EX-99.1 3 d592099dex991.htm EX-99.1

Exhibit 99.1

Glossary of Terms

The following abbreviations or acronyms used in this Form 8-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
2015 Biennial Review Order |  | Order issued by the Virginia Commission in November 2015 concluding the 2013—2014 biennial review of Virginia Power’s base rates, terms and conditions
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
ABO |  | Accumulated benefit obligation
AFUDC |  | Allowance for funds used during construction
AMR |  | Automated meter reading program deployed by East Ohio
AOCI |  | Accumulated other comprehensive income (loss)
APCo |  | Appalachian Power Company
ARO |  | Asset retirement obligation
Atlantic Coast Pipeline |  | Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion Energy, Duke and Southern Company Gas
BACT |  | Best available control technology
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
Blue Racer |  | Blue Racer Midstream, LLC, a joint venture between Dominion Energy and Caiman
BREDL |  | Blue Ridge Environmental Defense League
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
CCR |  | Coal combustion residual
CERCLA |  | Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund
CGN Committee |  | Compensation, Governance and Nominating Committee of Dominion Energy’s Board of Directors
CNG |  | Consolidated Natural Gas Company
CO2 |  | Carbon dioxide
COL |  | Combined Construction Permit and Operating License
Companies |  | Dominion Energy, Virginia Power and Dominion Energy Gas, collectively
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
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.
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 GP Holding Company, LLC, Iroquois GP Holding Company, LLC, DECG and Dominion Energy Questar Pipeline (beginning December 1, 2016) or operating segment, 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 operating segment, 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

|  |  |  | 1

Abbreviation or Acronym |  | Definition
Dominion Energy Questar Pipeline |  | Dominion Energy Questar Pipeline, LLC (formerly known as Questar Pipeline, LLC), one or more of its consolidated subsidiaries, or the entirety of Dominion Energy Questar Pipeline, LLC and its consolidated subsidiaries
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
East Ohio |  | The East Ohio Gas Company, doing business as Dominion Energy Ohio
EPA |  | U.S. Environmental Protection Agency
EPS |  | Earnings per share
ERISA |  | Employee Retirement Income Security Act of 1974
ERM |  | Enterprise Risk Management
FASB |  | Financial Accounting Standards Board
FERC |  | Federal Energy Regulatory Commission
Four Brothers |  | Four Brothers Solar, LLC, a limited liability company owned by Dominion Energy and Four Brothers Holdings, LLC, a wholly-owned subsidiary of NRG effective November 2016
Fowler Ridge |  | Fowler I Holdings LLC, a wind-turbine facility joint venture with BP Wind Energy North America Inc. in Benton County, Indiana
FTA |  | Free Trade Agreement
FTRs |  | Financial transmission rights
GAAP |  | U.S. generally accepted accounting principles
Gas Infrastructure |  | Gas Infrastructure Group operating segment
GHG |  | Greenhouse gas
Granite Mountain |  | Granite Mountain Holdings, LLC, a limited liability company owned by Dominion Energy and Granite Mountain Renewables, LLC, a wholly-owned subsidiary of NRG effective November 2016
Green Mountain |  | Green Mountain Power Corporation
Greensville County |  | An approximately 1,588 MW natural gas-fired combined-cycle power station under construction in Greensville County, Virginia
HATFA of 2014 |  | Highway and Transportation Funding Act of 2014
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 wholly-owned subsidiary of NRG effective November 2016
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
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
MAP 21 Act |  | Moving Ahead for Progress in the 21st Century Act
Massachusetts Municipal |  | Massachusetts Municipal Wholesale Electric Company
MATS |  | Utility Mercury and Air Toxics Standard Rule
mcfe |  | Thousand cubic feet equivalent
MGD |  | Million gallons a day
Millstone |  | Millstone nuclear power station
MISO |  | Midcontinent Independent System Operator, Inc.
Morgans Corner |  | Morgans Corner Solar Energy, LLC
MW |  | Megawatt
MWh |  | Megawatt hour
NAV |  | Net asset value
NedPower |  | NedPower Mount Storm LLC, a wind-turbine facility joint venture between Dominion Energy and Shell Wind Energy, Inc. in Grant County, West Virginia

2 |  |  |  |

Abbreviation or Acronym |  | Definition
NEIL |  | Nuclear Electric Insurance Limited
NGL |  | Natural gas liquid
NJNR |  | NJNR Pipeline Company
North Anna |  | North Anna nuclear power station
North Carolina Commission |  | North Carolina Utilities Commission
NOX |  | Nitrogen oxide
NRC |  | Nuclear Regulatory Commission
NRG |  | The legal entity, NRG Energy, Inc., one or more of its consolidated subsidiaries (including, effective November 2016, Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC and Iron Springs Renewables, LLC) or operating segments, or the entirety of NRG Energy, Inc. and its consolidated subsidiaries
NSPS |  | New Source Performance Standards
NYSE |  | New York Stock Exchange
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
Philadelphia Utility Index |  | Philadelphia Stock Exchange Utility Index
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
Questar Gas |  | Questar Gas Company
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
Rider B |  | A rate adjustment clause associated with the recovery of costs related to the conversion of three of Virginia Power’s coal-fired power stations to biomass
Rider BW |  | A rate adjustment clause associated with the recovery of costs related to Brunswick County
Rider GV |  | A rate adjustment clause associated with the recovery of costs related to Greensville County
Rider R |  | A rate adjustment clause associated with the recovery of costs related to Bear Garden
Rider S |  | A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center
Rider T1 |  | A rate adjustment clause to recover the difference between revenues produced from transmission rates included in base rates, and the new total revenue requirement developed annually for the rate years effective September 1
Rider 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 Woodland, Scott Solar and Whitehouse
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
RTO |  | Regional transmission organization
SBL Holdco |  | SBL Holdco, LLC, a wholly-owned subsidiary of DGI
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
SCANA Merger Agreement |  | Agreement and plan of merger entered on January 2, 2018 between Dominion Energy and SCANA in which SCANA will become a wholly-owned subsidiary of Dominion Energy upon closing
SCE&G |  | South Carolina Electric & Gas Company, a wholly-owned subsidiary of SCANA
Scott Solar |  | A 17 MW utility-scale solar power station in Powhatan County, VA
SEC |  | Securities and Exchange Commission
September 2006 hybrids |  | Dominion Energy’s 2006 Series B Enhanced Junior Subordinated Notes due 2066
South Carolina Commission |  | South Carolina Public Service Commission

|  |  |  | 3

Abbreviation or Acronym |  | Definition
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
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
Western System |  | Collection of approximately 212 miles of various diameter natural gas pipelines and three compressor stations in Ohio
Wexpro |  | The legal entity, Wexpro Company, one or more of its consolidated subsidiaries, or the entirety of Wexpro Company and its consolidated subsidiaries
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

4 |  |  |  |

Item 8. Financial Statements and Supplementary Data

|  | Page Number |
Dominion Energy, Inc. |  |  |  |
Report of Independent Registered Public Accounting Firm |  |  | 6 |
Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015 |  |  | 7 |
Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 2016 and 2015 |  |  | 8 |
Consolidated Balance Sheets at December 31, 2017 and 2016 |  |  | 9 |
Consolidated Statements of Equity for the years ended December 31, 2017, 2016 and 2015 |  |  | 11 |
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015 |  |  | 12 |
Virginia Electric and Power Company |  |  |  |
Report of Independent Registered Public Accounting Firm |  |  | 14 |
Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015 |  |  | 15 |
Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 2016 and 2015 |  |  | 16 |
Consolidated Balance Sheets at December 31, 2017 and 2016 |  |  | 17 |
Consolidated Statements of Common Shareholder’s Equity for the years ended December 31, 2017, 2016 and 2015 |  |  | 19 |
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015 |  |  | 20 |
Dominion Energy Gas Holdings, LLC |  |  |  |
Report of Independent Registered Public Accounting Firm |  |  | 22 |
Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015 |  |  | 23 |
Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 2016 and 2015 |  |  | 24 |
Consolidated Balance Sheets at December 31, 2017 and 2016 |  |  | 25 |
Consolidated Statements of Equity for the years ended December 31, 2017, 2016 and 2015 |  |  | 27 |
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015 |  |  | 28 |
Combined Notes to Consolidated Financial Statements |  |  | 30 |

|  |  |  | 5

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, 2017 and 2016, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2017, 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 27, 2018 (not presented herein), 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 27, 2018, except for the impact of the matters

discussed in Note 2 pertaining to the adoption of revised accounting

guidance related to certain net periodic pension and other postretirement

benefit costs, restricted cash and equivalents and certain

distributions from equity method investees, as to which the date

is June 6, 2018

We have served as Dominion Energy’s auditor since 1988.

6 |  |  |  |

Dominion Energy, Inc.

Consolidated Statements of Income

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions, except per share amounts) |  |  |  |  |  |  |  |  |
Operating Revenue(1) |  | $ | 12,586 |  |  | $ | 11,737 |  |  | $ | 11,683 |
Operating Expenses |  |  |  |  |  |  |  |  |  |  |  |
Electric fuel and other energy-related purchases |  |  | 2,301 |  |  |  | 2,333 |  |  |  | 2,725 |
Purchased electric capacity |  |  | 6 |  |  |  | 99 |  |  |  | 330 |
Purchased gas |  |  | 701 |  |  |  | 459 |  |  |  | 551 |
Other operations and maintenance |  |  | 3,068 |  |  |  | 3,243 |  |  |  | 2,711 |
Depreciation, depletion and amortization |  |  | 1,905 |  |  |  | 1,559 |  |  |  | 1,395 |
Other taxes |  |  | 668 |  |  |  | 596 |  |  |  | 551 |
Total operating expenses |  |  | 8,649 |  |  |  | 8,289 |  |  |  | 8,263 |
Income from operations |  |  | 3,937 |  |  |  | 3,448 |  |  |  | 3,420 |
Other income(1) |  |  | 358 |  |  |  | 429 |  |  |  | 312 |
Interest and related charges |  |  | 1,205 |  |  |  | 1,010 |  |  |  | 904 |
Income from operations including noncontrolling interests before income tax expense (benefit) |  |  | 3,090 |  |  |  | 2,867 |  |  |  | 2,828 |
Income tax expense (benefit) |  |  | (30 | ) |  |  | 655 |  |  |  | 905 |
Net Income Including Noncontrolling Interests |  |  | 3,120 |  |  |  | 2,212 |  |  |  | 1,923 |
Noncontrolling Interests |  |  | 121 |  |  |  | 89 |  |  |  | 24 |
Net Income Attributable to Dominion Energy |  |  | 2,999 |  |  |  | 2,123 |  |  |  | 1,899 |
Earnings Per Common Share |  |  |  |  |  |  |  |  |  |  |  |
Net income attributable to Dominion Energy—Basic |  | $ | 4.72 |  |  | $ | 3.44 |  |  | $ | 3.21 |
Net income attributable to Dominion Energy—Diluted |  | $ | 4.72 |  |  | $ | 3.44 |  |  | $ | 3.20 |
Dividends Declared Per Common Share |  | $ | 3.035 |  |  | $ | 2.80 |  |  | $ | 2.59 |

(1) | See Note 9 for amounts attributable to related parties.

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

|  |  |  | 7

Dominion Energy, Inc.

Consolidated Statements of Comprehensive Income

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Net income including noncontrolling interests |  | $ | 3,120 |  |  | $ | 2,212 |  |  | $ | 1,923 |
Other comprehensive income (loss), net of taxes: |  |  |  |  |  |  |  |  |  |  |  |
Net deferred gains on derivatives-hedging activities, net of $(3), $(37) and $(74) tax |  |  | 8 |  |  |  | 55 |  |  |  | 110 |
Changes in unrealized net gains on investment securities, net of $(121), $(53) and $23 tax |  |  | 215 |  |  |  | 93 |  |  |  | 6 |
Changes in net unrecognized pension and other postretirement benefit costs, net of $32, $189 and $29 tax |  |  | (69 | ) |  |  | (319 | ) |  |  | (66 | )
Amounts reclassified to net income: |  |  |  |  |  |  |  |  |  |  |  |
Net derivative gains-hedging activities, net of $18, $100 and $68 tax |  |  | (29 | ) |  |  | (159 | ) |  |  | (108 | )
Net realized gains on investment securities, net of $21, $15 and $29 tax |  |  | (37 | ) |  |  | (28 | ) |  |  | (50 | )
Net pension and other postretirement benefit costs, net of $(32), $(22) and $(35) tax |  |  | 50 |  |  |  | 34 |  |  |  | 51 |
Changes in other comprehensive income (loss) from equity method investees, net of $(2), $— and $1 tax |  |  | 3 |  |  |  | (1 | ) |  |  | (1 | )
Total other comprehensive income (loss) |  |  | 141 |  |  |  | (325 | ) |  |  | (58 | )
Comprehensive income including noncontrolling interests |  |  | 3,261 |  |  |  | 1,887 |  |  |  | 1,865 |
Comprehensive income attributable to noncontrolling interests |  |  | 122 |  |  |  | 89 |  |  |  | 24 |
Comprehensive income attributable to Dominion Energy |  | $ | 3,139 |  |  | $ | 1,798 |  |  | $ | 1,841 |

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

8 |  |  |  |

Dominion Energy, Inc.

Consolidated Balance Sheets

At December 31, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
ASSETS |  |  |  |  |  |  |  |
Current Assets |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 120 |  |  | $ | 261 |
Customer receivables (less allowance for doubtful accounts of $17 and $18) |  |  | 1,660 |  |  |  | 1,523 |
Other receivables (less allowance for doubtful accounts of $2 at both dates)(1) |  |  | 126 |  |  |  | 183 |
Inventories |  |  |  |  |  |  |  |
Materials and supplies |  |  | 1,049 |  |  |  | 1,087 |
Fossil fuel |  |  | 328 |  |  |  | 341 |
Gas Stored |  |  | 100 |  |  |  | 96 |
Prepayments |  |  | 260 |  |  |  | 194 |
Regulatory assets |  |  | 294 |  |  |  | 244 |
Other |  |  | 397 |  |  |  | 319 |
Total current assets |  |  | 4,334 |  |  |  | 4,248 |
Investments |  |  |  |  |  |  |  |
Nuclear decommissioning trust funds |  |  | 5,093 |  |  |  | 4,484 |
Investment in equity method affiliates |  |  | 1,544 |  |  |  | 1,561 |
Other |  |  | 327 |  |  |  | 298 |
Total investments |  |  | 6,964 |  |  |  | 6,343 |
Property, Plant and Equipment |  |  |  |  |  |  |  |
Property, plant and equipment |  |  | 74,823 |  |  |  | 69,556 |
Accumulated depreciation, depletion and amortization |  |  | (21,065 | ) |  |  | (19,592 | )
Total property, plant and equipment, net |  |  | 53,758 |  |  |  | 49,964 |
Deferred Charges and Other Assets |  |  |  |  |  |  |  |
Goodwill |  |  | 6,405 |  |  |  | 6,399 |
Pension and other postretirement benefit assets |  |  | 1,378 |  |  |  | 1,078 |
Intangible assets, net |  |  | 685 |  |  |  | 618 |
Regulatory assets |  |  | 2,480 |  |  |  | 2,473 |
Other |  |  | 581 |  |  |  | 487 |
Total deferred charges and other assets |  |  | 11,529 |  |  |  | 11,055 |
Total assets |  | $ | 76,585 |  |  | $ | 71,610 |

(1) | See Note 9 for amounts attributable to related parties.

|  |  |  | 9

At December 31, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
LIABILITIES AND EQUITY |  |  |  |  |  |  |  |
Current Liabilities |  |  |  |  |  |  |  |
Securities due within one year |  | $ | 3,078 |  |  | $ | 1,709 |
Short-term debt |  |  | 3,298 |  |  |  | 3,155 |
Accounts payable |  |  | 875 |  |  |  | 1,000 |
Accrued interest, payroll and taxes |  |  | 848 |  |  |  | 798 |
Other(1) |  |  | 1,537 |  |  |  | 1,453 |
Total current liabilities |  |  | 9,636 |  |  |  | 8,115 |
Long-Term Debt |  |  |  |  |  |  |  |
Long-term debt |  |  | 25,588 |  |  |  | 24,878 |
Junior subordinated notes |  |  | 3,981 |  |  |  | 2,980 |
Remarketable subordinated notes |  |  | 1,379 |  |  |  | 2,373 |
Total long-term debt |  |  | 30,948 |  |  |  | 30,231 |
Deferred Credits and Other Liabilities |  |  |  |  |  |  |  |
Deferred income taxes and investment tax credits |  |  | 4,523 |  |  |  | 8,602 |
Regulatory liabilities |  |  | 6,916 |  |  |  | 2,622 |
Asset retirement obligations |  |  | 2,169 |  |  |  | 2,236 |
Pension and other postretirement benefit liability |  |  | 2,160 |  |  |  | 2,112 |
Other(1) |  |  | 863 |  |  |  | 852 |
Total deferred credits and other liabilities |  |  | 16,631 |  |  |  | 16,424 |
Total liabilities |  |  | 57,215 |  |  |  | 54,770 |
Commitments and Contingencies (see Note 22) |  |  |  |  |  |  |  |
Equity |  |  |  |  |  |  |  |
Common stock-no par(2) |  |  | 9,865 |  |  |  | 8,550 |
Retained earnings |  |  | 7,936 |  |  |  | 6,854 |
Accumulated other comprehensive loss |  |  | (659 | ) |  |  | (799 | )
Total common shareholders’ equity |  |  | 17,142 |  |  |  | 14,605 |
Noncontrolling interests |  |  | 2,228 |  |  |  | 2,235 |
Total equity |  |  | 19,370 |  |  |  | 16,840 |
Total liabilities and equity |  | $ | 76,585 |  |  | $ | 71,610 |

(1) | See Notes 3 and 9 for amounts attributable to related parties.

(2) | 1 billion shares authorized; 645 million shares and 628 million shares outstanding at December 31, 2017 and 2016, respectively.

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

10 |  |  |  |

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, 2014 |  |  | 585 |  |  | $ | 5,876 |  |  | $ | 6,095 |  |  |  | $(416 | ) |  |  | $11,555 |  |  |  | $ 402 |  |  | $ | 11,957 |
Net income including noncontrolling interests |  |  |  |  |  |  |  |  |  |  | 1,899 |  |  |  |  |  |  |  | 1,899 |  |  |  | 24 |  |  |  | 1,923 |
Dominion Energy Midstream’s acquisition of interest in Iroquois |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | — |  |  |  | 216 |  |  |  | 216 |
Acquisition of Four Brothers and Three Cedars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | — |  |  |  | 47 |  |  |  | 47 |
Contributions from SunEdison to Four Brothers and Three Cedars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | — |  |  |  | 103 |  |  |  | 103 |
Sale of interest in merchant solar projects |  |  |  |  |  |  | 26 |  |  |  |  |  |  |  |  |  |  |  | 26 |  |  |  | 179 |  |  |  | 205 |
Purchase of Dominion Energy Midstream common units |  |  |  |  |  |  | (6 | ) |  |  |  |  |  |  |  |  |  |  | (6 | ) |  |  | (19 | ) |  |  | (25 | )
Issuance of common stock |  |  | 11 |  |  |  | 786 |  |  |  |  |  |  |  |  |  |  |  | 786 |  |  |  |  |  |  |  | 786 |
Stock awards (net of change in unearned compensation) |  |  |  |  |  |  | 13 |  |  |  |  |  |  |  |  |  |  |  | 13 |  |  |  |  |  |  |  | 13 |
Dividends |  |  |  |  |  |  |  |  |  |  | (1,536 | ) |  |  |  |  |  |  | (1,536 | ) |  |  |  |  |  |  | (1,536 | )
Dominion Energy Midstream distributions |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | — |  |  |  | (16 | ) |  |  | (16 | )
Other comprehensive loss, net of tax |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (58 | ) |  |  | (58 | ) |  |  |  |  |  |  | (58 | )
Other |  |  |  |  |  |  | (15 | ) |  |  |  |  |  |  |  |  |  |  | (15 | ) |  |  | 2 |  |  |  | (13 | )
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 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 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 |

(1) | See Note 17 for further information.

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

|  |  |  | 11

Dominion Energy, Inc.

