[3]
Depreciation and amortization										1,132.0		1,141.0		1,025.0
Interest income										10.0		19.0
Interest and related charges	[3]									511.0		494.0		461.0
Income tax expense (benefit)										300.0		774.0		727.0
Net income		239.0	$ 520.0	$ 339.0	$ 184.0	407.0	$ 459.0	$ 318.0	$ 356.0	1,282.0		1,540.0		1,218.0
Capital expenditures										2,542.0		2,729.0		2,649.0
Capital expenditures										2,228.0		2,496.0		2,489.0
Total assets		36,880.0				35,139.0				36,880.0		35,139.0
Total assets		36,880.0				35,139.0				36,880.0		35,139.0
Gas Infrastructure
Segment Reporting Information [Line Items]
Operating revenue										4,221.0		2,832.0		2,069.0
Gas Infrastructure | Dominion Energy Gas Holdings, LLC
Segment Reporting Information [Line Items]
Operating revenue										1,940.0		1,814.0		1,638.0
Depreciation and amortization										244.0		227.0		214.0
Impairment of assets and related charges										5.0		15.0
Gains on sales of assets										(119.0)		(70.0)		(45.0)
Equity in earnings of equity method investees										24.0		21.0		21.0
Interest income										2.0		2.0		1.0
Interest and related charges										104.0		97.0		92.0
Income tax expense (benefit)										188.0		256.0		237.0
Net income										552.0		436.0		395.0
Investment in equity method investees		91.0				95.0				91.0		95.0
Capital expenditures										772.0		778.0		854.0
Total assets		11,800.0				11,300.0				11,800.0		11,300.0
Total assets		11,800.0				11,300.0				11,800.0		11,300.0
Corporate and Other
Segment Reporting Information [Line Items]
Operating revenue										(208.0)		16.0		(7.0)
Corporate and Other | Dominion Energy Gas Holdings, LLC
Segment Reporting Information [Line Items]
Depreciation and amortization														(10.0)
Impairment of assets and related charges										341.0		1.0
Interest and related charges										1.0				2.0
Income tax expense (benefit)										(102.0)		(205.0)		(22.0)
Net income										(251.0)		179.0		(3.0)
Total assets		600.0				600.0				600.0		600.0
Total assets		600.0				600.0				600.0		600.0
Power Delivery
Segment Reporting Information [Line Items]
Operating revenue										2,206.0		2,206.0		2,210.0
Power Generation
Segment Reporting Information [Line Items]
Operating revenue										7,104.0		6,676.0		6,747.0
Adjustments & Eliminations
Segment Reporting Information [Line Items]
Operating revenue										43.0		856.0		718.0
Adjustments & Eliminations | Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Interest income										(4.0)		(3.0)
Interest and related charges										(4.0)		(3.0)		(2.0)
Total assets		(0.1)				(0.1)				(0.1)		(0.1)
Total assets		(0.1)				(0.1)				(0.1)		(0.1)
Intersegment revenue
Segment Reporting Information [Line Items]
Operating revenue										(735.0)		(1,476.0)		(1,339.0)
Intersegment revenue | Gas Infrastructure
Segment Reporting Information [Line Items]
Operating revenue										27.0		834.0		697.0
Intersegment revenue | Corporate and Other
Segment Reporting Information [Line Items]
Operating revenue										674.0		610.0		609.0
Intersegment revenue | Power Delivery
Segment Reporting Information [Line Items]
Operating revenue										23.0		22.0		23.0
Intersegment revenue | Power Generation
Segment Reporting Information [Line Items]
Operating revenue										11.0		10.0		10.0
Eliminations
Segment Reporting Information [Line Items]
Operating revenue										(692.0)		(620.0)		(621.0)
Operating Segments
Segment Reporting Information [Line Items]
Operating revenue										13,366.0		12,586.0		11,737.0
Operating Segments | Gas Infrastructure
Segment Reporting Information [Line Items]
Operating revenue										4,248.0		3,666.0		2,766.0
Depreciation and amortization										615.0		522.0		330.0
Impairment of assets and related charges										8.0
Gains on sales of assets										(186.0)		(147.0)		(44.0)
Equity in earnings of equity method investees										178.0		159.0		105.0
Interest income										64.0		45.0		34.0
Interest and related charges										268.0		109.0		38.0
Income tax expense (benefit)										330.0		487.0		431.0
Net income										1,214.0		898.0		726.0
Investment in equity method investees		1,159.0				1,422.0				1,159.0		1,422.0
Capital expenditures										1,415.0		2,149.0		2,322.0
Total assets		31,500.0				28,000.0				31,500.0		28,000.0
Total assets		31,500.0				28,000.0				31,500.0		28,000.0
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Operating revenue										466.0		626.0		602.0
Depreciation and amortization										14.0		43.0		30.0
Impairment of assets and related charges										394.0		15.0		4.0
Gains on sales of assets										(200.0)
Equity in earnings of equity method investees										1.0		4.0		22.0
Interest income										126.0		96.0		36.0
Interest and related charges										782.0		644.0		516.0
Income tax expense (benefit)										(204.0)		(1,224.0)		(363.0)
Net income										(608.0)		389.0		(484.0)
Investment in equity method investees		37.0				41.0				37.0		41.0
Capital expenditures										105.0		52.0		43.0
Total assets		11,200.0				12,000.0				11,200.0		12,000.0
Total assets		11,200.0				12,000.0				11,200.0		12,000.0
Operating Segments | Corporate and Other | Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Operating revenue										(215.0)				(19.0)
Depreciation and amortization										(25.0)
Interest income										5.0		3.0
Income tax expense (benefit)										(78.0)		(94.0)		(104.0)
Net income										(312.0)		74.0		(173.0)
Operating Segments | Power Delivery
Segment Reporting Information [Line Items]
Operating revenue										2,229.0		2,228.0		2,233.0
Depreciation and amortization										625.0		593.0		537.0
Interest income												4.0
Interest and related charges										265.0		265.0		244.0
Income tax expense (benefit)										160.0		334.0		308.0
Net income										587.0		531.0		484.0
Capital expenditures										1,564.0		1,433.0		1,320.0
Total assets		17,800.0				16,700.0				17,800.0		16,700.0
Total assets		17,800.0				16,700.0				17,800.0		16,700.0
Operating Segments | Power Delivery | Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Operating revenue										2,204.0		2,212.0		2,217.0
Depreciation and amortization										624.0		594.0		537.0
Interest income												4.0
Interest and related charges										265.0		265.0		244.0
Income tax expense (benefit)										158.0		334.0		307.0
Net income										586.0		527.0		482.0
Capital expenditures										1,539.0		1,439.0		1,313.0
Total assets		17.6				16.6				17.6		16.6
Total assets		17.6				16.6				17.6		16.6
Operating Segments | Power Generation
Segment Reporting Information [Line Items]
Operating revenue										7,115.0		6,686.0		6,757.0
Depreciation and amortization										746.0		747.0		662.0
Impairment of assets and related charges										1.0
Gains on sales of assets										6.0				4.0
Equity in earnings of equity method investees										18.0		(181.0)		(16.0)
Interest income										90.0		92.0		74.0
Interest and related charges										374.0		342.0		290.0
Income tax expense (benefit)										294.0		373.0		279.0
Net income										1,254.0		1,181.0		1,397.0
Investment in equity method investees		82.0				81.0				82.0		81.0
Capital expenditures										1,321.0		2,275.0		2,440.0
Total assets		28,200.0				29,000.0				28,200.0		29,000.0
Total assets		28,200.0				29,000.0				28,200.0		29,000.0
Operating Segments | Power Generation | Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Operating revenue										5,630.0		5,344.0		5,390.0
Depreciation and amortization										533.0		547.0		488.0
Interest income										9.0		15.0
Interest and related charges										250.0		232.0		219.0
Income tax expense (benefit)										220.0		534.0		524.0
Net income										1,008.0		939.0		909.0
Capital expenditures										1,003.0		1,290.0		$ 1,336.0
Total assets		19.4				18.6				19.4		18.6
Total assets		$ 19.4				$ 18.6				$ 19.4		$ 18.6