Consolidated Statements of Cash Flows

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Operating Activities |  |  |  |  |  |  |  |  |  |  |  |
Net income including noncontrolling interests |  | $ | 3,120 |  |  | $ | 2,212 |  |  | $ | 1,923 |
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities: |  |  |  |  |  |  |  |  |  |  |  |
Depreciation, depletion and amortization (including nuclear fuel) |  |  | 2,202 |  |  |  | 1,849 |  |  |  | 1,669 |
Deferred income taxes and investment tax credits |  |  | (3 | ) |  |  | 725 |  |  |  | 854 |
Current income tax for Dominion Energy Questar Pipeline contribution to Dominion Energy Midstream |  |  | — |  |  |  | (212 | ) |  |  | — |
Proceeds from assignment of tower rental portfolio |  |  | 91 |  |  |  | — |  |  |  | — |
Gains on the sales of assets |  |  | (148 | ) |  |  | (50 | ) |  |  | (123 | )
Charges associated with equity method investments |  |  | 158 |  |  |  | — |  |  |  | — |
Charges associated with future ash pond and landfill closure costs |  |  | — |  |  |  | 197 |  |  |  | 99 |
Contribution to pension plan |  |  | (75 | ) |  |  | — |  |  |  | — |
Other adjustments |  |  | (84 | ) |  |  | (84 | ) |  |  | (26 | )
Changes in: |  |  |  |  |  |  |  |  |  |  |  |
Accounts receivable |  |  | (103 | ) |  |  | (286 | ) |  |  | 294 |
Inventories |  |  | 15 |  |  |  | 1 |  |  |  | (26 | )
Deferred fuel and purchased gas costs, net |  |  | (71 | ) |  |  | 54 |  |  |  | 94 |
Prepayments |  |  | (62 | ) |  |  | 21 |  |  |  | (25 | )
Accounts payable |  |  | (89 | ) |  |  | 97 |  |  |  | (199 | )
Accrued interest, payroll and taxes |  |  | 64 |  |  |  | 203 |  |  |  | (52 | )
Margin deposit assets and liabilities |  |  | (10 | ) |  |  | (66 | ) |  |  | 237 |
Net realized and unrealized changes related to derivative activities |  |  | 44 |  |  |  | (335 | ) |  |  | (176 | )
Asset retirement obligations |  |  | (94 | ) |  |  | (61 | ) |  |  | (4 | )
Pension and other postretirement benefits |  |  | (177 | ) |  |  | (152 | ) |  |  | (51 | )
Other operating assets and liabilities |  |  | (276 | ) |  |  | 38 |  |  |  | 3 |
Net cash provided by operating activities |  |  | 4,502 |  |  |  | 4,151 |  |  |  | 4,491 |
Investing Activities |  |  |  |  |  |  |  |  |  |  |  |
Plant construction and other property additions (including nuclear fuel) |  |  | (5,504 | ) |  |  | (6,085 | ) |  |  | (5,575 | )
Acquisition of Dominion Energy Questar, net of cash acquired |  |  | — |  |  |  | (4,381 | ) |  |  | — |
Acquisition of solar development projects |  |  | (405 | ) |  |  | (40 | ) |  |  | (418 | )
Acquisition of DECG |  |  | — |  |  |  | — |  |  |  | (497 | )
Proceeds from sales of securities |  |  | 1,831 |  |  |  | 1,422 |  |  |  | 1,340 |
Purchases of securities |  |  | (1,940 | ) |  |  | (1,504 | ) |  |  | (1,326 | )
Sale of certain retail energy marketing assets |  |  | 68 |  |  |  | — |  |  |  | — |
Proceeds from assignment of shale development rights |  |  | 70 |  |  |  | 10 |  |  |  | 79 |
Contributions to equity method affiliates |  |  | (370 | ) |  |  | (198 | ) |  |  | (51 | )
Distributions from equity method affiliates |  |  | 275 |  |  |  | 2 |  |  |  | — |
Other |  |  | 33 |  |  |  | 83 |  |  |  | (65 | )
Net cash used in investing activities |  |  | (5,942 | ) |  |  | (10,691 | ) |  |  | (6,513 | )
Financing Activities |  |  |  |  |  |  |  |  |  |  |  |
Issuance (repayment) of short-term debt, net |  |  | 143 |  |  |  | (654 | ) |  |  | 734 |
Issuance of short-term notes |  |  | — |  |  |  | 1,200 |  |  |  | 600 |
Repayment and repurchase of short-term notes |  |  | (250 | ) |  |  | (1,800 | ) |  |  | (400 | )
Issuance and remarketing of long-term debt |  |  | 3,880 |  |  |  | 7,722 |  |  |  | 2,962 |
Repayment and repurchase of long-term debt |  |  | (1,572 | ) |  |  | (1,610 | ) |  |  | (892 | )
Net proceeds from issuance of Dominion Energy Midstream common units |  |  | 18 |  |  |  | 482 |  |  |  | — |
Net proceeds from issuance of Dominion Energy Midstream preferred units |  |  | — |  |  |  | 490 |  |  |  | — |
Proceeds from sale of interest in merchant solar projects |  |  | — |  |  |  | 117 |  |  |  | 184 |
Contributions from NRG and SunEdison to Four Brothers and Three Cedars |  |  | 9 |  |  |  | 189 |  |  |  | 103 |
Issuance of common stock |  |  | 1,302 |  |  |  | 2,152 |  |  |  | 786 |
Common dividend payments |  |  | (1,931 | ) |  |  | (1,727 | ) |  |  | (1,536 | )
Other |  |  | (296 | ) |  |  | (331 | ) |  |  | (224 | )
Net cash provided by financing activities |  |  | 1,303 |  |  |  | 6,230 |  |  |  | 2,317 |
Increase (decrease) in cash, restricted cash and equivalents |  |  | (137 | ) |  |  | (310 | ) |  |  | 295 |
Cash, restricted cash and equivalents at beginning of year |  |  | 322 |  |  |  | 632 |  |  |  | 337 |
Cash, restricted cash and equivalents at end of year |  | $ | 185 |  |  | $ | 322 |  |  | $ | 632 |
Supplemental Cash Flow Information |  |  |  |  |  |  |  |  |  |  |  |
Cash paid during the year for: |  |  |  |  |  |  |  |  |  |  |  |
Interest and related charges, excluding capitalized amounts |  | $ | 1,083 |  |  | $ | 905 |  |  | $ | 843 |
Income taxes |  |  | 9 |  |  |  | 145 |  |  |  | 75 |
Significant noncash investing and financing activities:(1)(2) |  |  |  |  |  |  |  |  |  |  |  |
Accrued capital expenditures |  |  | 343 |  |  |  | 427 |  |  |  | 478 |
Guarantee provided to equity method affiliate |  |  | 30 |  |  |  | — |  |  |  | — |
Dominion Energy Midstream’s acquisition of a noncontrolling partnership interest in Iroquois in exchange for issuance of Dominion Energy Midstream common units |  |  | — |  |  |  | — |  |  |  | 216 |

(1) | See Note 3 for noncash activities related to the acquisition of Four Brothers and Three Cedars.

(2) | See Note 17 for noncash activities related to the remarketing of RSNs in 2017 and 2016.

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

12 |  |  |  |

[THIS PAGE INTENTIONALLY LEFT BLANK]

|  |  |  | 13

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, 2017 and 2016, 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, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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 27, 2018, except for the impact of the matters

discussed in Note 2 pertaining to the adoption of revised

accounting guidance related to restricted cash and

equivalents, as to which the date is June 6, 2018

We have served as Virginia Power’s auditor since 1988.

14 |  |  |  |

Virginia Electric and Power Company

Consolidated Statements of Income

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Operating Revenue(1) |  | $ | 7,556 |  |  | $ | 7,588 |  |  | $ | 7,622 |
Operating Expenses |  |  |  |  |  |  |  |  |  |  |  |
Electric fuel and other energy-related purchases(1) |  |  | 1,909 |  |  |  | 1,973 |  |  |  | 2,320 |
Purchased electric capacity |  |  | 6 |  |  |  | 99 |  |  |  | 330 |
Other operations and maintenance: |  |  |  |  |  |  |  |  |  |  |  |
Affiliated suppliers |  |  | 309 |  |  |  | 310 |  |  |  | 279 |
Other |  |  | 1,169 |  |  |  | 1,547 |  |  |  | 1,355 |
Depreciation and amortization |  |  | 1,141 |  |  |  | 1,025 |  |  |  | 953 |
Other taxes |  |  | 290 |  |  |  | 284 |  |  |  | 264 |
Total operating expenses |  |  | 4,824 |  |  |  | 5,238 |  |  |  | 5,501 |
Income from operations |  |  | 2,732 |  |  |  | 2,350 |  |  |  | 2,121 |
Other income |  |  | 76 |  |  |  | 56 |  |  |  | 68 |
Interest and related charges(1) |  |  | 494 |  |  |  | 461 |  |  |  | 443 |
Income from operations before income tax expense |  |  | 2,314 |  |  |  | 1,945 |  |  |  | 1,746 |
Income tax expense |  |  | 774 |  |  |  | 727 |  |  |  | 659 |
Net Income |  | $ | 1,540 |  |  | $ | 1,218 |  |  | $ | 1,087 |

(1) | See Note 24 for amounts attributable to affiliates.

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

|  |  |  | 15

Virginia Electric and Power Company

Consolidated Statements of Comprehensive Income

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Net income |  | $ | 1,540 |  |  | $ | 1,218 |  |  | $ | 1,087 |
Other comprehensive income (loss), net of taxes: |  |  |  |  |  |  |  |  |  |  |  |
Net deferred losses on derivatives-hedging activities, net of $3, $1 and $2 tax |  |  | (5 | ) |  |  | (2 | ) |  |  | (1 | )
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds, net of $(16), $(7) and $1 tax |  |  | 24 |  |  |  | 11 |  |  |  | (4 | )
Amounts reclassified to net income: |  |  |  |  |  |  |  |  |  |  |  |
Net derivative losses on derivative-hedging activities, net of $—, $— and $— tax |  |  | 1 |  |  |  | 1 |  |  |  | 1 |
Net realized gains on nuclear decommissioning trust funds, net of $3, $2 and $4 tax |  |  | (4 | ) |  |  | (4 | ) |  |  | (6 | )
Total other comprehensive income (loss) |  |  | 16 |  |  |  | 6 |  |  |  | (10 | )
Comprehensive income |  | $ | 1,556 |  |  | $ | 1,224 |  |  | $ | 1,077 |

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

16 |  |  |  |

Virginia Electric and Power Company

Consolidated Balance Sheets

At December 31, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
ASSETS |  |  |  |  |  |  |  |
Current Assets |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 14 |  |  | $ | 11 |
Customer receivables (less allowance for doubtful accounts of $10 at both dates) |  |  | 951 |  |  |  | 892 |
Other receivables (less allowance for doubtful accounts of $1 at both dates) |  |  | 64 |  |  |  | 99 |
Affiliated receivables |  |  | 3 |  |  |  | 112 |
Inventories (average cost method) |  |  |  |  |  |  |  |
Materials and supplies |  |  | 531 |  |  |  | 525 |
Fossil fuel |  |  | 319 |  |  |  | 328 |
Prepayments |  |  | 27 |  |  |  | 30 |
Regulatory assets |  |  | 205 |  |  |  | 179 |
Other(1) |  |  | 110 |  |  |  | 72 |
Total current assets |  |  | 2,224 |  |  |  | 2,248 |
Investments |  |  |  |  |  |  |  |
Nuclear decommissioning trust funds |  |  | 2,399 |  |  |  | 2,106 |
Other |  |  | 3 |  |  |  | 3 |
Total investments |  |  | 2,402 |  |  |  | 2,109 |
Property, Plant and Equipment |  |  |  |  |  |  |  |
Property, plant and equipment |  |  | 42,329 |  |  |  | 40,030 |
Accumulated depreciation and amortization |  |  | (13,277 | ) |  |  | (12,436 | )
Total property, plant and equipment, net |  |  | 29,052 |  |  |  | 27,594 |
Deferred Charges and Other Assets |  |  |  |  |  |  |  |
Pension and other postretirement benefit assets(1) |  |  | 199 |  |  |  | 130 |
Intangible assets, net |  |  | 233 |  |  |  | 225 |
Regulatory assets |  |  | 810 |  |  |  | 770 |
Derivative assets(1) |  |  | 91 |  |  |  | 128 |
Other |  |  | 128 |  |  |  | 104 |
Total deferred charges and other assets |  |  | 1,461 |  |  |  | 1,357 |
Total assets |  | $ | 35,139 |  |  | $ | 33,308 |

(1) | See Note 24 for amounts attributable to affiliates.

|  |  |  | 17

At December 31, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
LIABILITIES AND SHAREHOLDER’S EQUITY |  |  |  |  |  |  |  |
Current Liabilities |  |  |  |  |  |  |  |
Securities due within one year |  | $ | 850 |  |  | $ | 678 |
Short-term debt |  |  | 542 |  |  |  | 65 |
Accounts payable |  |  | 361 |  |  |  | 444 |
Payables to affiliates |  |  | 125 |  |  |  | 109 |
Affiliated current borrowings |  |  | 33 |  |  |  | 262 |
Accrued interest, payroll and taxes |  |  | 256 |  |  |  | 239 |
Asset retirement obligations |  |  | 216 |  |  |  | 181 |
Other(1) |  |  | 537 |  |  |  | 544 |
Total current liabilities |  |  | 2,920 |  |  |  | 2,522 |
Long-Term Debt |  |  | 10,496 |  |  |  | 9,852 |
Deferred Credits and Other Liabilities |  |  |  |  |  |  |  |
Deferred income taxes and investment tax credits |  |  | 2,728 |  |  |  | 5,103 |
Asset retirement obligations |  |  | 1,149 |  |  |  | 1,262 |
Regulatory liabilities |  |  | 4,760 |  |  |  | 1,962 |
Pension and other postretirement benefit liabilities(1) |  |  | 505 |  |  |  | 396 |
Other |  |  | 357 |  |  |  | 346 |
Total deferred credits and other liabilities |  |  | 9,499 |  |  |  | 9,069 |
Total liabilities |  |  | 22,915 |  |  |  | 21,443 |
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 |  |  | 5,311 |  |  |  | 4,968 |
Accumulated other comprehensive income |  |  | 62 |  |  |  | 46 |
Total common shareholder’s equity |  |  | 12,224 |  |  |  | 11,865 |
Total liabilities and shareholder’s equity |  | $ | 35,139 |  |  | $ | 33,308 |

(1) | See Note 24 for amounts attributable to affiliates.

(2) | 500,000 shares authorized; 274,723 shares outstanding at December 31, 2017 and 2016.

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

18 |  |  |  |

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) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Balance at December 31, 2014 |  |  | 275 |  |  | $ | 5,738 |  |  | $ | 1,113 |  |  | $ | 3,154 |  |  |  | $ 50 |  |  | $ | 10,055 |
Net income |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,087 |  |  |  |  |  |  |  | 1,087 |
Dividends |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (491 | ) |  |  |  |  |  |  | (491 | )
Other comprehensive loss, net of tax |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (10 | ) |  |  | (10 | )
Balance at 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 |
Balance at 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 |
Balance at December 31, 2017 |  |  | 275 |  |  | $ | 5,738 |  |  | $ | 1,113 |  |  | $ | 5,311 |  |  |  | $ 62 |  |  | $ | 12,224 |

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

|  |  |  | 19

Virginia Electric and Power Company

Consolidated Statements of Cash Flows

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Operating Activities |  |  |  |  |  |  |  |  |  |  |  |
Net income |  | $ | 1,540 |  |  | $ | 1,218 |  |  | $ | 1,087 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and amortization (including nuclear fuel) |  |  | 1,333 |  |  |  | 1,210 |  |  |  | 1,121 |
Deferred income taxes and investment tax credits |  |  | 269 |  |  |  | 469 |  |  |  | 251 |
Proceeds from assignment of rental portfolio |  |  | 91 |  |  |  | — |  |  |  | — |
Charges associated with future ash pond and landfill closure costs |  |  | — |  |  |  | 197 |  |  |  | 99 |
Other adjustments |  |  | (36 | ) |  |  | (16 | ) |  |  | (27 | )
Changes in: |  |  |  |  |  |  |  |  |  |  |  |
Accounts receivable |  |  | (27 | ) |  |  | (65 | ) |  |  | 128 |
Affiliated accounts receivable and payable |  |  | 125 |  |  |  | 220 |  |  |  | (314 | )
Inventories |  |  | 3 |  |  |  | 20 |  |  |  | (20 | )
Prepayments |  |  | 3 |  |  |  | 8 |  |  |  | 214 |
Deferred fuel expenses, net |  |  | (59 | ) |  |  | 69 |  |  |  | 64 |
Accounts payable |  |  | (42 | ) |  |  | 25 |  |  |  | (75 | )
Accrued interest, payroll and taxes |  |  | 17 |  |  |  | 49 |  |  |  | (9 | )
Net realized and unrealized changes related to derivative activities |  |  | 13 |  |  |  | (153 | ) |  |  | (67 | )
Asset retirement obligations |  |  | (88 | ) |  |  | (59 | ) |  |  | 10 |
Other operating assets and liabilities |  |  | (181 | ) |  |  | 77 |  |  |  | 93 |
Net cash provided by operating activities |  |  | 2,961 |  |  |  | 3,269 |  |  |  | 2,555 |
Investing Activities |  |  |  |  |  |  |  |  |  |  |  |
Plant construction and other property additions |  |  | (2,496 | ) |  |  | (2,489 | ) |  |  | (2,474 | )
Purchases of nuclear fuel |  |  | (192 | ) |  |  | (153 | ) |  |  | (172 | )
Acquisition of solar development projects |  |  | (41 | ) |  |  | (7 | ) |  |  | (43 | )
Purchases of securities |  |  | (884 | ) |  |  | (775 | ) |  |  | (651 | )
Proceeds from sales of securities |  |  | 849 |  |  |  | 733 |  |  |  | 639 |
Other |  |  | (41 | ) |  |  | (33 | ) |  |  | (87 | )
Net cash used in investing activities |  |  | (2,805 | ) |  |  | (2,724 | ) |  |  | (2,788 | )
Financing Activities |  |  |  |  |  |  |  |  |  |  |  |
Issuance (repayment) of short-term debt, net |  |  | 477 |  |  |  | (1,591 | ) |  |  | 295 |
Repayment of affiliated current borrowings, net |  |  | (229 | ) |  |  | (114 | ) |  |  | (51 | )
Issuance and remarketing of long-term debt |  |  | 1,500 |  |  |  | 1,688 |  |  |  | 1,112 |
Repayment of long-term debt |  |  | (681 | ) |  |  | (517 | ) |  |  | (625 | )
Common dividend payments to parent |  |  | (1,199 | ) |  |  | — |  |  |  | (491 | )
Other |  |  | (11 | ) |  |  | (18 | ) |  |  | (4 | )
Net cash provided by (used in) financing activities |  |  | (143 | ) |  |  | (552 | ) |  |  | 236 |
Increase (decrease) in cash, restricted cash and equivalents |  |  | 13 |  |  |  | (7 | ) |  |  | 3 |
Cash, restricted cash and equivalents at beginning of year |  |  | 11 |  |  |  | 18 |  |  |  | 15 |
Cash, restricted cash and equivalents at end of year |  | $ | 24 |  |  | $ | 11 |  |  | $ | 18 |
Supplemental Cash Flow Information |  |  |  |  |  |  |  |  |  |  |  |
Cash paid during the year for: |  |  |  |  |  |  |  |  |  |  |  |
Interest and related charges, excluding capitalized amounts |  | $ | 458 |  |  | $ | 435 |  |  | $ | 422 |
Income taxes |  |  | 362 |  |  |  | 79 |  |  |  | 517 |
Significant noncash investing activities: |  |  |  |  |  |  |  |  |  |  |  |
Accrued capital expenditures |  |  | 169 |  |  |  | 256 |  |  |  | 169 |

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

20 |  |  |  |

[THIS PAGE INTENTIONALLY LEFT BLANK]

|  |  |  | 21

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, 2017 and 2016, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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 27, 2018, except for the impact of the matters

discussed in Note 2 pertaining to the adoption of revised accounting

guidance related to certain net periodic pension and other postretirement

benefit costs, restricted cash and equivalents and certain

distributions from equity method investees, as to which the date

is June 6, 2018

We have served as Dominion Energy Gas’ auditor since 2012.

22 |  |  |  |

Dominion Energy Gas Holdings, LLC

Consolidated Statements of Income

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Operating Revenue(1) |  | $ | 1,814 |  |  | $ | 1,638 |  |  | $ | 1,716 |
Operating Expenses |  |  |  |  |  |  |  |  |  |  |  |
Purchased gas(1) |  |  | 132 |  |  |  | 109 |  |  |  | 133 |
Other energy-related purchases(1) |  |  | 21 |  |  |  | 12 |  |  |  | 21 |
Other operations and maintenance: |  |  |  |  |  |  |  |  |  |  |  |
Affiliated suppliers |  |  | 87 |  |  |  | 81 |  |  |  | 64 |
Other(1) |  |  | 524 |  |  |  | 469 |  |  |  | 388 |
Depreciation and amortization |  |  | 227 |  |  |  | 204 |  |  |  | 217 |
Other taxes |  |  | 185 |  |  |  | 170 |  |  |  | 166 |
Total operating expenses |  |  | 1,176 |  |  |  | 1,045 |  |  |  | 989 |
Income from operations |  |  | 638 |  |  |  | 593 |  |  |  | 727 |
Earnings from equity method investee |  |  | 21 |  |  |  | 21 |  |  |  | 23 |
Other income |  |  | 104 |  |  |  | 87 |  |  |  | 63 |
Interest and related charges(1) |  |  | 97 |  |  |  | 94 |  |  |  | 73 |
Income from operations before income tax expense |  |  | 666 |  |  |  | 607 |  |  |  | 740 |
Income tax expense |  |  | 51 |  |  |  | 215 |  |  |  | 283 |
Net Income |  | $ | 615 |  |  | $ | 392 |  |  | $ | 457 |

(1) | See Note 24 for amounts attributable to related parties.

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

|  |  |  | 23

Dominion Energy Gas Holdings, LLC

Consolidated Statements of Comprehensive Income

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Net income |  | $ | 615 |  |  | $ | 392 |  |  | $ | 457 |
Other comprehensive income (loss), net of taxes: |  |  |  |  |  |  |  |  |  |  |  |
Net deferred gains (losses) on derivatives-hedging activities, net of $(3), $10, and $(4) tax |  |  | 5 |  |  |  | (16 | ) |  |  | 6 |
Changes in unrecognized pension benefit (costs), net of $(8), $14, and $13 tax |  |  | 20 |  |  |  | (20 | ) |  |  | (20 | )
Amounts reclassified to net income: |  |  |  |  |  |  |  |  |  |  |  |
Net derivative (gains) losses, net of $3, $(6), and $3 tax |  |  | (4 | ) |  |  | 9 |  |  |  | (3 | )
Net pension and other postretirement benefit costs, net of $(2), $(2), and $(3) tax |  |  | 4 |  |  |  | 3 |  |  |  | 4 |
Other comprehensive income (loss) |  |  | 25 |  |  |  | (24 | ) |  |  | (13 | )
Comprehensive income |  | $ | 640 |  |  | $ | 368 |  |  | $ | 444 |

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

24 |  |  |  |

Dominion Energy Gas Holdings, LLC

Consolidated Balance Sheets

At December 31, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
ASSETS |  |  |  |  |  |  |  |
Current Assets |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 4 |  |  | $ | 23 |
Customer receivables (less allowance for doubtful accounts of $1 at both dates)(1) |  |  | 297 |  |  |  | 281 |
Other receivables (less allowance for doubtful accounts of $1 at both dates)(1) |  |  | 15 |  |  |  | 13 |
Affiliated receivables |  |  | 10 |  |  |  | 17 |
Inventories: |  |  |  |  |  |  |  |
Materials and supplies |  |  | 55 |  |  |  | 57 |
Gas stored |  |  | 9 |  |  |  | 13 |
Prepayments |  |  | 112 |  |  |  | 94 |
Gas imbalances(1) |  |  | 46 |  |  |  | 37 |
Other |  |  | 52 |  |  |  | 47 |
Total current assets |  |  | 600 |  |  |  | 582 |
Investments |  |  | 97 |  |  |  | 99 |
Property, Plant and Equipment |  |  |  |  |  |  |  |
Property, plant and equipment |  |  | 11,173 |  |  |  | 10,475 |
Accumulated depreciation and amortization |  |  | (3,018 | ) |  |  | (2,851 | )
Total property, plant and equipment, net |  |  | 8,155 |  |  |  | 7,624 |
Deferred Charges and Other Assets |  |  |  |  |  |  |  |
Goodwill |  |  | 542 |  |  |  | 542 |
Intangible assets, net |  |  | 109 |  |  |  | 98 |
Regulatory assets |  |  | 511 |  |  |  | 577 |
Pension and other postretirement benefit assets(1) |  |  | 1,828 |  |  |  | 1,557 |
Other(1) |  |  | 98 |  |  |  | 63 |
Total deferred charges and other assets |  |  | 3,088 |  |  |  | 2,837 |
Total assets |  | $ | 11,940 |  |  | $ | 11,142 |

(1) | See Note 24 for amounts attributable to related parties.

|  |  |  | 25

At December 31, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
LIABILITIES AND EQUITY |  |  |  |  |  |  |  |
Current Liabilities |  |  |  |  |  |  |  |
Short-term debt |  | $ | 629 |  |  | $ | 460 |
Accounts payable |  |  | 193 |  |  |  | 221 |
Payables to affiliates |  |  | 62 |  |  |  | 29 |
Affiliated current borrowings |  |  | 18 |  |  |  | 118 |
Accrued interest, payroll and taxes |  |  | 250 |  |  |  | 225 |
Other(1) |  |  | 189 |  |  |  | 162 |
Total current liabilities |  |  | 1,341 |  |  |  | 1,215 |
Long-Term Debt |  |  | 3,570 |  |  |  | 3,528 |
Deferred Credits and Other Liabilities |  |  |  |  |  |  |  |
Deferred income taxes and investment tax credits |  |  | 1,454 |  |  |  | 2,438 |
Regulatory liabilities |  |  | 1,227 |  |  |  | 219 |
Other(1) |  |  | 185 |  |  |  | 206 |
Total deferred credits and other liabilities |  |  | 2,866 |  |  |  | 2,863 |
Total liabilities |  |  | 7,777 |  |  |  | 7,606 |
Commitments and Contingencies (see Note 22) |  |  |  |  |  |  |  |
Equity |  |  |  |  |  |  |  |
Membership interests |  |  | 4,261 |  |  |  | 3,659 |
Accumulated other comprehensive loss |  |  | (98 | ) |  |  | (123 | )
Total equity |  |  | 4,163 |  |  |  | 3,536 |
Total liabilities and equity |  | $ | 11,940 |  |  | $ | 11,142 |

(1) | See Note 24 for amounts attributable to related parties.

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

26 |  |  |  |

Dominion Energy Gas Holdings, LLC

Consolidated Statements of Equity

|  | Membership Interests |  |  | Accumulated Other Comprehensive Income (Loss) |  |  | Total |
(millions) |  |  |  |  |  |  |  |  |
Balance at December 31, 2014 |  |  | $3,652 |  |  |  | $ (86 | ) |  | $ | 3,566 |
Net income |  |  | 457 |  |  |  |  |  |  |  | 457 |
Distributions |  |  | (692 | ) |  |  |  |  |  |  | (692 | )
Other comprehensive loss, net of tax |  |  |  |  |  |  | (13 | ) |  |  | (13 | )
Balance at December 31, 2015 |  |  | 3,417 |  |  |  | (99 | ) |  |  | 3,318 |
Net income |  |  | 392 |  |  |  |  |  |  |  | 392 |
Distributions |  |  | (150 | ) |  |  |  |  |  |  | (150 | )
Other comprehensive loss, net of tax |  |  |  |  |  |  | (24 | ) |  |  | (24 | )
Balance at 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 |
Balance at December 31, 2017 |  |  | $4,261 |  |  |  | $ (98 | ) |  | $ | 4,163 |

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

|  |  |  | 27

Dominion Energy Gas Holdings, LLC

Consolidated Statements of Cash Flows

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Operating Activities |  |  |  |  |  |  |  |  |  |  |  |
Net income |  | $ | 615 |  |  | $ | 392 |  |  | $ | 457 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |  |  |  |  |  |
Gains on sales of assets |  |  | (70 | ) |  |  | (50 | ) |  |  | (123 | )
Depreciation and amortization |  |  | 227 |  |  |  | 204 |  |  |  | 217 |
Deferred income taxes and investment tax credits |  |  | 27 |  |  |  | 238 |  |  |  | 163 |
Other adjustments |  |  | (7 | ) |  |  | (6 | ) |  |  | 23 |
Changes in: |  |  |  |  |  |  |  |  |  |  |  |
Accounts receivable |  |  | (17 | ) |  |  | (68 | ) |  |  | 115 |
Affiliated receivables and payables |  |  | 40 |  |  |  | 88 |  |  |  | (105 | )
Inventories |  |  | 6 |  |  |  | 8 |  |  |  | (13 | )
Prepayments |  |  | (18 | ) |  |  | (6 | ) |  |  | 99 |
Accounts payable |  |  | (17 | ) |  |  | 15 |  |  |  | (51 | )
Accrued interest, payroll and taxes |  |  | 24 |  |  |  | 42 |  |  |  | (11 | )
Pension and other postretirement benefits |  |  | (143 | ) |  |  | (141 | ) |  |  | (119 | )
Other operating assets and liabilities |  |  | (1 | ) |  |  | (68 | ) |  |  | (17 | )
Net cash provided by operating activities |  |  | 666 |  |  |  | 648 |  |  |  | 635 |
Investing Activities |  |  |  |  |  |  |  |  |  |  |  |
Plant construction and other property additions |  |  | (778 | ) |  |  | (854 | ) |  |  | (795 | )
Proceeds from sale of equity method investment in Iroquois |  |  | — |  |  |  | 7 |  |  |  | — |
Proceeds from assignments of shale development rights |  |  | 70 |  |  |  | 10 |  |  |  | 79 |
Other |  |  | (19 | ) |  |  | (12 | ) |  |  | (17 | )
Net cash used in investing activities |  |  | (727 | ) |  |  | (849 | ) |  |  | (733 | )
Financing Activities |  |  |  |  |  |  |  |  |  |  |  |
Issuance of short-term debt, net |  |  | 169 |  |  |  | 69 |  |  |  | 391 |
Issuance (repayment) of affiliated current borrowings, net |  |  | (100 | ) |  |  | 23 |  |  |  | (289 | )
Repayment of long-term debt |  |  | — |  |  |  | (400 | ) |  |  | — |
Issuance of long-term debt |  |  | — |  |  |  | 680 |  |  |  | 700 |
Distribution payments to parent |  |  | (15 | ) |  |  | (150 | ) |  |  | (692 | )
Other |  |  | (6 | ) |  |  | (5 | ) |  |  | (7 | )
Net cash provided by financing activities |  |  | 48 |  |  |  | 217 |  |  |  | 103 |
Increase (decrease) in cash, restricted cash and equivalents |  |  | (13 | ) |  |  | 16 |  |  |  | 5 |
Cash, restricted cash and equivalents at beginning of year |  |  | 43 |  |  |  | 27 |  |  |  | 22 |
Cash, restricted cash and equivalents at end of year |  | $ | 30 |  |  | $ | 43 |  |  | $ | 27 |
Supplemental Cash Flow Information |  |  |  |  |  |  |  |  |  |  |  |
Cash paid (received) during the year for: |  |  |  |  |  |  |  |  |  |  |  |
Interest and related charges, excluding capitalized amounts |  | $ | 89 |  |  | $ | 81 |  |  | $ | 70 |
Income taxes |  |  | 9 |  |  |  | (92 | ) |  |  | 98 |
Significant noncash investing and financing activities: |  |  |  |  |  |  |  |  |  |  |  |
Accrued capital expenditures |  |  | 38 |  |  |  | 59 |  |  |  | 57 |

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

28 |  |  |  |

[THIS PAGE INTENTIONALLY LEFT BLANK]

|  |  |  | 29

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 Dominion Energy Questar Combination was completed in September 2016. See Note 3 for a description of operations acquired in the Dominion Energy Questar Combination.

Dominion Energy’s operations also include the Cove Point LNG import, transport and storage facility in Maryland, an equity investment in Atlantic Coast Pipeline and regulated gas transportation and distribution operations in West Virginia. Dominion Energy’s nonregulated operations include merchant generation, energy marketing and price risk management activities, retail energy marketing operations and an equity investment in Blue Racer.

In October 2014, Dominion Energy Midstream launched its initial public offering of 20,125,000 common units representing limited partner interests. At December 31, 2017, Dominion Energy owns the general partner, 50.6% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owns 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. The public’s ownership interest in Dominion Energy Midstream is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements.

Dominion Energy manages 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.

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, the accounts 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. NRG’s ownership interest in Four Brothers and Three Cedars, as well as Terra Nova Renewable Partners’ 33% interest in certain of Dominion Energy’s merchant solar projects, is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. See Note 3 for further information on these transactions.

The Companies report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements.

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, 2016 and 2015 Consolidated Financial Statements and Notes have been reclassified as a result of the adoption of revised accounting guidance pertaining to certain net periodic pension and other postretirement benefit costs, restricted cash and equivalents and certain distributions from equity method investees. In addition, certain other amounts in the 2016 and 2015 Consolidated Financial Statements and Notes have been reclassified to conform to the 2017 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

30 |  |  |  |

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, 2017 and 2016 included $661 million and $631 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, 2017 and 2016 included $400 million and $349 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, 2017 and 2016 included $121 million and $134 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas delivered but not yet billed to its customers. See Note 9 for amounts attributable to related parties.

The primary types of sales and service activities reported as operating revenue for Dominion Energy are as follows:

• |  | 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 derivative activity;

• |  | Regulated gas sales consist primarily of state- and FERC-regulated natural gas sales and related distribution services and associated derivative activity;

• |  | 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, gas trading and marketing revenue and associated derivative activity;

• |  | Gas transportation and storage consists primarily of FERC-regulated sales of transmission and storage services. Also included are state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services; and

• |  | Other revenue consists primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also includes 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 are as follows:

• |  | Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services; and

• |  | Other revenue consists 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 are as follows:

• |  | Regulated gas sales consist primarily of state- and FERC-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 and sales of gas purchased from third parties. Revenue from sales of gas production is recognized based on actual volumes of gas sold to purchasers and is reported net of royalties;

• |  | Gas transportation and storage consists primarily of FERC-regulated sales of transmission and storage services. Also included are state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

• |  | NGL revenue consists primarily of sales of NGL production and condensate, extracted products and associated derivative activity; and

• |  | Other revenue consists primarily of miscellaneous service revenue, gas processing and handling revenue.

Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs

Where permitted by regulatory authorities, the differences between Dominion Energy’s and Virginia Power’s actual electric fuel and purchased energy expenses and Dominion Energy’s 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, approximately 84% is currently 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’s, Questar Gas’ and Hope’s 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.

31

Combined Notes to Consolidated Financial Statements, Continued

The 2017 Tax Reform Act includes 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 is 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 are 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.

Dominion Energy and Virginia Power both recognized interest income of $11 million in 2017. Dominion Energy Gas’ interest was immaterial in 2017. Interest for the Companies was immaterial in 2016 and 2015. Dominion Energy’s, Virginia Power’s and Dominion Energy Gas’ penalties were immaterial in 2017, 2016 and 2015.

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 are expected to be 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.

At December 31, 2016, Virginia Power had an income tax-related affiliated receivable of $112 million, comprised of $122 million of federal income taxes due from Dominion Energy net of $10 million for state income taxes due to Dominion Energy. Dominion Energy Gas also had an affiliated receivable of $11 million due from Dominion Energy, representing $10 million of federal income taxes and $1 million of state income taxes. The net affiliated receivables were refunded by Dominion Energy.

In addition, Virginia Power’s Consolidated Balance Sheet at December 31, 2016 included $2 million of noncurrent federal income taxes payable, $6 million of state income taxes receivable and $13 million of noncurrent state income taxes receivable. Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2016 included $1 million of noncurrent federal income taxes payable, $1 million of state income taxes receivable and $7 million of noncurrent state income taxes payable.

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

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:

Year Ended December 31, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
Dominion Energy |  | $ | 30 |  |  | $ | 24 |
Virginia Power |  |  | 17 |  |  |  | 11 |
Dominion Energy Gas |  |  | 7 |  |  |  | 9 |

32 |  |  |  |

RESTRICTED CASH AND EQUIVALENTS

The Companies hold restricted cash and equivalent balances that primarily consist of amounts held for certain customer deposits, future debt payments on SBL Holdco and Dominion Solar Projects III, Inc.’s term loan agreements and a distribution reserve at Cove Point. Upon adoption of revised accounting guidance in January 2018, restricted cash and equivalents are included within the Companies’ Consolidated Statements of Cash Flows, with the change in balance no longer considered a separate investing activity. The guidance required retrospective application which resulted in adjustments to other cash provided by (used in) investing activities presented within Dominion Energy, Virginia Power and Dominion Energy Gas’ Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015, which were previously reported as follows:

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Dominion Energy |  | $ | 29 |  |  | $ | 47 |  |  | $ | (71 | )
Virginia Power |  |  | (51 | ) |  |  | (33 | ) |  |  | (87 | )
Dominion Energy Gas |  |  | (23 | ) |  |  | (18 | ) |  |  | (11 | )

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, 2017, 2016 and 2015:

|  | Cash, Restricted Cash and Equivalents at End/Beginning of Year |
At December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |  |  | 2014 |
(millions) |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 120 |  |  | $ | 261 |  |  | $ | 607 |  |  | $ | 318 |
Restricted cash and equivalents(1) |  |  | 65 |  |  |  | 61 |  |  |  | 25 |  |  |  | 19 |
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows |  | $ | 185 |  |  | $ | 322 |  |  | $ | 632 |  |  | $ | 337 |
Virginia Power |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 14 |  |  | $ | 11 |  |  | $ | 18 |  |  | $ | 15 |
Restricted cash and equivalents(1) |  |  | 10 |  |  |  | — |  |  |  | — |  |  |  | — |
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows |  | $ | 24 |  |  | $ | 11 |  |  | $ | 18 |  |  | $ | 15 |
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 4 |  |  | $ | 23 |  |  | $ | 13 |  |  | $ | 9 |
Restricted cash and equivalents(1) |  |  | 26 |  |  |  | 20 |  |  |  | 14 |  |  |  | 13 |
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows |  | $ | 30 |  |  | $ | 43 |  |  | $ | 27 |  |  | $ | 22 |

(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. Effective January 2018, 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. Dis-

tributions 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. Previously, distributions were determined to be either a return on an investment or return of an investment based on a cumulative earnings approach whereby any distributions received in excess of earnings were considered to be a return of an investment. Dominion Energy and Dominion Energy Gas have applied this approach on a retrospective basis. As a result distributions from equity method investees were reclassified within the Consolidated Statements of Cash Flows between distributions from equity method affiliates and other cash used in investing activities at Dominion Energy and Dominion Energy Gas, respectively, to other adjustments from operating activities for both Dominion Energy and Dominion Energy Gas, which were previously reported as follows:

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Dominion Energy |  | $ | (37 | ) |  | $ | (108 | ) |  | $ | (42 | )
Dominion Energy Gas |  |  | (9 | ) |  |  | (6 | ) |  |  | 16 |

For purposes of the Consolidated Statements of Cash Flows, 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.

Derivative Instruments

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 $92 million and $82 million associated with cash collateral at

33

Combined Notes to Consolidated Financial Statements, Continued

December 31, 2017 and 2016, respectively. Dominion Energy’s margin liabilities associated with cash collateral at December 31, 2017 or 2016 were immaterial. Virginia Power had margin assets of $23 million and $2 million associated with cash collateral at December 31, 2017 and 2016, respectively. Virginia Power’s margin liabilities associated with cash collateral were immaterial at December 31, 2017 and 2016. Dominion Energy Gas’ margin assets and liabilities associated with cash collateral were immaterial at December 31, 2017 and 2016. 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

The Companies designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For all derivatives designated as hedges, the Companies formally document the relationship between the hedging instrument and the hedged item, as well as the risk management objective and the strategy for using the hedging instrument. The Companies assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, the Companies may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges. 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 also uses fair value hedges to mitigate the fixed price exposure inherent in commodity inventory. In addition, Dominion Energy has designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. 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 2017, 2016 and 2015, Dominion Energy capitalized interest costs and AFUDC to property, plant and equipment of $236 million, $159 million and $100 million, respectively. In 2017, 2016 and 2015, Virginia Power capitalized AFUDC to property, plant and equipment of $37 million, $21 million and $30 million, respectively. In 2017, 2016 and 2015, Dominion Energy Gas capitalized AFUDC to property, plant and equipment of $25 million, $8 million and $1 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 2017, 2016 and 2015, Virginia Power recorded $22 million, $31 million and $19 million of AFUDC related to these projects, respectively.

For property subject to cost-of-service rate regulation, including 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 prop-

34 |  |  |  |

erty, 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.

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, |  | 2017 |  |  | 2016 |  |  | 2015 |
(percent) |  |  |  |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |
Generation |  |  | 2.94 |  |  |  | 2.83 |  |  |  | 2.78 |
Transmission |  |  | 2.55 |  |  |  | 2.47 |  |  |  | 2.42 |
Distribution |  |  | 3.00 |  |  |  | 3.02 |  |  |  | 3.11 |
Storage |  |  | 2.48 |  |  |  | 2.29 |  |  |  | 2.42 |
Gas gathering and processing |  |  | 2.21 |  |  |  | 2.66 |  |  |  | 3.19 |
General and other |  |  | 4.89 |  |  |  | 4.12 |  |  |  | 3.67 |
Virginia Power |  |  |  |  |  |  |  |  |  |  |  |
Generation |  |  | 2.94 |  |  |  | 2.83 |  |  |  | 2.78 |
Transmission |  |  | 2.54 |  |  |  | 2.36 |  |  |  | 2.33 |
Distribution |  |  | 3.32 |  |  |  | 3.32 |  |  |  | 3.33 |
General and other |  |  | 4.68 |  |  |  | 3.49 |  |  |  | 3.40 |
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |
Transmission |  |  | 2.40 |  |  |  | 2.43 |  |  |  | 2.46 |
Distribution |  |  | 2.42 |  |  |  | 2.55 |  |  |  | 2.45 |
Storage |  |  | 2.45 |  |  |  | 2.19 |  |  |  | 2.44 |
Gas gathering and processing |  |  | 2.42 |  |  |  | 2.58 |  |  |  | 3.20 |
General and other |  |  | 4.96 |  |  |  | 4.54 |  |  |  | 4.72 |

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 $2.11 per mcfe in 2017.

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 |  |  | 15-40 years |
Nonutility gas gathering and processing |  |  | 3-50 years |
General and other |  |  | 5-59 years |

Depreciation and amortization related to Virginia Power’s and Dominion Energy Gas’ nonutility property, plant and equipment and exploration and production properties was immaterial for the years ended December 31, 2017, 2016 and 2015, 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.

Regulatory Assets and Liabilities

The accounting for Dominion Energy’s and Dominion Energy Gas’ regulated gas 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

|  |  |  | 35

Combined Notes to Consolidated Financial Statements, Continued

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. Virginia Power reports 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, Virginia Power reports 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 over the lives of the new issuances.

Investments

MARKETABLE EQUITY AND DEBT SECURITIES

Dominion Energy accounts for and classifies investments in marketable equity and debt securities as trading or available-for-sale securities. Virginia Power classifies investments in marketable equity and debt securities as available-for-sale securities.