[1] See Note 9 for amounts attributable to related parties.

[2] See Note 24 for amounts attributable to related parties.

[3] See Note 24 for amounts attributable to affiliates.

XML

Quarterly Financial and Common Stock Data (Unaudited) (Quarterly Financial and Common Stock Data) (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Condensed Financial Statements, Captions [Line Items]
Operating revenue	$ 3,361	$ 3,451	$ 3,088	$ 3,466	$ 3,210	$ 3,179	$ 2,813	$ 3,384	$ 13,366	[1]	$ 12,586	[1]	$ 11,737	[1]
Income (loss) from operations	834	1,150	742	875	953	1,152	753	1,079	3,601		3,937		3,448
Net income including noncontrolling interests	662	883	478	526	1,333	696	417	674	2,549		3,120		2,212
Net income	$ 641	$ 854	$ 449	$ 503	$ 1,312	$ 665	$ 390	$ 632	$ 2,447		$ 2,999		$ 2,123
Net income attributable to Dominion Energy - Basic	$ 0.97	$ 1.31	$ 0.69	$ 0.77	$ 2.04	$ 1.03	$ 0.62	$ 1.01	$ 3.74		$ 4.72		$ 3.44
Net income attributable to Dominion Energy - Diluted	0.97	1.30	0.69	0.77	2.04	1.03	0.62	1.01	3.74		4.72		3.44
Dividends declared per common share	$ 0.835	$ 0.835	$ 0.835	$ 0.835	$ 0.770	$ 0.770	$ 0.755	$ 0.755	$ 3.34		$ 3.035		$ 2.80
Virginia Electric and Power Company
Condensed Financial Statements, Captions [Line Items]
Operating revenue	$ 1,810	$ 2,232	$ 1,829	$ 1,748	$ 1,824	$ 2,154	$ 1,747	$ 1,831	$ 7,619	[2]	$ 7,556	[2]	$ 7,588	[2]
Income (loss) from operations	418	756	533	364	619	847	613	653	2,071		2,732		2,350
Net income	239	520	339	184	407	459	318	356	1,282		1,540		1,218
Dominion Energy Gas Holdings, LLC
Condensed Financial Statements, Captions [Line Items]
Operating revenue	532	423	459	526	501	401	422	490	1,940	[3]	1,814	[3]	1,638	[3]
Income (loss) from operations	(55)	182	7	201	181	185	116	156	335		638		593
Net income	$ (16)	$ 136	$ 15	$ 166	$ 313	$ 117	$ 77	$ 108	$ 301		$ 615		$ 392

[1] See Note 9 for amounts attributable to related parties.

[2] See Note 24 for amounts attributable to affiliates.

[3] See Note 24 for amounts attributable to related parties.

XML

Quarterly Financial and Common Stock Data (Unaudited) (Narrative) (Detail) - USD ($) $ in Millions	3 Months Ended				12 Months Ended
	Dec. 31, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Parent Company Only Financial Information [Line Items]
After-tax gains from the sale of certain merchant generation facilities	$ 536
After-tax impairment charge for certain gathering and processing assets	164
After-taxcharge for disallowance of FERC-regulated plant		$ 89
After-taxcharge associated with Virginia legislation			$ 160
Tax benefit resulting from remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act				$ (851)	$ 46	$ (851)	$ 0
Charges associated with equity method investments in wind-powered generation facilities, after tax						96
Virginia Electric and Power Company
Parent Company Only Financial Information [Line Items]
After-taxcharge associated with Virginia legislation			$ 160
Tax benefit resulting from remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act				(93)	21	(93)	0
Dominion Energy Gas Holdings, LLC
Parent Company Only Financial Information [Line Items]
After-tax gains from the sale of certain merchant generation facilities	$ 165
After-taxcharge for disallowance of FERC-regulated plant		$ 89
Tax benefit resulting from remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act				$ (197)	$ (11)	$ (197)	$ 0