• |  | Trading securities include marketable equity and debt 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.

• |  | Available-for-sale securities include all other marketable equity and 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 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 marketable equity and debt securities, the cost basis of the security is based on the specific identification method.

NON-M ARKETABLE INVESTMENTS

The Companies account for illiquid and privately held securities for which market prices or quotations are not readily available under either the equity or cost method. Non-marketable investments 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 Virginia Power’s investments are included in other investments in their Consolidated Balance Sheets. The Companies record equity method adjustments in other income in the 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’s and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds.

OTHER-THAN-TEMPORARY IMPAIRMENT

The Companies periodically review their investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in 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

• |  | The recognition provisions of the FASB’s other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities.

• |  | Debt Securities—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

36 |  |  |  |

|  | 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.

• |  | Equity securities and other investments—Dominion Energy’s and Virginia Power’s method of assessing other-than-temporary declines requires demonstrating the ability to hold individual securities for a period of time sufficient to allow for the anticipated recovery in their market value prior to the consideration of the other criteria mentioned above. Since Dominion Energy and Virginia Power have limited ability to oversee the day-to-day management of nuclear decommissioning trust fund investments, they do not have the ability to ensure investments are held through an anticipated recovery period. Accordingly, they consider all equity and other securities as well as non-marketable investments held in nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired.

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 $9 million and $13 million at December 31, 2017 and December 31, 2016, respectively. Based on the average price of gas purchased during 2017 and 2016, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $79 million and $55 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 core principle of this revised accounting guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consid-

eration to which the entity expects to be entitled in exchange for those goods or services. The amendments in this update also require disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For the Companies, the revised accounting guidance is effective for interim and annual periods beginning January 1, 2018. The Companies have completed their evaluations of the impact of this guidance and expect no significant impact on their results of operations. However, the Companies will have offsetting increases in operating revenues and other energy-related purchases for noncash consideration related to NGLs received in consideration for performing processing and fractionation services and offsetting decreases in operating revenues and purchased gas for fuel retained to offset costs on certain transportation and storage arrangements. The Companies will apply the standard using the modified retrospective method as opposed to the full retrospective method.

FINANCIAL INSTRUMENTS

In January 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of financial instruments. In accordance with the guidance effective January 2018, Dominion Energy and Virginia Power will no longer classify equity securities as trading or available-for-sale securities. All equity securities with a readily determinable fair value, or for which it is permitted to estimate fair value using NAV (or its equivalent), including those held in Dominion Energy’s and Virginia Power’s nuclear decommissioning trusts and Dominion Energy’s rabbi trusts, will be reported at fair value in nuclear decommissioning trust funds and other investments, respectively, 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 will be 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. Net realized and unrealized gains and losses on equity securities held in Virginia Power’s nuclear decommissioning trusts will be 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 will be included in other income. Dominion Energy and Virginia Power will qualitatively assess equity securities reported using the measurement alternative to evaluate whether the investment is impaired on an ongoing basis.

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 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 approx-

|  |  |  | 37

Combined Notes to Consolidated Financial Statements, Continued

imately $36 million ($22 million after-tax) in net unrealized gains on equity securities previously classified as cost method investments of which $4 million was recorded to retained earnings and $32 million was recorded to regulatory liabilities for net unrealized gains subject to cost-based regulation. The potential impact to the Consolidated Statements of Income is subject to investment price risk and is therefore difficult to reasonably estimate. If this guidance had been effective January 1, 2017, Dominion Energy and Virginia Power would have recorded net unrealized gains of approximately $275 million ($176 million after-tax) and $30 million ($19 million after-tax), respectively, to other income in the Consolidated Statements of Income.

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, although it can be early adopted, with a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented for leases that commenced prior to the date of adoption. The Companies plan to elect the proposed transition expedient which would allow the Companies to maintain historical presentation for periods before January 1, 2019. The Companies expect to elect the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases and no reassessment of lease classification for existing leases. The Companies have completed a preliminary assessment for evaluating the impact of this guidance and anticipate that its adoption will result in a significant amount of offsetting right-of-use assets and liabilities on their financial position for leases in effect at the adoption date. No material changes are expected on the Companies’ results of operations. The Companies are beginning implementation activities that primarily include accumulating contracts and lease data points in formats compatible with a new lease management system that will assist with the initial adoption and on-going compliance with the standard.

DEFINITION OF A BUSINESS

In January 2017, the FASB issued revised accounting guidance to clarify the definition of a business. The revised guidance affects the evaluation of whether a transaction should be accounted for as an acquisition or disposition of an asset or a business, which may impact goodwill and related financial statement disclosures. The Companies have adopted this guidance on a prospective basis effective October 1, 2017. The adoption of the pronouncement will result in additional transactions being accounted for as asset acquisitions or dispositions.

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 is effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, and the Companies have elected to apply the standard using the modified retrospective method. Upon adoption of the standard on January 1, 2018, 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. The update 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.

This guidance became effective for the Companies beginning January 1, 2018 with a retrospective adoption for income statement presentation and a prospective adoption for capitalization. Dominion Energy’s and Dominion Energy Gas’ Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015 have been recast to reflect retrospective adoption for the presentation of the non-service cost component of net periodic pension and other postretirement benefit costs. Previously, the non-service cost component for Dominion Energy and Dominion Energy Gas was reflected in other operations and maintenance in the Consolidated Statements of Income, along with the service cost component of net periodic pension and other postretirement benefit costs. Subsequent to the adoption of this guidance, the non-service cost component of net periodic pension and other postretirement benefit costs is recorded in other income in the Consolidated Statements of Income. As previously

38 |  |  |  |

reported, Dominion Energy and Dominion Energy Gas’ other operations and maintenance expense and other income were as follows:

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |
Other operations and maintenance expense |  | $ | 2,875 |  |  | $ | 3,064 |  |  | $ | 2,595 |
Other income |  |  | 165 |  |  |  | 250 |  |  |  | 196 |
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |
Other operations and maintenance expense |  |  | 440 |  |  |  | 393 |  |  |  | 326 |
Other income |  |  | 20 |  |  |  | 11 |  |  |  | 1 |

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 provides for up to a one-year measurement period in which to complete the required analyses and accounting. The guidance describes 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. In addition, the guidance provides clarification related to disclosures for entities which are utilizing the measurement period. The Companies have recorded their best estimate of the impacts of the 2017 Tax Reform Act as discussed above and in Note 5. The amounts are considered to be provisional and may result in adjustments to be recognized during the measurement period.

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 guidance is effective for the Companies’ interim and annual reporting periods beginning January 1, 2019, with early adoption permitted, and may be applied prospectively or retrospectively upon adoption. If the Companies had adopted this guidance for the period ended December 31, 2017, Dominion Energy would have reclassified a benefit of $165 million from AOCI to retained earnings, Dominion Energy Gas would have reclassified a benefit of $26 million from AOCI to membership interests and Virginia Power would have reclassified an expense of $13 million from AOCI to retained earnings.

NOTE 3. ACQUISITIONS AND DISPOSITIONS

DOMINION ENERGY

Proposed Acquisition of SCANA

Under the terms of the SCANA Merger Agreement announced in January 2018, Dominion Energy has agreed to issue 0.6690 shares of Dominion Energy common stock for each share of

SCANA common stock upon closing. In addition, Dominion Energy will provide the financial support for SCE&G to make a $1.3 billion up-front, one-time rate credit to all current electric service customers of SCE&G to be paid within 90 days of closing and a $575 million refund along with the benefit of the 2017 Tax Reform Act resulting in at least a 5% reduction to SCE&G electric service customers’ bills over an eight-year period as well as the exclusions from rate recovery of approximately $1.7 billion of costs related to the V.C. Summer Units 2 and 3 new nuclear development project and approximately $180 million to purchase the Columbia Energy Center power station. In addition, SCANA’s debt, which currently totals approximately $7.0 billion, is expected to remain outstanding.

The transaction requires approval of SCANA’s shareholders, FERC and the NRC and clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act. In February 2018, the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Act. In January 2018, SCANA and Dominion Energy filed for review and approval, as required, from the South Carolina Commission, the North Carolina Commission, the Georgia Public Service Commission and the NRC. Dominion Energy is not required to accept an order by the South Carolina Commission approving Dominion Energy’s merger with SCANA if such order contains any material change to the terms, conditions or undertakings set forth in the cost recovery plan related to the V.C. Summer Units 2 and 3 new nuclear development project or any significant changes to the economic value of the cost recovery plan. In addition, the SCANA Merger Agreement provides that Dominion Energy will have the right to refuse to close the merger if there shall have occurred any substantive change in the Base Load Review Act or other laws governing South Carolina public utilities which has or would reasonably be expected to have an adverse effect on SCE&G. The SCANA Merger Agreement contains certain termination rights for both Dominion Energy and SCANA, and provides that, upon termination of the SCANA Combination under specified circumstances, Dominion Energy would be required to pay a termination fee of $280 million to SCANA and SCANA would be required to pay Dominion Energy a termination fee of $240 million. Subject to receipt of SCANA shareholder and any required regulatory approvals and meeting closing conditions, Dominion Energy targets closing by the end of 2018.

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, became a wholly-owned subsidiary of Dominion Energy. Dominion Energy Questar included Questar Gas, Wexpro and Dominion Energy Questar Pipeline at closing. 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

|  |  |  | 39

Combined Notes to Consolidated Financial Statements, Continued

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. See Notes 17 and 19 for more information.

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 recog-

nized 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(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, 2017, 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.

40 |  |  |  |

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 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 2017 and 2016, of which $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, 2015. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.

|  | Twelve Months Ended December 31, |
|  | 2016(1) |  |  | 2015 |
(millions, except EPS) |  |  |  |  |  |
Operating Revenue |  |  | $12,497 |  |  |  | $12,818 |
Net income attributable to Dominion Energy |  |  | 2,300 |  |  |  | 2,108 |
Earnings Per Common Share – Basic |  |  | $ 3.73 |  |  |  | $ 3.56 |
Earnings Per Common Share – Diluted |  |  | $ 3.73 |  |  |  | $ 3.55 |

(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.

41

Combined Notes to Consolidated Financial Statements, Continued

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 |
April 2015 |  | EC&R NA Solar PV, LLC |  |  | 1 |  |  | California |  | Alamo |  |  | $ 66 |  |  |  | $ 66 |  |  | May 2015 |  |  | 20 |
April 2015 |  | EDF Renewable Development, Inc. |  |  | 3 |  |  | California |  | Cottonwood(3) |  |  | 106 |  |  |  | 106 |  |  | May 2015 |  |  | 24 |
June 2015 |  | EDF Renewable Development, Inc. |  |  | 1 |  |  | California |  | Catalina 2 |  |  | 68 |  |  |  | 68 |  |  | July 2015 |  |  | 18 |
July 2015 |  | SunPeak Solar, LLC |  |  | 1 |  |  | California |  | Imperial Valley 2 |  |  | 42 |  |  |  | 71 |  |  | August 2015 |  |  | 20 |
November 2015 |  | EC&R NA Solar PV, LLC |  |  | 1 |  |  | California |  | Maricopa West |  |  | 65 |  |  |  | 65 |  |  | December 2015 |  |  | 20 |
November 2015 |  | Community Energy Solar, LLC |  |  | 1 |  |  | Virginia |  | Amazon Solar Farm U.S East |  |  | 34 |  |  |  | 212 |  |  | October 2016 |  |  | 80 |
February 2017 |  | Community Energy Solar, LLC |  |  | 1 |  |  | Virginia |  | Amazon Solar Farm Virginia—Southampton |  |  | 29 |  |  |  | 205 |  |  | December 2017 |  |  | 100 |
March 2017 |  | Solar Frontier Americas Holding LLC |  |  | 1 | (4) |  | 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) | One of the projects, Marin Carport, began commercial operations in 2016.

(4) | 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 or will claim 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, including certain projects in the table above. In December 2015, the sale of interest in 15 of the solar projects closed for $184 million with the sale of interest in the remaining projects completed in January 2016 for $117 million. Upon closing, SunEdison sold its interest in these projects to Terra Nova Renewable Partners. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion Energy’s remaining 67% ownership in the projects upon the occurrence of certain events, none of which are expected to occur in 2018.

42 |  |  |  |

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, consisting of $2 million in cash and a $62 million payable. Dominion Energy had no remaining obligation related to this payable at December 31, 2016. 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, consisting of $6 million in cash and a $37 million payable. There was a $2 million payable included in other current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2016. Dominion has no remaining obligation related to this payable at December 31, 2017. 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 owns 50% of the voting interests in Four Brothers and Three Cedars and has a controlling financial interest over the entities through its rights to control operations. The allocation of the $64 million purchase price for Four Brothers resulted in $89 million of property, plant and equipment and $25 million of noncontrolling interest. The allocation of the $43 million purchase price for Three Cedars resulted in $65 million of property, plant and equipment and $22 million of noncontrolling interest. The noncontrolling interest for each entity was measured at fair value using the discounted cash flow method, with the primary components of the valuation being future cash flows (both incoming and outgoing) and the discount rate. Dominion Energy determined its discount rate based on the cost of capital a utility-scale investor would expect, as well as the cost of capital an individual project developer could achieve via a combination of nonrecourse project financing and outside equity partners. The acquired assets of Four Brothers and Three Cedars are included in the Power Generation operating segment.

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, 2017, 2016 and 2015.

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.

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, which owns and operates a 416-mile, FERC-regulated natural gas transmission pipeline in New York and Connecticut. In exchange for this partnership interest, Dominion Energy Midstream issued 8.6 million common units representing limited partnership interests in Dominion Energy Midstream (6.8 million common units to NG for its 20.4% interest and 1.8 million common units to NJNR for its 5.53% interest). The investment was recorded at $216 million based on the value of Dominion Energy Midstream’s common units at closing. These common units are reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. Dominion Energy Midstream’s noncontrolling partnership interest is reflected in the Gas Infrastructure operating segment. In addition to this acquisition, Dominion Energy Gas currently holds a 24.07% noncontrolling partnership interest in Iroquois. Dominion Energy Midstream and Dominion Energy Gas each account for their interest in Iroquois as an equity method investment. See Notes 9 and 15 for more information regarding Iroquois.

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. DECG owns and operates nearly 1,500 miles of FERC-regulated interstate natural gas pipeline in South Carolina and southeastern Georgia. This acquisition supports Dominion Energy’s natural gas expansion into the southeastern U.S. The allocation of the purchase price resulted in $277 million of net property, plant and equipment, $250 million of goodwill, of which approximately $225 million is expected to be deductible for income tax purposes, and $38 million of regulatory liabilities. The goodwill reflects the value associated with enhancing Dominion Energy’s regulated gas position, economic value attributable to future expansion projects as well as increased opportunities for synergies. The acquired assets of DECG are included in the Gas Infrastructure operating segment.

On March 24, 2015, DECG converted to a limited liability company under the laws of South Carolina and changed its name from Carolina Gas Transmission Corporation to DECG. On April 1, 2015, Dominion Energy contributed 100% of the issued and outstanding membership interests of DECG to Dominion Energy Midstream in exchange for total consideration of $501 million, as adjusted for working capital. Total consideration to Dominion Energy consisted of the issuance of a two-year, $301 million senior unsecured promissory note payable by Dominion Energy Midstream at an annual interest rate of 0.6%, and 5,112,139 common units, valued at $200 million, representing limited partner interests in Dominion Energy Midstream. The number of units was based on the volume weighted average trading price of Dominion Energy Midstream’s common units for the ten trading days prior to April 1, 2015, or $39.12 per unit. Since Dominion Energy consolidates Dominion Energy Midstream for financial reporting purposes, this transaction was

|  |  |  | 43

Combined Notes to Consolidated Financial Statements, Continued

eliminated upon consolidation and did not impact Dominion Energy’s financial position or cash flows.

VIRGINIA POWER

Acquisition of Solar Projects

In December 2015, Virginia Power completed the acquisition of 100% of a solar development project in North Carolina from Morgans Corner for $47 million, all of which was allocated to property, plant and equipment. The project was placed into service in December 2015 with a total cost of $49 million, including the initial acquisition cost. The project generates 20 MW. The output generated by the project is used to meet a ten-year non-jurisdictional supply agreement with the U.S. Navy, which has the unilateral option to extend for an additional ten years. In October 2015, the North Carolina Commission granted the transfer of the existing CPCN from Morgans Corner to Virginia Power. The acquired asset is included in the Power Generation operating segment.

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 consists of the following:

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |
Electric sales: |  |  |  |  |  |  |  |  |  |  |  |
Regulated |  | $ | 7,383 |  |  | $ | 7,348 |  |  | $ | 7,482 |
Nonregulated |  |  | 1,429 |  |  |  | 1,519 |  |  |  | 1,488 |
Gas sales: |  |  |  |  |  |  |  |  |  |  |  |
Regulated |  |  | 1,067 |  |  |  | 500 |  |  |  | 218 |
Nonregulated |  |  | 457 |  |  |  | 354 |  |  |  | 471 |
Gas transportation and storage |  |  | 1,786 |  |  |  | 1,636 |  |  |  | 1,616 |
Other |  |  | 464 |  |  |  | 380 |  |  |  | 408 |
Total operating revenue |  | $ | 12,586 |  |  | $ | 11,737 |  |  | $ | 11,683 |
Virginia Power |  |  |  |  |  |  |  |  |  |  |  |
Regulated electric sales |  | $ | 7,383 |  |  | $ | 7,348 |  |  | $ | 7,482 |
Other |  |  | 173 |  |  |  | 240 |  |  |  | 140 |
Total operating revenue |  | $ | 7,556 |  |  | $ | 7,588 |  |  | $ | 7,622 |
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |
Gas sales: |  |  |  |  |  |  |  |  |  |  |  |
Regulated |  | $ | 87 |  |  | $ | 119 |  |  | $ | 122 |
Nonregulated |  |  | 20 |  |  |  | 13 |  |  |  | 10 |
Gas transportation and storage |  |  | 1,435 |  |  |  | 1,307 |  |  |  | 1,366 |
NGL revenue |  |  | 91 |  |  |  | 62 |  |  |  | 93 |
Other |  |  | 181 |  |  |  | 137 |  |  |  | 125 |
Total operating revenue |  | $ | 1,814 |  |  | $ | 1,638 |  |  | $ | 1,716 |

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 author-

ities. 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 includes a broad range of tax reform provisions affecting the Companies as discussed in Note 2. The 2017 Tax Reform Act reduces 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 allows for the continued deductibility of interest expense, changes the tax depreciation of certain property acquired after September 27, 2017, and continues certain rate normalization requirements for accelerated depreciation benefits.

In December 2015, U.S. federal legislation was enacted, providing an extension of the 50% bonus depreciation allowance for qualifying expenditures incurred in 2015, 2016 and 2017. In addition, the legislation extended the 30% investment tax credit for qualifying expenditures incurred through 2019 and provides a phase down of the credit to 26% in 2020, 22% in 2021 and 10% in 2022 and thereafter.

As indicated in Note 2, certain of the Companies’ operations, including accounting for income taxes, is 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 are recorded as either an increase to a regulatory asset or liability. 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 refunds of other deferred taxes may be determined by state and federal regulators. See Note 13 for more information.

The Companies have completed or have made a reasonable estimate for the measurement and accounting of certain effects of the 2017 Tax Reform Act which have been reflected in the Consolidated Financial Statements. The changes in deferred taxes were recorded as either an increase to a regulatory liability or as an adjustment to the deferred tax provision.

The items reflected as provisional amounts are related to accelerated depreciation for tax purposes of certain property acquired and placed into service after September 27, 2017 and the impact of accelerated depreciation on state income taxes to the extent there is uncertainty on conformity to the new federal tax system.

The determination of the income tax effects of the items reflected as provisional amounts represents a reasonable estimate, but will require additional analysis of historical records and further interpretation of the 2017 Tax Reform Act from yet to be issued U.S. Department of Treasury regulations, which will require more time, information and resources than currently available to the Companies.

44 |  |  |  |

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, |  | 2017 |  |  | 2016 |  |  | 2015 |  |  | 2017 |  |  | 2016 |  |  | 2015 |  |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Federal |  | $ | (1 | ) |  | $ | (155 | ) |  | $ | (24 | ) |  | $ | 432 |  |  | $ | 168 |  |  | $ | 316 |  |  | $ | 16 |  |  | $ | (27 | ) |  | $ | 90 |
State |  |  | (26 | ) |  |  | 85 |  |  |  | 75 |  |  |  | 73 |  |  |  | 90 |  |  |  | 92 |  |  |  | 8 |  |  |  | 4 |  |  |  | 30 |
Total current expense (benefit) |  |  | (27 | ) |  |  | (70 | ) |  |  | 51 |  |  |  | 505 |  |  |  | 258 |  |  |  | 408 |  |  |  | 24 |  |  |  | (23 | ) |  |  | 120 |
Deferred: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Federal |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2017 Tax Reform Act impact |  |  | (851 | ) |  |  | — |  |  |  | — |  |  |  | (93 | ) |  |  | — |  |  |  | — |  |  |  | (197 | ) |  |  | — |  |  |  | — |
Taxes before operating loss carryforwards and investment tax credits |  |  | 739 |  |  |  | 1,050 |  |  |  | 384 |  |  |  | 319 |  |  |  | 435 |  |  |  | 154 |  |  |  | 199 |  |  |  | 239 |  |  |  | 156 |
Tax utilization expense (benefit) of operating loss carryforwards |  |  | 174 |  |  |  | (161 | ) |  |  | 539 |  |  |  | 4 |  |  |  | (2 | ) |  |  | 96 |  |  |  | 5 |  |  |  | (2 | ) |  |  | 6 |
Investment tax credits |  |  | (200 | ) |  |  | (248 | ) |  |  | (134 | ) |  |  | (23 | ) |  |  | (25 | ) |  |  | (11 | ) |  |  | — |  |  |  | — |  |  |  | — |
State |  |  | 132 |  |  |  | 50 |  |  |  | 66 |  |  |  | 59 |  |  |  | 27 |  |  |  | 13 |  |  |  | 20 |  |  |  | 1 |  |  |  | 1 |
Total deferred expense (benefit) |  |  | (6 | ) |  |  | 691 |  |  |  | 855 |  |  |  | 266 |  |  |  | 435 |  |  |  | 252 |  |  |  | 27 |  |  |  | 238 |  |  |  | 163 |
Investment tax credit-gross deferral |  |  | 5 |  |  |  | 35 |  |  |  | — |  |  |  | 5 |  |  |  | 35 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Investment tax credit-amortization |  |  | (2 | ) |  |  | (1 | ) |  |  | (1 | ) |  |  | (2 | ) |  |  | (1 | ) |  |  | (1 | ) |  |  | — |  |  |  | — |  |  |  | — |
Total income tax expense (benefit) |  | $ | (30 | ) |  | $ | 655 |  |  | $ | 905 |  |  | $ | 774 |  |  | $ | 727 |  |  | $ | 659 |  |  | $ | 51 |  |  | $ | 215 |  |  | $ | 283 |

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.

In 2015, Dominion Energy’s current federal income tax benefit includes the recognition of a $20 million benefit related to a carryback to be filed for nuclear decommissioning expenditures included in its 2014 net operating loss.

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, |  | 2017 |  |  | 2016 |  |  | 2015 |  |  | 2017 |  |  | 2016 |  |  | 2015 |  |  | 2017 |  |  | 2016 |  |  | 2015 |
U.S. statutory rate |  |  | 35.0 | % |  |  | 35.0 | % |  |  | 35.0 | % |  |  | 35.0 | % |  |  | 35.0 | % |  |  | 35.0 | % |  |  | 35.0 | % |  |  | 35.0 | % |  |  | 35.0 | %
Increases (reductions) resulting from: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
State taxes, net of federal benefit |  |  | 2.0 |  |  |  | 2.4 |  |  |  | 3.7 |  |  |  | 3.7 |  |  |  | 3.8 |  |  |  | 3.9 |  |  |  | 2.4 |  |  |  | 0.5 |  |  |  | 2.7 |
Investment tax credits |  |  | (6.3 | ) |  |  | (11.7 | ) |  |  | (4.7 | ) |  |  | (0.8 | ) |  |  | — |  |  |  | (0.6 | ) |  |  | — |  |  |  | — |  |  |  | — |
Production tax credits |  |  | (0.7 | ) |  |  | (0.8 | ) |  |  | (0.8 | ) |  |  | (0.4 | ) |  |  | (0.5 | ) |  |  | (0.6 | ) |  |  | — |  |  |  | — |  |  |  | — |
Valuation allowances |  |  | 0.2 |  |  |  | 1.2 |  |  |  | (0.3 | ) |  |  | — |  |  |  | 0.1 |  |  |  | — |  |  |  | 0.3 |  |  |  | — |  |  |  | — |
Federal legislative change |  |  | (27.5 | ) |  |  | — |  |  |  | — |  |  |  | (4.0 | ) |  |  | — |  |  |  | — |  |  |  | (29.5 | ) |  |  | — |  |  |  | — |
State legislative change |  |  | — |  |  |  | (0.6 | ) |  |  | (0.1 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
AFUDC—equity |  |  | (1.4 | ) |  |  | (0.6 | ) |  |  | (0.3 | ) |  |  | (0.6 | ) |  |  | (0.6 | ) |  |  | (0.6 | ) |  |  | (0.9 | ) |  |  | (0.2 | ) |  |  | 0.2 |
Employee stock ownership plan deduction |  |  | (0.6 | ) |  |  | (0.6 | ) |  |  | (0.6 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Other, net |  |  | (1.7 | ) |  |  | (1.4 | ) |  |  | 0.1 |  |  |  | 0.6 |  |  |  | (0.4 | ) |  |  | 0.6 |  |  |  | 0.4 |  |  |  | 0.1 |  |  |  | 0.3 |
Effective tax rate |  |  | (1.0 | )% |  |  | 22.9 | % |  |  | 32.0 | % |  |  | 33.5 | % |  |  | 37.4 | % |  |  | 37.7 | % |  |  | 7.7 | % |  |  | 35.4 | % |  |  | 38.2 | %

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 recog-

|  |  |  | 45

Combined Notes to Consolidated Financial Statements, Continued

nition 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, |  | 2017 |  |  | 2016 |  |  | 2017 |  |  | 2016 |  |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred income taxes: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total deferred income tax assets |  | $ | 2,686 |  |  | $ | 1,827 |  |  | $ | 923 |  |  |  | $ 268 |  |  |  | $ 320 |  |  | $ | 126 |
Total deferred income tax liabilities |  |  | 7,158 |  |  |  | 10,381 |  |  |  | 3,600 |  |  |  | 5,323 |  |  |  | 1,774 |  |  |  | 2,564 |
Total net deferred income tax liabilities |  | $ | 4,472 |  |  | $ | 8,554 |  |  | $ | 2,677 |  |  |  | $5,055 |  |  |  | $1,454 |  |  | $ | 2,438 |
Total deferred income taxes: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Plant and equipment, primarily depreciation method and basis differences |  | $ | 5,056 |  |  | $ | 7,782 |  |  | $ | 2,969 |  |  |  | $4,604 |  |  |  | $1,132 |  |  | $ | 1,726 |
Excess deferred income taxes |  |  | (1,050 | ) |  |  | — |  |  |  | (687 | ) |  |  | — |  |  |  | (244 | ) |  |  | — |
Nuclear decommissioning |  |  | 829 |  |  |  | 1,240 |  |  |  | 260 |  |  |  | 406 |  |  |  | — |  |  |  | — |
Deferred state income taxes |  |  | 834 |  |  |  | 747 |  |  |  | 378 |  |  |  | 321 |  |  |  | 227 |  |  |  | 204 |
Federal benefit of deferred state income taxes |  |  | (175 | ) |  |  | (261 | ) |  |  | (79 | ) |  |  | (112 | ) |  |  | (48 | ) |  |  | (71 | )
Deferred fuel, purchased energy and gas costs |  |  | 1 |  |  |  | (25 | ) |  |  | (3 | ) |  |  | (29 | ) |  |  | 2 |  |  |  | 4 |
Pension benefits |  |  | 141 |  |  |  | 155 |  |  |  | (104 | ) |  |  | (138 | ) |  |  | 419 |  |  |  | 646 |
Other postretirement benefits |  |  | (51 | ) |  |  | (68 | ) |  |  | 44 |  |  |  | 49 |  |  |  | (2 | ) |  |  | (6 | )
Loss and credit carryforwards |  |  | (1,536 | ) |  |  | (1,547 | ) |  |  | (111 | ) |  |  | (88 | ) |  |  | (4 | ) |  |  | (5 | )
Valuation allowances |  |  | 146 |  |  |  | 135 |  |  |  | 5 |  |  |  | 3 |  |  |  | 3 |  |  |  | — |
Partnership basis differences |  |  | 473 |  |  |  | 688 |  |  |  | — |  |  |  | — |  |  |  | 26 |  |  |  | 43 |
Other |  |  | (196 | ) |  |  | (292 | ) |  |  | 5 |  |  |  | 39 |  |  |  | (57 | ) |  |  | (103 | )
Total net deferred income tax liabilities |  | $ | 4,472 |  |  | $ | 8,554 |  |  | $ | 2,677 |  |  |  | $5,055 |  |  |  | $1,454 |  |  | $ | 2,438 |
Deferred Investment Tax Credits – Regulated Operations |  |  | 51 |  |  |  | 48 |  |  |  | 51 |  |  |  | 48 |  |  |  | — |  |  |  | — |
Total Deferred Taxes and Deferred Investment Tax Credits |  | $ | 4,523 |  |  | $ | 8,602 |  |  | $ | 2,728 |  |  |  | $5,103 |  |  |  | $1,454 |  |  | $ | 2,438 |

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 reflects 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, 2017, Dominion Energy had the following deductible loss and credit carryforwards:

|  | Deductible Amount |  |  | Deferred Tax Asset |  |  | Valuation Allowance |  |  | Expiration Period |
(millions) |  |  |  |  |  |  |  |  |  |  |  |
Federal losses |  |  | $ 560 |  |  |  | $ 118 |  |  |  | $ — |  |  |  | 2034 |
Federal investment credits |  |  | — |  |  |  | 938 |  |  |  | — |  |  |  | 2033-2037 |
Federal production credits |  |  | — |  |  |  | 129 |  |  |  | — |  |  |  | 2031-2037 |
Other federal credits |  |  | — |  |  |  | 58 |  |  |  | — |  |  |  | 2031-2037 |
State losses |  |  | 1,366 |  |  |  | 103 |  |  |  | (63 | ) |  |  | 2018-2037 |
State minimum tax credits |  |  | — |  |  |  | 90 |  |  |  | — |  |  |  | No expiration |
State investment and other credits |  |  | — |  |  |  | 100 |  |  |  | (83 | ) |  |  | 2018-2027 |
Total |  |  | $1,926 |  |  |  | $1,536 |  |  |  | $(146 | ) |  |  |  |

At December 31, 2017, 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 |  |  | — |  |  |  | 51 |  |  |  | — |  |  |  | 2034-2037 |
Federal production and other credits |  |  | — |  |  |  | 51 |  |  |  | — |  |  |  | 2031-2037 |
State investment credits |  |  | — |  |  |  | 9 |  |  |  | (5 | ) |  |  | 2024 |
Total |  |  | $ 1 |  |  |  | $111 |  |  |  | $(5 | ) |  |  |  |

At December 31, 2017, 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 |  |  |  | $ — |  |  |  | 2032-2036 |
State losses |  |  | 33 |  |  |  | 3 |  |  |  | (3 | ) |  |  | 2036-2037 |
Total |  |  | $33 |  |  |  | $4 |  |  |  | $ (3 | ) |  |  |  |

46 |  |  |  |

A reconciliation of changes in the Companies’ unrecognized tax benefits follows:

|  | Dominion Energy |  |  | Virginia Power |  |  | Dominion Energy Gas |
|  | 2017 |  |  | 2016 |  |  | 2015 |  |  | 2017 |  |  | 2016 |  |  | 2015 |  |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Balance at January 1 |  | $ | 64 |  |  | $ | 103 |  |  | $ | 145 |  |  | $ | 13 |  |  | $ | 12 |  |  | $ | 36 |  |  |  | $ 7 |  |  | $ | 29 |  |  |  | $29 |
Increases-prior period positions |  |  | 1 |  |  |  | 9 |  |  |  | 2 |  |  |  | — |  |  |  | 4 |  |  |  | — |  |  |  | — |  |  |  | 1 |  |  |  | — |
Decreases-prior period positions |  |  | (9 | ) |  |  | (44 | ) |  |  | (40 | ) |  |  | (1 | ) |  |  | (3 | ) |  |  | (25 | ) |  |  | — |  |  |  | (19 | ) |  |  | — |
Increases-current period positions |  |  | 5 |  |  |  | 6 |  |  |  | 8 |  |  |  | — |  |  |  | — |  |  |  | 1 |  |  |  | — |  |  |  | — |  |  |  | — |
Settlements with tax authorities |  |  | (23 | ) |  |  | (8 | ) |  |  | (5 | ) |  |  | (8 | ) |  |  | — |  |  |  | — |  |  |  | (7 | ) |  |  | (4 | ) |  |  | — |
Expiration of statutes of limitations |  |  | — |  |  |  | (2 | ) |  |  | (7 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Balance at December 31 |  | $ | 38 |  |  | $ | 64 |  |  | $ | 103 |  |  | $ | 4 |  |  | $ | 13 |  |  | $ | 12 |  |  |  | $— |  |  | $ | 7 |  |  |  | $29 |

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 $31 million, $45 million and $69 million at December 31, 2017, 2016 and 2015, respectively. For Dominion Energy, the change in these unrecognized tax benefits decreased income tax expense by $9 million, $18 million and $6 million in 2017, 2016 and 2015, respectively. For Virginia Power, these unrecognized tax benefits were $3 million, $9 million, and $8 million at December 31, 2017, 2016 and 2015, respectively. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by $6 million in 2017 and increased income tax expense by $1 million and less than $1 million in 2016 and 2015, respectively. For Dominion Energy Gas, these unrecognized tax benefits were less than $1 million, $5 million and $19 million at December 31, 2017, 2016 and 2015, respectively. For Dominion Energy Gas, the change in these unrecognized tax benefits decreased income tax expense by $5 million, $11 million and less than $1 million in 2017, 2016 and 2015, 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 2016 and 2017, the Companies submitted research credit claims for tax years 2012-2016. These claims are currently under IRS examination. With the exception of these research credit claims, the IRS has completed its audit of tax years through 2015. 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 2016, no material adjustments are expected. The IRS examination of tax year 2017 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 2018 by up to $13 million for Dominion Energy, $2 million for Virginia Power and less than $1 million for 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 $12 million for Dominion Energy, $2 million for Virginia Power and less than $1 million for Dominion Energy Gas.

Otherwise, with regard to 2017 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 2018.

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 |  |  | 2014 |
Virginia(2) |  |  | 2014 |
West Virginia(1) |  |  | 2014 |
New York(1) |  |  | 2011 |
Utah |  |  | 2014 |

(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 includ-

47

Combined Notes to Consolidated Financial Statements, Continued

ing 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

The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. 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 broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, the Companies consider 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 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 Companies must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect their market assumptions.

The Companies’ commodity derivative valuations are prepared by Dominion Energy’s ERM department. The ERM department creates daily mark-to-market valuations for the Companies’ derivative transactions using computer-based statistical models. The inputs that go into the market valuations are transactional information stored in the systems of record and market pricing information that resides in data warehouse databases. The majority of forward prices are automatically uploaded into the data warehouse databases from various third-party sources. Inputs obtained from third-party sources are evaluated for reliability considering the reputation, independence, market presence, and methodology used by the third-party. If forward prices are not available from third-party sources, then the ERM department models the forward prices based on other available market data. A team consisting of risk management and risk quantitative analysts meets each business day to assess the validity of market prices and mark-to-market valuations. During this meeting, the changes in mark-to-market valuations from period to period are examined and qualified against historical expectations. If any discrepancies are identified during this process, the mark-to-market valuations or the market pricing information is evaluated further and adjusted, if necessary.

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 a Spread Approximation Model when contracts include different commodities or commodity locations and a Swing Option Model when contracts allow either the buyer or seller the ability to exercise within a range of quantities. 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

The Companies regularly evaluate and validate the inputs used to estimate fair value by a number of methods, including review and verification of models, as well as various market price verification procedures such as the use of pricing services and multiple broker quotes to support the market price of the various commodities and investments in which the Companies transact.

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

48 |  |  |  |

|  | 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.

For derivative contracts, the Companies recognize transfers among Level 1, Level 2 and Level 3 based on fair values as of the first day of the month in which the transfer occurs. 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

Fair value measurements are categorized as Level 3 when price or other inputs that are considered to be unobservable are significant to their valuations. Long-dated commodity derivatives are generally based on unobservable inputs due to the length of time to settlement and the absence of market activity and are therefore categorized as Level 3. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from ISO auctions, which are generally not considered to be liquid markets. Other modeled commodity derivatives have unobservable inputs in their valuation, mostly due to non-transparent and illiquid markets.

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 unobservable inputs are developed and substantiated using historical information, available market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party pricing sources.

49

Combined Notes to Consolidated Financial Statements, Continued

The following table presents Dominion Energy’s quantitative information about Level 3 fair value measurements at December 31, 2017. 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) |  |  | $ 84 |  |  |  | Discounted cash flow |  |  |  | Market price (per Dth)(4) |  |  |  | (2) - 14 |  |  |  | — |
FTRs |  |  | 29 |  |  |  | Discounted cash flow |  |  |  | Market price (per MWh)(4) |  |  |  | (1) - 7 |  |  |  | 2 |
Physical options: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas |  |  | 1 |  |  |  | Option model |  |  |  | Market price (per Dth)(4) |  |  |  | 2 - 7 |  |  |  | 3 |
|  |  |  |  |  |  |  |  |  |  | Price volatility (5) |  |  |  | 26% - 54% |  |  |  | 33 | %
Electricity |  |  | 43 |  |  |  | Option model |  |  |  | Market price (per MWh)(4) |  |  |  | 22 - 74 |  |  |  | 37 |
|  |  |  |  |  |  |  |  |  |  | Price volatility (5) |  |  |  | 13% - 63% |  |  |  | 33 | %
Total assets |  |  | $157 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Financial forwards: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Liquids(3) |  |  | $ 2 |  |  |  | Discounted cash flow |  |  |  | Market price (per Gal)(4) |  |  |  | 0 - 2 |  |  |  | 1 |
FTRs |  |  | $ 5 |  |  |  | Discounted cash flow |  |  |  | Market price (per MWh)(4) |  |  |  | (4) - 6 |  |  |  | — |
Total liabilities |  |  | $ 7 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

(1) | Averages weighted by volume.

(2) | Includes basis.

(3) | Includes NGLs and oil.

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

(5) | Represents 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.

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’s and Dominion Energy Gas’ pension and other postretirement benefit plans are presented in Note 21.

50 |  |  |  |

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, 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 |
December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  | $ | — |  |  | $ | 115 |  |  |  | $147 |  |  | $ | 262 |
Interest rate |  |  | — |  |  |  | 17 |  |  |  | — |  |  |  | 17 |
Investments(1): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. |  |  | 2,913 |  |  |  | — |  |  |  | — |  |  |  | 2,913 |
Fixed income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Corporate debt instruments |  |  | — |  |  |  | 487 |  |  |  | — |  |  |  | 487 |
Government securities |  |  | 424 |  |  |  | 614 |  |  |  | — |  |  |  | 1,038 |
Cash equivalents and other |  |  | 5 |  |  |  | — |  |  |  | — |  |  |  | 5 |
Total assets |  | $ | 3,342 |  |  | $ | 1,233 |  |  |  | $147 |  |  | $ | 4,722 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  | $ | — |  |  | $ | 88 |  |  |  | $ 8 |  |  | $ | 96 |
Interest rate |  |  | — |  |  |  | 53 |  |  |  | — |  |  |  | 53 |
Foreign currency |  |  | — |  |  |  | 6 |  |  |  | — |  |  |  | 6 |
Total liabilities |  | $ | — |  |  | $ | 147 |  |  |  | $ 8 |  |  | $ | 155 |

(1) | Includes investments held in the nuclear decommissioning and rabbi trusts. Excludes $88 million and $89 million of assets at December 31, 2017 and 2016, 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:

|  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Balance at January 1, |  | $ | 139 |  |  | $ | 95 |  |  | $ | 107 |
Total realized and unrealized gains (losses): |  |  |  |  |  |  |  |  |  |  |  |
Included in earnings |  |  | (38 | ) |  |  | (35 | ) |  |  | (5 | )
Included in other comprehensive loss |  |  | (2 | ) |  |  | — |  |  |  | (9 | )
Included in regulatory assets/liabilities |  |  | 42 |  |  |  | (39 | ) |  |  | (4 | )
Settlements |  |  | 6 |  |  |  | 38 |  |  |  | 9 |
Purchases |  |  | — |  |  |  | 87 |  |  |  | — |
Transfers out of Level 3 |  |  | 3 |  |  |  | (7 | ) |  |  | (3 | )
Balance at December 31, |  | $ | 150 |  |  | $ | 139 |  |  | $ | 95 |
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 |  |  | $ | (1 | ) |  | $ | 2 |

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

|  | Operating Revenue |  |  | Electric Fuel and Other Energy-Related Purchases |  |  | Purchased Gas |  |  | Total |
(millions) |  |  |  |  |  |  |  |  |  |  |  |
Year Ended December 31, 2017 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total gains (losses) included in earnings |  |  | $ 3 |  |  |  | $(42 | ) |  |  | $ 1 |  |  | $ | (38 | )
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date |  |  | 2 |  |  |  | — |  |  |  | — |  |  |  | 2 |
Year Ended December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total gains (losses) included in earnings |  |  | $— |  |  |  | $(35 | ) |  |  | $— |  |  | $ | (35 | )
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date |  |  | — |  |  |  | (1 | ) |  |  | — |  |  |  | (1 | )
Year Ended December 31, 2015 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total gains (losses) included in earnings |  |  | $ 6 |  |  |  | $(11 | ) |  |  | $— |  |  | $ | (5 | )
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date |  |  | 1 |  |  |  | 1 |  |  |  | — |  |  |  | 2 |

51

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, 2017. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

|  | Fair Value (millions) |  |  | Valuation Techniques |  |  | Unobservable Input |  |  | Range |  |  | Weighted Average(1) |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Physical and financial forwards and futures: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas(2) |  |  | $ 81 |  |  |  | Discounted cash flow |  |  |  | Market price (per Dth)(3) |  |  |  | (2)-7 |  |  |  | (1 | )
FTRs |  |  | 27 |  |  |  | Discounted cash flow |  |  |  | Market price (per MWh)(3) |  |  |  | (1)-7 |  |  |  | 2 |
Physical options: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas |  |  | 1 |  |  |  | Option model |  |  |  | Market price (per Dth)(3) |  |  |  | 2-7 |  |  |  | 3 |
|  |  |  |  |  |  |  |  |  |  | Price volatility (4) |  |  |  | 26%-54% |  |  |  | 33 | %
Electricity |  |  | 43 |  |  |  | Option model |  |  |  | Market price (per MWh)(3) |  |  |  | 22-74 |  |  |  | 37 |
|  |  |  |  |  |  |  |  |  |  | Price volatility (4) |  |  |  | 13%-63% |  |  |  | 33 | %
Total assets |  |  | $152 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Financial forwards: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
FTRs |  |  | $ 5 |  |  |  | Discounted cash flow |  |  |  | Market price (per MWh)(3) |  |  |  | (4)-6 |  |  |  | — |
Total liabilities |  |  | $ 5 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

(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.

52 |  |  |  |

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, 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 |
December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  | $ | — |  |  | $ | 43 |  |  | $ | 145 |  |  | $ | 188 |
Interest rate |  |  | — |  |  |  | 6 |  |  |  | — |  |  |  | 6 |
Investments(1): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. |  |  | 1,302 |  |  |  | — |  |  |  | — |  |  |  | 1,302 |
Fixed income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Corporate debt instruments |  |  | — |  |  |  | 277 |  |  |  | — |  |  |  | 277 |
Government securities |  |  | 136 |  |  |  | 291 |  |  |  | — |  |  |  | 427 |
Total assets |  | $ | 1,438 |  |  | $ | 617 |  |  | $ | 145 |  |  | $ | 2,200 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  | $ | — |  |  | $ | 8 |  |  | $ | 2 |  |  | $ | 10 |
Interest rate |  |  | — |  |  |  | 21 |  |  |  | — |  |  |  | 21 |
Total liabilities |  | $ | — |  |  | $ | 29 |  |  | $ | 2 |  |  | $ | 31 |

(1) | Includes investments held in the nuclear decommissioning trusts. Excludes $27 million and $26 million of assets at December 31, 2017 and 2016, 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:

|  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Balance at January 1, |  | $ | 143 |  |  | $ | 93 |  |  | $ | 102 |
Total realized and unrealized gains (losses): |  |  |  |  |  |  |  |  |  |  |  |
Included in earnings |  |  | (43 | ) |  |  | (35 | ) |  |  | (13 | )
Included in regulatory assets/liabilities |  |  | 40 |  |  |  | (37 | ) |  |  | (5 | )
Settlements |  |  | 7 |  |  |  | 35 |  |  |  | 13 |
Purchases |  |  | — |  |  |  | 87 |  |  |  | — |
Transfers out of Level 3 |  |  | — |  |  |  | — |  |  |  | (4 | )
Balance at December 31, |  | $ | 147 |  |  | $ | 143 |  |  | $ | 93 |

The gains and losses included in earnings in the Level 3 fair value category were classified in electric fuel and other energy-related purchases expense in Virginia Power’s Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015. 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, 2017, 2016 and 2015.

DOMINION ENERGY GAS

The following table presents Dominion Energy Gas’ quantitative information about Level 3 fair value measurements at December 31, 2017. The range and weighted average are presented in dollars for market price inputs.

|  | Fair Value (millions) |  |  | Valuation Techniques |  |  | Unobservable Input |  |  | Range |  |  | Weighted Average(1) |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Financial forwards: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NGLs |  |  | $2 |  |  |  | Discounted cash flow |  |  |  | Market price (per Dth) | (2) |  |  | 0 - 1 |  |  |  | 1 |
Total liabilities |  |  | $2 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

(1) | Averages weighted by volume.

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

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

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

53

Combined Notes to Consolidated Financial Statements, Continued

The following table presents Dominion Energy Gas’ assets and liabilities for commodity and foreign currency 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, 2017 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign currency |  |  | $ — |  |  |  | $32 |  |  |  | $ — |  |  | $ | 32 |
Total assets |  |  | $ — |  |  |  | $32 |  |  |  | $ — |  |  | $ | 32 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | $ — |  |  |  | $ 4 |  |  |  | $ 2 |  |  | $ | 6 |
Foreign currency |  |  | — |  |  |  | 2 |  |  |  | — |  |  |  | 2 |
Total liabilities |  |  | $ — |  |  |  | $ 6 |  |  |  | $ 2 |  |  | $ | 8 |
December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | $ — |  |  |  | $ 3 |  |  |  | $ 2 |  |  | $ | 5 |
Foreign currency |  |  | — |  |  |  | 6 |  |  |  | — |  |  |  | 6 |
Total liabilities |  |  | $ — |  |  |  | $ 9 |  |  |  | $ 2 |  |  | $ | 11 |

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:

|  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Balance at January 1, |  | $ | (2 | ) |  | $ | 6 |  |  | $ | 2 |
Total realized and unrealized gains (losses): |  |  |  |  |  |  |  |  |  |  |  |
Included in earnings |  |  | — |  |  |  | — |  |  |  | 1 |
Included in other comprehensive loss |  |  | (3 | ) |  |  | — |  |  |  | (5 | )
Settlements |  |  | — |  |  |  | — |  |  |  | (1 | )
Transfers out of Level 3 |  |  | 3 |  |  |  | (8 | ) |  |  | 9 |
Balance at December 31, |  | $ | (2 | ) |  | $ | (2 | ) |  | $ | 6 |

The gains and losses included in earnings in the Level 3 fair value category were classified in operating revenue in Dominion Energy Gas’ Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015. 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, 2017, 2016 and 2015.

Fair Value of Financial Instruments

Substantially all of the Companies’ financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash and cash equivalents, restricted cash and 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, |  | 2017 |  |  | 2016 |
|  | 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) |  | $ | 28,666 |  |  |  | $31,233 |  |  | $ | 26,587 |  |  |  | $28,273 |
Junior subordinated notes(3) |  |  | 3,981 |  |  |  | 4,102 |  |  |  | 2,980 |  |  |  | 2,893 |
Remarketable subordinated notes(3) |  |  | 1,379 |  |  |  | 1,446 |  |  |  | 2,373 |  |  |  | 2,418 |
Virginia Power |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt, including securities due within one year(3) |  | $ | 11,346 |  |  |  | $12,842 |  |  | $ | 10,530 |  |  |  | $11,584 |
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt, including securities due within one year(4) |  | $ | 3,570 |  |  |  | $ 3,719 |  |  | $ | 3,528 |  |  |  | $ 3,603 |

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

(2) | Carrying amount includes amounts which represent the unamortized debt issuance costs, discount or premium, and foreign currency remeasurement adjustments. At December 31, 2017, and 2016, includes the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt of $(22) million and $(1) 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.

54 |  |  |  |

NOTE 7. DERIVATIVES AND HEDGE ACCOUNTING ACTIVITIES

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. The Companies use derivative instruments to manage exposure to these risks, and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes. As discussed in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivatives are deferred as regulatory assets or regulatory liabilities until the related transactions impact earnings. 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’s 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.

|  |  |  | 55

Combined Notes to Consolidated Financial Statements, Continued

DOMINION ENERGY

Balance Sheet Presentation

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

|  | December 31, 2017 |  |  | December 31, 2016 |
|  | Gross Amounts of Recognized Assets |  |  | Gross Amounts Offset in the Consolidated Balance Sheet |  |  | Net Amounts of Assets Presented in the Consolidated Balance Sheet |  |  | Gross Amounts of Recognized Assets |  |  | Gross Amounts Offset in the Consolidated Balance Sheet |  |  | Net Amounts of Assets Presented in the Consolidated Balance Sheet |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | $174 |  |  |  | $— |  |  |  | $174 |  |  |  | $211 |  |  |  | $— |  |  |  | $211 |
Exchange |  |  | 80 |  |  |  | — |  |  |  | 80 |  |  |  | 44 |  |  |  | — |  |  |  | 44 |
Interest rate contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | 17 |  |  |  | — |  |  |  | 17 |  |  |  | 17 |  |  |  | — |  |  |  | 17 |
Foreign currency contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | 32 |  |  |  | — |  |  |  | 32 |  |  |  | — |  |  |  | — |  |  |  | — |
Total derivatives, subject to a master netting or similar arrangement |  |  | 303 |  |  |  | — |  |  |  | 303 |  |  |  | 272 |  |  |  | — |  |  |  | 272 |
Total derivatives, not subject to a master netting or similar arrangement |  |  | 4 |  |  |  | — |  |  |  | 4 |  |  |  | 7 |  |  |  | — |  |  |  | 7 |
Total |  |  | $307 |  |  |  | $— |  |  |  | $307 |  |  |  | $279 |  |  |  | $— |  |  |  | $279 |

|  |  |  |  | December 31, 2017 |  |  |  |  |  | December 31, 2016 |
|  |  |  |  | Gross Amounts Not Offset in the Consolidated Balance Sheet |  |  |  |  |  |  |  |  | Gross Amounts Not Offset in the Consolidated Balance Sheet |  |  |  |
|  | Net Amounts of Assets Presented in the Consolidated Balance Sheet |  |  | Financial Instruments |  |  | Cash Collateral Received |  |  | Net Amounts |  |  | Net Amounts of Assets Presented in the Consolidated Balance Sheet |  |  | Financial Instruments |  |  | Cash Collateral Received |  |  | Net Amounts |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | $174 |  |  |  | $ 9 |  |  |  | $— |  |  |  | $165 |  |  |  | $211 |  |  |  | $14 |  |  |  | $— |  |  |  | $197 |
Exchange |  |  | 80 |  |  |  | 80 |  |  |  | — |  |  |  | — |  |  |  | 44 |  |  |  | 44 |  |  |  | — |  |  |  | — |
Interest rate contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | 17 |  |  |  | 8 |  |  |  | — |  |  |  | 9 |  |  |  | 17 |  |  |  | 9 |  |  |  | — |  |  |  | 8 |
Foreign currency contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | 32 |  |  |  | 2 |  |  |  | — |  |  |  | 30 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Total |  |  | $303 |  |  |  | $99 |  |  |  | $— |  |  |  | $204 |  |  |  | $272 |  |  |  | $67 |  |  |  | $— |  |  |  | $205 |

|  | December 31, 2017 |  |  | December 31, 2016 |
|  | Gross Amounts of Recognized Liabilities |  |  | Gross Amounts Offset in the Consolidated Balance Sheet |  |  | Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |  |  | Gross Amounts of Recognized Liabilities |  |  | Gross Amounts Offset in the Consolidated Balance Sheet |  |  | Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | $ 76 |  |  |  | $— |  |  |  | $ 76 |  |  |  | $ 23 |  |  |  | $— |  |  |  | $ 23 |
Exchange |  |  | 120 |  |  |  | — |  |  |  | 120 |  |  |  | 71 |  |  |  | — |  |  |  | 71 |
Interest rate contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | 85 |  |  |  | — |  |  |  | 85 |  |  |  | 53 |  |  |  | — |  |  |  | 53 |
Foreign currency contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | 2 |  |  |  | — |  |  |  | 2 |  |  |  | 6 |  |  |  | — |  |  |  | 6 |
Total derivatives, subject to a master netting or similar arrangement |  |  | 283 |  |  |  | — |  |  |  | 283 |  |  |  | 153 |  |  |  | — |  |  |  | 153 |
Total derivatives, not subject to a master netting or similar arrangement |  |  | 1 |  |  |  | — |  |  |  | 1 |  |  |  | 2 |  |  |  | — |  |  |  | 2 |
Total |  |  | $284 |  |  |  | $— |  |  |  | $284 |  |  |  | $155 |  |  |  | $— |  |  |  | $155 |

56 |  |  |  |

|  |  |  |  | December 31, 2017 |  |  |  |  |  | December 31, 2016 |
|  |  |  |  | Gross Amounts Not Offset in the Consolidated Balance Sheet |  |  |  |  |  |  |  |  | Gross Amounts Not Offset in the Consolidated Balance Sheet |  |  |  |
|  | Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |  |  | Financial Instruments |  |  | Cash Collateral Paid |  |  | Net Amounts |  |  | Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |  |  | Financial Instruments |  |  | Cash Collateral Paid |  |  | Net Amounts |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | $ 76 |  |  |  | $ 9 |  |  |  | $ 6 |  |  |  | $ 61 |  |  |  | $ 23 |  |  |  | $14 |  |  |  | $— |  |  |  | $ 9 |
Exchange |  |  | 120 |  |  |  | 80 |  |  |  | 40 |  |  |  | — |  |  |  | 71 |  |  |  | 44 |  |  |  | 27 |  |  |  | — |
Interest rate contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | 85 |  |  |  | 8 |  |  |  | — |  |  |  | 77 |  |  |  | 53 |  |  |  | 9 |  |  |  | — |  |  |  | 44 |
Foreign currency contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | 2 |  |  |  | 2 |  |  |  | — |  |  |  | — |  |  |  | 6 |  |  |  | — |  |  |  | — |  |  |  | 6 |
Total |  |  | $283 |  |  |  | $99 |  |  |  | $46 |  |  |  | $138 |  |  |  | $153 |  |  |  | $67 |  |  |  | $27 |  |  |  | $59 |

Volumes

The following table presents the volume of Dominion Energy’s derivative activity as of December 31, 2017. 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) |  |  | 77 |  |  |  | 19 |
Basis |  |  | 163 |  |  |  | 600 |
Electricity (MWh): |  |  |  |  |  |  |  |
Fixed price |  |  | 10,552,363 |  |  |  | 364,990 |
FTRs |  |  | 46,494,865 |  |  |  | — |
Liquids (Gal)(2) |  |  | 44,153,704 |  |  |  | 10,087,200 |
Interest rate(3) |  | $ | 1,950,000,000 |  |  | $ | 4,192,517,177 |
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, 2017, 2016 and 2015, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy’s Consolidated Balance Sheet at December 31, 2017:

|  | AOCI After-Tax |  |  | Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax |  |  | Maximum Term |
(millions) |  |  |  |  |  |  |  |  |
Commodities: |  |  |  |  |  |  |  |  |  |  |  |
Gas |  |  | $ (2 | ) |  |  | $ (3 | ) |  |  | 34 months |
Electricity |  |  | (55 | ) |  |  | (55 | ) |  |  | 12 months |
Other |  |  | (4 | ) |  |  | (4 | ) |  |  | 15 months |
Interest rate |  |  | (246 | ) |  |  | (10 | ) |  |  | 384 months |
Foreign currency |  |  | 5 |  |  |  | (1 | ) |  |  | 102 months |
Total |  |  | $(302 | ) |  |  | $(73 | ) |  |  |  |

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.

|  |  |  | 57

Combined Notes to Consolidated Financial Statements, Continued

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, 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 |
At December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |
ASSETS |  |  |  |  |  |  |  |  |  |  |  |
Current Assets |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | $ 29 |  |  |  | $101 |  |  | $ | 130 |
Interest rate |  |  | 10 |  |  |  | — |  |  |  | 10 |
Total current derivative assets(1) |  |  | 39 |  |  |  | 101 |  |  |  | 140 |
Noncurrent Assets |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | — |  |  |  | 132 |  |  |  | 132 |
Interest rate |  |  | 7 |  |  |  | — |  |  |  | 7 |
Total noncurrent derivative assets(2) |  |  | 7 |  |  |  | 132 |  |  |  | 139 |
Total derivative assets |  |  | $ 46 |  |  |  | $233 |  |  | $ | 279 |
LIABILITIES |  |  |  |  |  |  |  |  |  |  |  |
Current Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | $ 51 |  |  |  | $ 41 |  |  | $ | 92 |
Interest rate |  |  | 33 |  |  |  | — |  |  |  | 33 |
Foreign currency |  |  | 3 |  |  |  | — |  |  |  | 3 |
Total current derivative liabilities(3) |  |  | 87 |  |  |  | 41 |  |  |  | 128 |
Noncurrent Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | 1 |  |  |  | 3 |  |  |  | 4 |
Interest rate |  |  | 20 |  |  |  | — |  |  |  | 20 |
Foreign currency |  |  | 3 |  |  |  | — |  |  |  | 3 |
Total noncurrent derivative liabilities(4) |  |  | 24 |  |  |  | 3 |  |  |  | 27 |
Total derivative liabilities |  |  | $111 |  |  |  | $ 44 |  |  | $ | 155 |

(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 table presents 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, 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 | )
Year Ended December 31, 2015 |  |  |  |  |  |  |  |  |  |  |  |
Derivative type and location of gains (losses): |  |  |  |  |  |  |  |  |  |  |  |
Commodity: |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  |  |  |  |  |  | $203 |  |  |  |  |
Purchased gas |  |  |  |  |  |  | (15 | ) |  |  |  |
Electric fuel and other energy-related purchases |  |  |  |  |  |  | (1 | ) |  |  |  |
Total commodity |  |  | $230 |  |  |  | $187 |  |  |  | $ 4 |
Interest rate(3) |  |  | (46 | ) |  |  | (11 | ) |  |  | (13 | )
Total |  |  | $184 |  |  |  | $176 |  |  |  | $ (9 | )

(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.

58 |  |  |  |

Derivatives not designated as hedging instruments |  | Amount of Gain (Loss) Recognized in Income on Derivatives(1) |
Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Derivative type and location of gains (losses): |  |  |  |  |  |  |  |  |  |  |  |
Commodity: |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  |  | $ 18 |  |  |  | $ 2 |  |  |  | $ 24 |
Purchased gas |  |  | (3 | ) |  |  | 4 |  |  |  | (14 | )
Electric fuel and other energy-related purchases |  |  | (59 | ) |  |  | (70 | ) |  |  | (14 | )
Other operations & maintenance |  |  | (1 | ) |  |  | 1 |  |  |  | — |
Interest rate(2) |  |  | — |  |  |  | — |  |  |  | (1 | )
Total |  |  | $(45 | ) |  |  | $(63 | ) |  |  | $ (5 | )

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

VIRGINIA POWER

Balance Sheet Presentation

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

|  | December 31, 2017 |  |  | December 31, 2016 |
|  | Gross Amounts of Recognized Assets |  |  | Gross Amounts Offset in the Consolidated Balance Sheet |  |  | Net Amounts of Assets Presented in the Consolidated Balance Sheet |  |  | Gross Amounts of Recognized Assets |  |  | Gross Amounts Offset in the Consolidated Balance Sheet |  |  | Net Amounts of Assets Presented in the Consolidated Balance Sheet |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | $155 |  |  |  | $— |  |  |  | $155 |  |  |  | $147 |  |  |  | $— |  |  |  | $147 |
Interest rate contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 6 |  |  |  | — |  |  |  | 6 |
Total derivatives, subject to a master netting or similar arrangement |  |  | 155 |  |  |  | — |  |  |  | 155 |  |  |  | 153 |  |  |  | — |  |  |  | 153 |
Total derivatives, not subject to a master netting or similar arrangement |  |  | 11 |  |  |  | — |  |  |  | 11 |  |  |  | 41 |  |  |  | — |  |  |  | 41 |
Total |  |  | $166 |  |  |  | $— |  |  |  | $166 |  |  |  | $194 |  |  |  | $— |  |  |  | $194 |

|  |  |  |  | December 31, 2017 |  |  |  |  |  | December 31, 2016 |
|  |  |  |  | Gross Amounts Not Offset in the Consolidated Balance Sheet |  |  |  |  |  |  |  |  | Gross Amounts Not Offset in the Consolidated Balance Sheet |  |  |  |
|  | Net Amounts of Assets Presented in the Consolidated Balance Sheet |  |  | Financial Instruments |  |  | Cash Collateral Received |  |  | Net Amounts |  |  | Net Amounts of Assets Presented in the Consolidated Balance Sheet |  |  | Financial Instruments |  |  | Cash Collateral Received |  |  | Net Amounts |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | $155 |  |  |  | $ 4 |  |  |  | $— |  |  |  | $151 |  |  |  | $147 |  |  |  | $ 2 |  |  |  | $— |  |  |  | $145 |
Interest rate contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 6 |  |  |  | — |  |  |  | — |  |  |  | 6 |
Total |  |  | $155 |  |  |  | $ 4 |  |  |  | $— |  |  |  | $151 |  |  |  | $153 |  |  |  | $ 2 |  |  |  | $— |  |  |  | $151 |

|  |  |  | 59

Combined Notes to Consolidated Financial Statements, Continued

|  | December 31, 2017 |  |  | December 31, 2016 |
|  | Gross Amounts of Recognized Liabilities |  |  | Gross Amounts Offset in the Consolidated Balance Sheet |  |  | Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |  |  | Gross Amounts of Recognized Liabilities |  |  | Gross Amounts Offset in the Consolidated Balance Sheet |  |  | Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | $ 4 |  |  |  | $— |  |  |  | $ 4 |  |  |  | $ 2 |  |  |  | $— |  |  |  | $ 2 |
Interest rate contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | 57 |  |  |  | — |  |  |  | 57 |  |  |  | 21 |  |  |  | — |  |  |  | 21 |
Total derivatives, subject to a master netting or similar arrangement |  |  | 61 |  |  |  | — |  |  |  | 61 |  |  |  | 23 |  |  |  | — |  |  |  | 23 |
Total derivatives, not subject to a master netting or similar arrangement |  |  | 5 |  |  |  | — |  |  |  | 5 |  |  |  | 8 |  |  |  | — |  |  |  | 8 |
Total |  |  | $66 |  |  |  | $— |  |  |  | $66 |  |  |  | $31 |  |  |  | $— |  |  |  | $31 |

|  |  |  |  | December 31, 2017 |  |  |  |  |  | December 31, 2016 |
|  |  |  |  | Gross Amounts Not Offset in the Consolidated Balance Sheet |  |  |  |  |  |  |  |  | Gross Amounts Not Offset in the Consolidated Balance Sheet |  |  |  |
|  | Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |  |  | Financial Instruments |  |  | Cash Collateral Paid |  |  | Net Amounts |  |  | Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |  |  | Financial Instruments |  |  | Cash Collateral Paid |  |  | Net Amounts |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | $ 4 |  |  |  | $ 4 |  |  |  | $— |  |  |  | $— |  |  |  | $ 2 |  |  |  | $ 2 |  |  |  | $— |  |  |  | $— |
Interest rate contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | 57 |  |  |  | — |  |  |  | — |  |  |  | 57 |  |  |  | 21 |  |  |  | — |  |  |  | — |  |  |  | 21 |
Total |  |  | $61 |  |  |  | $ 4 |  |  |  | $— |  |  |  | $57 |  |  |  | $23 |  |  |  | $ 2 |  |  |  | $— |  |  |  | $21 |

Volumes

The following table presents the volume of Virginia Power’s derivative activity at December 31, 2017. 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) |  |  | 33 |  |  |  | 5 |
Basis |  |  | 79 |  |  |  | 540 |
Electricity (MWh): |  |  |  |  |  |  |  |
Fixed price(1) |  |  | 1,453,910 |  |  |  | 364,990 |
FTRs |  |  | 42,582,981 |  |  |  | — |
Interest rate(2) |  | $ | 1,150,000,000 |  |  | $ | 300,000,000 |

(1) | Includes options.

(2) | Maturity is determined based on final settlement period.

Ineffectiveness and AOCI

For the years ended December 31, 2017, 2016 and 2015, gains or losses on hedging instruments determined to be ineffective were not material.

The following table presents selected information related to losses on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at December 31, 2017:

|  | AOCI After-Tax |  |  | Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax |  |  | Maximum Term |
(millions) |  |  |  |  |  |  |  |  |
Interest rate |  |  | $(12 | ) |  |  | $(1 | ) |  |  | 384 months |
Total |  |  | $(12 | ) |  |  | $(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.

60 |  |  |  |

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, 2017 |  |  |  |  |  |  |  |  |  |  |  |
ASSETS |  |  |  |  |  |  |  |  |  |  |  |
Current Assets |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | $— |  |  |  | $ 75 |  |  |  | $ 75 |
Total current derivative assets(1) |  |  | — |  |  |  | 75 |  |  |  | 75 |
Noncurrent Assets |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | — |  |  |  | 91 |  |  |  | 91 |
Total noncurrent derivative assets |  |  | — |  |  |  | 91 |  |  |  | 91 |
Total derivative assets |  |  | $— |  |  |  | $166 |  |  |  | $166 |
LIABILITIES |  |  |  |  |  |  |  |  |  |  |  |
Current Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | $— |  |  |  | $ 9 |  |  |  | $ 9 |
Interest rate |  |  | 44 |  |  |  | — |  |  |  | 44 |
Total current derivative liabilities(2) |  |  | 44 |  |  |  | 9 |  |  |  | 53 |
Noncurrent Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Interest rate |  |  | 13 |  |  |  | — |  |  |  | 13 |
Total noncurrent derivatives liabilities(3) |  |  | 13 |  |  |  | — |  |  |  | 13 |
Total derivative liabilities |  |  | $57 |  |  |  | $ 9 |  |  |  | $ 66 |
At December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |
ASSETS |  |  |  |  |  |  |  |  |  |  |  |
Current Assets |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | $— |  |  |  | $ 60 |  |  |  | $ 60 |
Interest rate |  |  | 6 |  |  |  | — |  |  |  | 6 |
Total current derivative assets(1) |  |  | 6 |  |  |  | 60 |  |  |  | 66 |
Noncurrent Assets |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | — |  |  |  | 128 |  |  |  | 128 |
Total noncurrent derivative assets |  |  | — |  |  |  | 128 |  |  |  | 128 |
Total derivative assets |  |  | $6 |  |  |  | $188 |  |  |  | $194 |
LIABILITIES |  |  |  |  |  |  |  |  |  |  |  |
Current Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | $— |  |  |  | $ 10 |  |  |  | $ 10 |
Interest rate |  |  | 8 |  |  |  | — |  |  |  | 8 |
Total current derivative liabilities(2) |  |  | 8 |  |  |  | 10 |  |  |  | 18 |
Noncurrent Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Interest rate |  |  | 13 |  |  |  | — |  |  |  | 13 |
Total noncurrent derivative liabilities(3) |  |  | 13 |  |  |  | — |  |  |  | 13 |
Total derivative liabilities |  |  | $21 |  |  |  | $ 10 |  |  |  | $ 31 |

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

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

(3) | 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, 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 | )
Year Ended December 31, 2015 |  |  |  |  |  |  |  |  |  |  |  |
Derivative type and location of gains (losses): |  |  |  |  |  |  |  |  |  |  |  |
Commodity: |  |  |  |  |  |  |  |  |  |  |  |
Electric fuel and other energy-related purchases |  |  |  |  |  |  | $(1 | ) |  |  |  |
Total commodity |  |  | $— |  |  |  | $(1 | ) |  |  | $ 4 |
Interest rate(3) |  |  | (3 | ) |  |  | — |  |  |  | (13 | )
Total |  |  | $(3 | ) |  |  | $(1 | ) |  |  | $ (9 | )

(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, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Derivative type and location of gains (losses): |  |  |  |  |  |  |  |  |  |  |  |
Commodity(2) |  |  | $(57 | ) |  |  | $(70 | ) |  |  | $(13 | )
Total |  |  | $(57 | ) |  |  | $(70 | ) |  |  | $(13 | )

(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.

61

Combined Notes to Consolidated Financial Statements, Continued

DOMINION ENERGY GAS

Balance Sheet Presentation

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

|  | December 31, 2017 |  |  | December 31, 2016 |
|  | Gross Amounts of Recognized Assets |  |  | Gross Amounts Offset in the Consolidated Balance Sheet |  |  | Net Amounts of Assets Presented in the Consolidated Balance Sheet |  |  | Gross Amounts of Recognized Assets |  |  | Gross Amounts Offset in the Consolidated Balance Sheet |  |  | Net Amounts of Assets Presented in the Consolidated Balance Sheet |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign currency contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | $32 |  |  |  | $— |  |  |  | $32 |  |  |  | $— |  |  |  | $— |  |  |  | $— |
Total derivatives, subject to a master netting or similar arrangement |  |  | $32 |  |  |  | $— |  |  |  | $32 |  |  |  | $— |  |  |  | $— |  |  |  | $— |

|  |  |  |  | December 31, 2017 |  |  |  |  |  | December 31, 2016 |
|  |  |  |  | Gross Amounts Not Offset in the Consolidated Balance Sheet |  |  |  |  |  |  |  |  | Gross Amounts Not Offset in the Consolidated Balance Sheet |  |  |  |
|  | Net Amounts of Assets Presented in the Consolidated Balance Sheet |  |  | Financial Instruments |  |  | Cash Collateral Received |  |  | Net Amounts |  |  | Net Amounts of Assets Presented in the Consolidated Balance Sheet |  |  | Financial Instruments |  |  | Cash Collateral Received |  |  | Net Amounts |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign currency contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | $32 |  |  |  | $2 |  |  |  | $— |  |  |  | $30 |  |  |  | $— |  |  |  | $— |  |  |  | $— |  |  |  | $— |
Total |  |  | $32 |  |  |  | $2 |  |  |  | $— |  |  |  | $30 |  |  |  | $— |  |  |  | $— |  |  |  | $— |  |  |  | $— |

|  | December 31, 2017 |  |  | December 31, 2016 |
|  | Gross Amounts of Recognized Liabilities |  |  | Gross Amounts Offset in the Consolidated Balance Sheet |  |  | Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |  |  | Gross Amounts of Recognized Liabilities |  |  | Gross Amounts Offset in the Consolidated Balance Sheet |  |  | Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | $6 |  |  |  | $— |  |  |  | $6 |  |  |  | $ 5 |  |  |  | $— |  |  |  | $ 5 |
Foreign currency contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | 2 |  |  |  | — |  |  |  | 2 |  |  |  | 6 |  |  |  | — |  |  |  | 6 |
Total derivatives, subject to a master netting or similar arrangement |  |  | $8 |  |  |  | $— |  |  |  | $8 |  |  |  | $11 |  |  |  | $— |  |  |  | $11 |

|  |  |  |  | December 31, 2017 |  |  |  |  |  | December 31, 2016 |
|  |  |  |  | Gross Amounts Not Offset in the Consolidated Balance Sheet |  |  |  |  |  |  |  |  | Gross Amounts Not Offset in the Consolidated Balance Sheet |  |  |  |
|  | Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |  |  | Financial Instruments |  |  | Cash Collateral Paid |  |  | Net Amounts |  |  | Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |  |  | Financial Instruments |  |  | Cash Collateral Paid |  |  | Net Amounts |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | $6 |  |  |  | $— |  |  |  | $— |  |  |  | $ 6 |  |  |  | $ 5 |  |  |  | $— |  |  |  | $— |  |  |  | $ 5 |
Foreign currency contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Over-the-counter |  |  | 2 |  |  |  | 2 |  |  |  | — |  |  |  | — |  |  |  | 6 |  |  |  | — |  |  |  | — |  |  |  | 6 |
Total |  |  | $8 |  |  |  | $ 2 |  |  |  | $— |  |  |  | $ 6 |  |  |  | $11 |  |  |  | $— |  |  |  | $— |  |  |  | $11 |

62 |  |  |  |

Volumes

The following table presents the volume of Dominion Energy Gas’ derivative activity at December 31, 2017. 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): |  |  |  |  |  |  |  |
Basis |  |  | 1 |  |  |  | — |
NGLs (Gal) |  |  | 40,961,704 |  |  |  | 8,491,200 |
Foreign currency(1) |  | $ | — |  |  | $ | 280,000,000 |

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

Ineffectiveness and AOCI

For the years ended December 31, 2017, 2016 and 2015, gains or losses on hedging instruments determined to be ineffective were not material.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2017:

|  | AOCI After-Tax |  |  | Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax |  |  | Maximum Term |
(millions) |  |  |  |  |  |  |  |  |
Commodities: |  |  |  |  |  |  |  |  |  |  |  |
NGLs |  |  | $ (4 | ) |  |  | $(4 | ) |  |  | 15 months |
Interest rate |  |  | (25 | ) |  |  | (3 | ) |  |  | 324 months |
Foreign currency |  |  | 6 |  |  |  | (1 | ) |  |  | 102 months |
Total |  |  | $(23 | ) |  |  | $(8 | ) |  |  |  |

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

Fair Value and Gains and Losses on Derivative Instruments

The following tables present 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, 2017 |  |  |  |  |  |  |  |  |  |  |  |
ASSETS |  |  |  |  |  |  |  |  |  |  |  |
Noncurrent Assets |  |  |  |  |  |  |  |  |  |  |  |
Foreign currency |  |  | $32 |  |  |  | $— |  |  |  | $32 |
Total noncurrent derivative assets(1) |  |  | 32 |  |  |  | — |  |  |  | 32 |
Total derivative assets |  |  | $32 |  |  |  | $— |  |  |  | $32 |
LIABILITIES |  |  |  |  |  |  |  |  |  |  |  |
Current Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | $ 6 |  |  |  | $— |  |  |  | $ 6 |
Foreign currency |  |  | 2 |  |  |  | — |  |  |  | 2 |
Total current derivative liabilities(2) |  |  | 8 |  |  |  | — |  |  |  | 8 |
Total derivative liabilities |  |  | $ 8 |  |  |  | $— |  |  |  | $ 8 |
At December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |
LIABILITIES |  |  |  |  |  |  |  |  |  |  |  |
Current Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | $ 4 |  |  |  | $— |  |  |  | $ 4 |
Foreign currency |  |  | 3 |  |  |  | — |  |  |  | 3 |
Total current derivative liabilities(2) |  |  | 7 |  |  |  | — |  |  |  | 7 |
Noncurrent Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  | 1 |  |  |  | — |  |  |  | 1 |
Foreign currency |  |  | 3 |  |  |  | — |  |  |  | 3 |
Total noncurrent derivative liabilities(3) |  |  | 4 |  |  |  | — |  |  |  | 4 |
Total derivative liabilities |  |  | $11 |  |  |  | $— |  |  |  | $11 |

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

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

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

63

Combined Notes to Consolidated Financial Statements, Continued

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, 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 | )
Year Ended December 31, 2015 |  |  |  |  |  |  |  |
Derivative Type and Location of Gains (Losses): |  |  |  |  |  |  |  |
Commodity: |  |  |  |  |  |  |  |
Operating revenue |  |  |  |  |  |  | $ 6 |
Total commodity |  |  | $ 16 |  |  |  | $ 6 |
Interest rate(2) |  |  | (6) |  |  |  | — |
Total |  |  | $ 10 |  |  |  | $ 6 |

(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, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Derivative type and location of gains (losses): |  |  |  |  |  |  |  |  |  |  |  |
Commodity |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  |  | $— |  |  |  | $1 |  |  |  | $6 |
Total |  |  | $— |  |  |  | $1 |  |  |  | $6 |

NOTE 8. EARNINGS PER SHARE

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

|  | 2017 |  |  | 2016 |  |  | 2015 |
(millions, except EPS) |  |  |  |  |  |  |  |  |
Net income attributable to Dominion Energy |  | $ | 2,999 |  |  | $ | 2,123 |  |  | $ | 1,899 |
Average shares of common stock outstanding – Basic |  |  | 636.0 |  |  |  | 616.4 |  |  |  | 592.4 |
Net effect of dilutive securities(1) |  |  | — |  |  |  | 0.7 |  |  |  | 1.3 |
Average shares of common stock outstanding – Diluted |  |  | 636.0 |  |  |  | 617.1 |  |  |  | 593.7 |
Earnings Per Common Share – Basic |  | $ | 4.72 |  |  | $ | 3.44 |  |  | $ | 3.21 |
Earnings Per Common Share – Diluted |  | $ | 4.72 |  |  | $ | 3.44 |  |  | $ | 3.20 |

(1) | Dilutive securities consist primarily of the 2013 Equity Units for 2016 and 2015. See Note 17 for more information.

The 2014 Equity Units were excluded from the calculation of diluted EPS for the years ended December 31, 2016 and 2015, as the dilutive stock price threshold was not met. The 2016 Equity Units were excluded from the calculation of diluted EPS for the year ended December 31, 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 are potentially dilutive securities but had no effect on the calculation of diluted EPS for the years ended December 31, 2017 and 2016. See Note 19 for more information.

64 |  |  |  |

NOTE 9. INVESTMENTS

DOMINION ENERGY

Equity and Debt Securities

RABBI TRUST SECURITIES

Marketable equity and debt securities and cash equivalents held in Dominion Energy’s rabbi trusts and classified as trading totaled $112 million and $104 million at December 31, 2017 and 2016, respectively.

DECOMMISSIONING TRUST SECURITIES

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

|  | Amortized Cost |  |  | Total Unrealized Gains(1) |  |  | Total Unrealized Losses(1) |  |  | Fair Value |
(millions) |  |  |  |  |  |  |  |  |  |  |  |
At December 31, 2017 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Marketable equity securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. |  |  | $1,569 |  |  |  | $1,857 |  |  |  | $ — |  |  |  | $3,426 |
Fixed income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
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(2) |  |  | 34 |  |  |  | — |  |  |  | — |  |  |  | 34 |
Total |  |  | $3,200 |  |  |  | $1,899 |  |  |  | $ (6 | )(3) |  |  | $5,093 |
At December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Marketable equity securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. |  |  | $1,449 |  |  |  | $1,408 |  |  |  | $ — |  |  |  | $2,857 |
Fixed income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Corporate debt instruments |  |  | 478 |  |  |  | 13 |  |  |  | (4 | ) |  |  | 487 |
Government securities |  |  | 978 |  |  |  | 22 |  |  |  | (8) |  |  |  | 992 |
Common/collective trust funds |  |  | 67 |  |  |  | — |  |  |  | — |  |  |  | 67 |
Cost method investments |  |  | 69 |  |  |  | — |  |  |  | — |  |  |  | 69 |
Cash equivalents and other(2) |  |  | 12 |  |  |  | — |  |  |  | — |  |  |  | 12 |
Total |  |  | $3,053 |  |  |  | $1,443 |  |  |  | $(12 | )(3) |  |  | $4,484 |

(1) | Included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(2) | Includes pending sales of securities of $5 million and $9 million at December 31, 2017 and 2016, respectively.

(3) | The fair value of securities in an unrealized loss position was $565 million and $576 million at December 31, 2017 and 2016, respectively.

The fair value of Dominion Energy’s marketable debt securities held in nuclear decommissioning trust funds at December 31, 2017 by contractual maturity is as follows:

|  | Amount |
(millions) |  |  |
Due in one year or less |  | $ | 151 |
Due after one year through five years |  |  | 385 |
Due after five years through ten years |  |  | 370 |
Due after ten years |  |  | 659 |
Total |  | $ | 1,565 |

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

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Proceeds from sales |  | $ | 1,831 |  |  | $ | 1,422 |  |  | $ | 1,340 |
Realized gains(1) |  |  | 166 |  |  |  | 128 |  |  |  | 219 |
Realized losses(1) |  |  | 71 |  |  |  | 55 |  |  |  | 84 |

(1) | Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.

|  |  |  | 65

Combined Notes to Consolidated Financial Statements, Continued

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

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Total other-than-temporary impairment losses(1) |  | $ | 44 |  |  | $ | 51 |  |  | $ | 66 |
Losses recorded to the nuclear decomissioning trust regulatory liability |  |  | (16 | ) |  |  | (16 | ) |  |  | (26 | )
Losses recognized in other comprehensive income (before taxes) |  |  | (5 | ) |  |  | (12 | ) |  |  | (9 | )
Net impairment losses recognized in earnings |  | $ | 23 |  |  | $ | 23 |  |  | $ | 31 |

(1) | Amounts include other-than-temporary impairment losses for debt securities of $5 million, $13 million and $9 million at December 31, 2017, 2016 and 2015, respectively.

VIRGINIA POWER

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

|  | Amortized Cost |  |  | Total Unrealized Gains(1) |  |  | Total Unrealized Losses(1) |  |  | Fair Value |
(millions) |  |  |  |  |  |  |  |  |  |  |  |
At December 31, 2017 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Marketable equity securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. |  |  | $ 734 |  |  |  | $831 |  |  |  | $— |  |  |  | $1,565 |
Fixed income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
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(2) |  |  | 22 |  |  |  | — |  |  |  | — |  |  |  | 22 |
Total |  |  | $1,549 |  |  |  | $852 |  |  |  | $(2 | )(3) |  |  | $2,399 |
At December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Marketable equity securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. |  |  | $ 677 |  |  |  | $624 |  |  |  | $— |  |  |  | $1,301 |
Fixed income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Corporate debt instruments |  |  | 274 |  |  |  | 6 |  |  |  | (4 | ) |  |  | 276 |
Government securities |  |  | 420 |  |  |  | 9 |  |  |  | (2 | ) |  |  | 427 |
Common/collective trust funds |  |  | 26 |  |  |  | — |  |  |  | — |  |  |  | 26 |
Cost method investments |  |  | 69 |  |  |  | — |  |  |  | — |  |  |  | 69 |
Cash equivalents and other(2) |  |  | 7 |  |  |  | — |  |  |  | — |  |  |  | 7 |
Total |  |  | $1,473 |  |  |  | $639 |  |  |  | $(6 | )(3) |  |  | $2,106 |

(1) | Included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(2) | Includes pending sales of securities of $6 million and $7 million at December 31, 2017 and 2016, respectively.

(3) | The fair value of securities in an unrealized loss position was $234 million and $287 million at December 31, 2017 and 2016, respectively.

The fair value of Virginia Power’s marketable debt securities at December 31, 2017, by contractual maturity is as follows:

|  | Amount |
(millions) |  |  |
Due in one year or less |  |  | $ 32 |
Due after one year through five years |  |  | 165 |
Due after five years through ten years |  |  | 199 |
Due after ten years |  |  | 348 |
Total |  |  | $744 |

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

Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Proceeds from sales |  | $ | 849 |  |  | $ | 733 |  |  | $ | 639 |
Realized gains(1) |  |  | 75 |  |  |  | 63 |  |  |  | 110 |
Realized losses(1) |  |  | 30 |  |  |  | 27 |  |  |  | 43 |

(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, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Total other-than-temporary impairment losses(1) |  | $ | 20 |  |  | $ | 26 |  |  | $ | 36 |
Losses recorded to the nuclear decomissioning trust regulatory liability |  |  | (16 | ) |  |  | (16 | ) |  |  | (26 | )
Losses recognized in other comprehensive income (before taxes) |  |  | (2 | ) |  |  | (7 | ) |  |  | (6 | )
Net impairment losses recognized in earnings |  | $ | 2 |  |  | $ | 3 |  |  | $ | 4 |

(1) | Amounts include other-than-temporary impairment losses for debt securities of $2 million, $8 million and $6 million at December 31, 2017, 2016 and 2015, 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, |  |  |  |  | 2017 |  |  | 2016 |  |  |  |
(millions) |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Blue Racer |  |  | 50 | % |  | $ | 691 |  |  | $ | 677 |  |  |  | Midstream gas and related services |
Iroquois |  |  | 50 | %(1) |  |  | 311 |  |  |  | 316 |  |  |  | Gas transmission system |
Atlantic Coast Pipeline |  |  | 48 | % |  |  | 382 |  |  |  | 256 |  |  |  | Gas transmission system |
Fowler Ridge |  |  | 50 | % |  |  | 81 |  |  |  | 116 |  |  |  | Wind-powered merchant generation facility |
NedPower |  |  | 50 | % |  |  | — | (2) |  |  | 112 |  |  |  | Wind-powered merchant generation facility |
Other |  |  | various |  |  |  | 79 |  |  |  | 84 |  |  |  |  |
Total |  |  |  |  |  | $ | 1,544 |  |  | $ | 1,561 |  |  |  |  |
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Iroquois |  |  | 24.07 | % |  | $ | 95 |  |  | $ | 98 |  |  |  | Gas transmission system |
Total |  |  |  |  |  | $ | 95 |  |  | $ | 98 |  |  |  |  |

(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.

66 |  |  |  |

(2) | Liability of $17 million associated with NedPower recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets as of December 31, 2017. See additional discussion of NedPower below.

Dominion Energy’s equity earnings on its investments totaled $14 million, $111 million and $56 million in 2017, 2016 and 2015, respectively, included in other income in Dominion Energy’s Consolidated Statements of Income. Dominion Energy received distributions from these investments of $419 million, $104 million and $83 million in 2017, 2016 and 2015, respectively. As of December 31, 2017 and 2016, the carrying amount of Dominion Energy’s investments exceeded its share of underlying equity in net assets by $249 million and $260 million, respectively. These differences are comprised at both December 31, 2017 and 2016 of $176 million, reflecting equity method goodwill that is not being amortized and at December 31, 2017 and 2016, of $73 million and $84 million related to basis differences from Dominion Energy’s investments in Blue Racer and 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 the credit facility.

Dominion Energy Gas’ equity earnings on its investment totaled $21 million in 2017 and 2016 and $23 million in 2015. Dominion Energy Gas received distributions from its investment of $24 million, $22 million and $28 million in 2017, 2016 and 2015, respectively. As of December 31, 2017 and 2016, 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

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 is 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, which is included in property, plant and equipment in Dominion Energy Gas’ Consolidated Balance Sheets.

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, 2017, 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. Public Service Company of North Carolina, Inc. also plans to be a customer of the pipeline under a 20-year contract. 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 $129 million, $95 million and $74 million in 2017, 2016 and 2015, respectively, included in operating revenue in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income. Amounts receivable related to these services were $12 million and $10 million at December 31, 2017 and 2016, 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 $310 million, $184 million and $38 million during 2017, 2016 and 2015, respectively, to Atlantic Coast Pipeline.

Dominion Energy received distributions of $270 million in 2017 from Atlantic Coast Pipeline. No distributions were received in 2016 or 2015.

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 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.

67

Combined Notes to Consolidated Financial Statements, Continued

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, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |
Utility: |  |  |  |  |  |  |  |
Generation |  | $ | 17,602 |  |  | $ | 17,147 |
Transmission |  |  | 15,335 |  |  |  | 14,315 |
Distribution |  |  | 17,408 |  |  |  | 16,381 |
Storage |  |  | 2,887 |  |  |  | 2,814 |
Nuclear fuel |  |  | 1,599 |  |  |  | 1,537 |
Gas gathering and processing |  |  | 219 |  |  |  | 216 |
Oil and gas |  |  | 1,720 |  |  |  | 1,652 |
General and other |  |  | 1,514 |  |  |  | 1,450 |
Plant under construction |  |  | 7,765 |  |  |  | 6,254 |
Total utility |  |  | 66,049 |  |  |  | 61,766 |
Nonutility: |  |  |  |  |  |  |  |
Merchant generation-nuclear |  |  | 1,452 |  |  |  | 1,419 |
Merchant generation-other |  |  | 4,992 |  |  |  | 4,149 |
Nuclear fuel |  |  | 968 |  |  |  | 897 |
Gas gathering and processing |  |  | 630 |  |  |  | 619 |
Other-including plant under construction |  |  | 732 |  |  |  | 706 |
Total nonutility |  |  | 8,774 |  |  |  | 7,790 |
Total property, plant and equipment |  | $ | 74,823 |  |  | $ | 69,556 |
Virginia Power |  |  |  |  |  |  |  |
Utility: |  |  |  |  |  |  |  |
Generation |  | $ | 17,602 |  |  | $ | 17,147 |
Transmission |  |  | 8,332 |  |  |  | 7,871 |
Distribution |  |  | 11,151 |  |  |  | 10,573 |
Nuclear fuel |  |  | 1,599 |  |  |  | 1,537 |
General and other |  |  | 794 |  |  |  | 745 |
Plant under construction |  |  | 2,840 |  |  |  | 2,146 |
Total utility |  |  | 42,318 |  |  |  | 40,019 |
Nonutility-other |  |  | 11 |  |  |  | 11 |
Total property, plant and equipment |  | $ | 42,329 |  |  | $ | 40,030 |
Dominion Energy Gas |  |  |  |  |  |  |  |
Utility: |  |  |  |  |  |  |  |
Transmission |  | $ | 4,732 |  |  | $ | 4,231 |
Distribution |  |  | 3,267 |  |  |  | 3,019 |
Storage |  |  | 1,688 |  |  |  | 1,627 |
Gas gathering and processing |  |  | 202 |  |  |  | 198 |
General and other |  |  | 216 |  |  |  | 184 |
Plant under construction |  |  | 293 |  |  |  | 448 |
Total utility |  |  | 10,398 |  |  |  | 9,707 |
Nonutility: |  |  |  |  |  |  |  |
Gas gathering and processing |  |  | 630 |  |  | $ | 619 |
Other-including plant under construction |  |  | 145 |  |  |  | 149 |
Total nonutility |  |  | 775 |  |  |  | 768 |
Total property, plant and equipment |  | $ | 11,173 |  |  | $ | 10,475 |

DOMINION ENERGY AND VIRGINIA POWER

Jointly-Owned Power Stations

Dominion Energy’s and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2017 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 |  | $ | 1,059 |  |  | $ | 2,504 |  |  | $ | 589 |  |  | $ | 1,217 |
Accumulated depreciation |  |  | (612 | ) |  |  | (1,263 | ) |  |  | (231 | ) |  |  | (381 | )
Nuclear fuel |  |  | — |  |  |  | 745 |  |  |  | — |  |  |  | 552 |
Accumulated amortization of nuclear fuel |  |  | — |  |  |  | (607 | ) |  |  | — |  |  |  | (427 | )
Plant under construction |  |  | 2 |  |  |  | 92 |  |  |  | 6 |  |  |  | 68 |

(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.

Acquisition of Solar Projects

In September 2017, Virginia Power entered into agreements to acquire two solar development projects in North Carolina. The first acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2018, and cost approximately $140 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 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.

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 recognized $11 million during 2017, with the remaining $35 million to be recognized ratably through 2023.

DOMINION ENERGY AND DOMINION ENERGY GAS

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 provide for payments to Dominion Energy Gas, subject to customary

68 |  |  |  |

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 operations and maintenance expense 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 will receive total consideration of $130 million, with $65 million received in 2017 and $65 million to be received by the end of the third quarter of 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 other operations and maintenance expense 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 other operations and maintenance expense in Dominion Energy Gas’ Consolidated Statements of Income associated with the elimination of its overriding royalty interest and expects to recognize an approximately $65 million ($47 million after-tax) gain 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 addi-

tional 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 other operations and maintenance expense 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 the first quarter of 2018.

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. This transaction resulted in a $27 million ($16 million after-tax) gain, included in other operations and maintenance expense in Dominion Energy Gas’ Consolidated Statements of Income.

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 September 2015, Dominion Energy Gas received proceeds of $52 million associated with the conveyance of the acreage, resulting in a $52 million ($29 million after-tax) gain, included in other operations and maintenance expense in Dominion Energy Gas’ Consolidated Statements of Income.

DOMINION ENERGY

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 other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income. Dominion Energy is expected to recognize a benefit of approximately $65 million ($48 million after-tax) in other operations and maintenance expense upon closing of the second phase of the agreement in 2018. 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.

69

Combined Notes to Consolidated Financial Statements, Continued

NOTE 11. GOODWILL AND INTANGIBLE ASSETS

Goodwill

The changes in Dominion Energy’s 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, 2015(2) |  |  | $1,422 |  |  |  | $ 946 |  |  |  | $926 |  |  |  | $— |  |  |  | $3,294 |
Dominion Energy Questar Combination |  |  | — |  |  |  | 3,105 | (3) |  |  | — |  |  |  | — |  |  |  | 3,105 |
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 |
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Balance at December 31, 2015(2) |  |  | $ — |  |  |  | $ 542 |  |  |  | $ — |  |  |  | $— |  |  |  | $ 542 |
No events affecting goodwill |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Balance at December 31, 2016(2) |  |  | $ — |  |  |  | $ 542 |  |  |  | $ — |  |  |  | $— |  |  |  | $ 542 |
No events affecting goodwill |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Balance at December 31, 2017(2) |  |  | $ — |  |  |  | $ 542 |  |  |  | $ — |  |  |  | $— |  |  |  | $ 542 |

(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 $80 million, $73 million and $78 million for 2017, 2016 and 2015, respectively. In 2017, Dominion Energy acquired $147 million of intangible assets, primarily representing software and right-of-use assets, with an estimated weighted-average amortization period of approximately 14 years. Amortization expense for Virginia Power’s intangible assets was $31 million, $29 million and $25 million for 2017, 2016 and 2015, respectively. In 2017, Virginia Power acquired $39 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 7 years. Dominion Energy Gas’ amor-

tization expense for intangible assets was $14 million, $6 million and $18 million for 2017, 2016 and 2015, respectively. In 2017, Dominion Energy Gas acquired $25 million of intangible assets, primarily representing software and right-of-use assets, with an estimated weighted-average amortization period of approximately 14 years. The components of intangible assets are as follows:

|  | 2017 |  |  | 2016 |
At December 31, |  | Gross Carrying Amount |  |  | Accumulated Amortization |  |  | Gross Carrying Amount |  |  | Accumulated Amortization |
(millions) |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Software, licenses and other |  |  | $1,043 |  |  |  | $358 |  |  |  | $955 |  |  |  | $337 |
Virginia Power |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Software, licenses and other |  |  | $ 347 |  |  |  | $114 |  |  |  | $326 |  |  |  | $101 |
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Software, licenses and other |  |  | $ 165 |  |  |  | $ 56 |  |  |  | $147 |  |  |  | $ 49 |

Annual amortization expense for these intangible assets is estimated to be as follows:

|  | 2018 |  |  | 2019 |  |  | 2020 |  |  | 2021 |  |  | 2022 |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy |  | $ | 78 |  |  | $ | 68 |  |  | $ | 56 |  |  | $ | 43 |  |  | $ | 37 |
Virginia Power |  | $ | 30 |  |  | $ | 26 |  |  | $ | 20 |  |  | $ | 13 |  |  | $ | 9 |
Dominion Energy Gas |  | $ | 13 |  |  | $ | 13 |  |  | $ | 12 |  |  | $ | 11 |  |  | $ | 10 |

70 |  |  |  |

NOTE 12. REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities include the following:

At December 31, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |
Regulatory assets: |  |  |  |  |  |  |  |
Deferred rate adjustment clause costs(1) |  | $ | 70 |  |  | $ | 63 |
Deferred nuclear refueling outage costs(2) |  |  | 54 |  |  |  | 71 |
Unrecovered gas costs(3) |  |  | 38 |  |  |  | 19 |
Deferred cost of fuel used in electric generation(4) |  |  | 23 |  |  |  | — |
Other |  |  | 109 |  |  |  | 91 |
Regulatory assets-current |  |  | 294 |  |  |  | 244 |
Unrecognized pension and other postretirement benefit costs(5) |  |  | 1,336 |  |  |  | 1,401 |
Deferred rate adjustment clause costs(1) |  |  | 401 |  |  |  | 329 |
Derivatives(6) |  |  | 223 |  |  |  | 174 |
PJM transmission rates(7) |  |  | 222 |  |  |  | 192 |
Utility reform legislation(8) |  |  | 147 |  |  |  | 99 |
Income taxes recoverable through future rates(9) |  |  | 32 |  |  |  | 123 |
Other |  |  | 119 |  |  |  | 155 |
Regulatory assets-noncurrent |  |  | 2,480 |  |  |  | 2,473 |
Total regulatory assets |  | $ | 2,774 |  |  | $ | 2,717 |
Regulatory liabilities: |  |  |  |  |  |  |  |
Provision for future cost of removal and AROs(10) |  | $ | 101 |  |  | $ | — |
PIPP(11) |  |  | 20 |  |  |  | 28 |
Deferred cost of fuel used in electric generation(4) |  |  | 8 |  |  |  | 61 |
Other |  |  | 64 |  |  |  | 74 |
Regulatory liabilities-current(12) |  |  | 193 |  |  |  | 163 |
Income taxes refundable through future rates(13) |  |  | 4,058 |  |  |  | — |
Provision for future cost of removal and AROs(10) |  |  | 1,384 |  |  |  | 1,427 |
Nuclear decommissioning trust(14) |  |  | 1,121 |  |  |  | 902 |
Derivatives(6) |  |  | 69 |  |  |  | 69 |
Other |  |  | 284 |  |  |  | 224 |
Regulatory liabilities-noncurrent |  |  | 6,916 |  |  |  | 2,622 |
Total regulatory liabilities |  | $ | 7,109 |  |  | $ | 2,785 |
Virginia Power |  |  |  |  |  |  |  |
Regulatory assets: |  |  |  |  |  |  |  |
Deferred rate adjustment clause costs(1) |  | $ | 56 |  |  | $ | 51 |
Deferred nuclear refueling outage costs(2) |  |  | 54 |  |  |  | 71 |
Deferred cost of fuel used in electric generation(4) |  |  | 23 |  |  |  | — |
Other |  |  | 72 |  |  |  | 57 |
Regulatory assets-current |  |  | 205 |  |  |  | 179 |
Deferred rate adjustment clause costs(1) |  |  | 312 |  |  |  | 246 |
PJM transmission rates(7) |  |  | 222 |  |  |  | 192 |
Derivatives(6) |  |  | 190 |  |  |  | 133 |
Income taxes recoverable through future rates(9) |  |  | — |  |  |  | 76 |
Other |  |  | 86 |  |  |  | 123 |
Regulatory assets-noncurrent |  |  | 810 |  |  |  | 770 |
Total regulatory assets |  | $ | 1,015 |  |  | $ | 949 |
Regulatory liabilities: |  |  |  |  |  |  |  |
Provision for future cost of removal(10) |  | $ | 80 |  |  | $ | — |
Deferred cost of fuel used in electric generation(4) |  |  | 8 |  |  |  | 61 |
Other |  |  | 39 |  |  |  | 54 |
Regulatory liabilities-current(12) |  |  | 127 |  |  |  | 115 |
Income taxes refundable through future rates(13) |  |  | 2,581 |  |  |  | — |
Nuclear decommissioning trust(14) |  |  | 1,121 |  |  |  | 902 |
Provision for future cost of removal(10) |  |  | 915 |  |  |  | 946 |
Derivatives(6) |  |  | 69 |  |  |  | 69 |
Other |  |  | 74 |  |  |  | 45 |
Regulatory liabilities-noncurrent |  |  | 4,760 |  |  |  | 1,962 |
Total regulatory liabilities |  | $ | 4,887 |  |  | $ | 2,077 |

At December 31, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
Dominion Energy Gas |  |  |  |  |  |  |  |
Regulatory assets: |  |  |  |  |  |  |  |
Deferred rate adjustment clause costs(1) |  | $ | 14 |  |  | $ | 12 |
Unrecovered gas costs(3) |  |  | 8 |  |  |  | 12 |
Other |  |  | 4 |  |  |  | 2 |
Regulatory assets-current(15) |  |  | 26 |  |  |  | 26 |
Unrecognized pension and other postretirement benefit costs(5) |  |  | 258 |  |  |  | 358 |
Utility reform legislation(8) |  |  | 147 |  |  |  | 99 |
Deferred rate adjustment clause costs(1) |  |  | 89 |  |  |  | 79 |
Income taxes recoverable through future rates(9) |  |  | — |  |  |  | 23 |
Other |  |  | 17 |  |  |  | 18 |
Regulatory assets-noncurrent |  |  | 511 |  |  |  | 577 |
Total regulatory assets |  | $ | 537 |  |  | $ | 603 |
Regulatory liabilities: |  |  |  |  |  |  |  |
PIPP(11) |  | $ | 20 |  |  | $ | 28 |
Provision for future cost of removal and AROs(10) |  |  | 13 |  |  |  | — |
Other |  |  | 5 |  |  |  | 7 |
Regulatory liabilities-current(12) |  |  | 38 |  |  |  | 35 |
Income taxes refundable through future rates(13) |  |  | 998 |  |  |  | — |
Provision for future cost of removal and AROs(10) |  |  | 160 |  |  |  | 174 |
Other |  |  | 69 |  |  |  | 45 |
Regulatory liabilities-noncurrent |  |  | 1,227 |  |  |  | 219 |
Total regulatory liabilities |  | $ | 1,265 |  |  | $ | 254 |

(1) | Primarily reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects for Virginia Power and deferrals of costs associated with certain current and prospective rider projects for Dominion Energy Gas. See Note 13 for more information.

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

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

(4) | Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Dominion Energy’s and Virginia Power’s generation operations. See Note 13 for more information.

(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’s and Dominion Energy Gas’ rate-regulated subsidiaries.

(6) | 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.

(7) | Reflects amount related to the PJM transmission cost allocation matter. See Note 13 for more information.

(8) | 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.

(9) | Amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes. See below for discussion of the 2017 Tax Reform Act.

71

Combined Notes to Consolidated Financial Statements, Continued

(10) | 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.

(11) | Under PIPP, eligible customers can make reduced payments based on their ability to pay. The difference between the customer’s total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rate adjustment clause according to East Ohio tariff provisions. See Note 13 for more information.

(12) | Current regulatory liabilities are presented in other current liabilities in the Consolidated Balance Sheets of the Companies.

(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) | Current regulatory assets are presented in other current assets in the Consolidated Balance Sheets of Dominion Energy Gas.

At December 31, 2017, $390 million of Dominion Energy’s, $273 million of Virginia Power’s and $11 million of Dominion Energy Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. With the exception of the $222 million 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 matters for which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.

FERC—ELECTRIC

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public util-

ities. Dominion Energy’s merchant generators sell electricity in the PJM, MISO, 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. Virginia Power purchases and, under its FERC market-based rate authority, sells electricity in the wholesale market. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.

Rates

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

In March 2010, ODEC and 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 whole-

72 |  |  |  |

sale transmission customers filed petitions for rehearing. While Virginia Power cannot predict the outcome of the matter, it is not expected to have a material effect on results of operations.

PJM Transmission Rates

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

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

In June 2016, PJM, the PJM transmission owners and state commissions representing substantially all of the load in the PJM market submitted a settlement to FERC to resolve the outstanding issues regarding this matter. Under the terms of the settlement, Virginia Power would be required to pay approximately $200 million to PJM over the next 10 years. Although the settlement agreement has not been accepted by FERC, and the settlement is opposed by a small group of parties to the proceeding, Virginia Power believes it is probable it will be required to make payment as an outcome of the settlement. Accordingly, as of December 31, 2017, Virginia Power has a contingent liability of $231 million in other deferred credits and other liabilities, which is offset by a $222 million regulatory asset for the amount that will be recovered through retail rates in Virginia.

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 other operations and maintenance expense in Dominion Energy’s 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. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the other findings 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.

Virginia Power submitted a response to the North Carolina Commission detailing the impact of the 2017 Tax Reform Act on base non-fuel cost of service and Virginia Power’s excess deferred income taxes clarifying that the amounts have been deferred to a regulatory liability. Questar Gas submitted a response to the Utah Commission detailing the impact of the 2017 Tax Reform Act on base rates and the infrastructure rider, and proposing that the benefits be passed back to customers. These filings are pending. Dominion Energy plans to respond to the remaining state regulatory commissions in accordance with the due dates on the issued orders. The Companies will begin to reserve the impacts of the cost of service reduction as a regulatory liability beginning in 2018 until the rates are reset.

To date, the FERC has not issued guidance on how and when to reflect the impacts of the 2017 Tax Reform Act in customer rates.

The Companies have recorded a reasonable estimate of net income taxes refundable through future rates in the jurisdictions in which they operate. Through actions by FERC or state regulators the estimates may be subject to changes that could have a material impact on the Companies’ results of operations, financial condition and/or cash flows.

Other Regulatory Matters

ELECTRIC REGULATION IN VIRGINIA

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 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.

If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings,

73

Combined Notes to Consolidated Financial Statements, Continued

differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.

Regulation Act Legislation

In February 2015, the Virginia Governor signed legislation into law which will keep Virginia Power’s base rates unchanged until at least December 1, 2022. In addition, no biennial reviews will be conducted by the Virginia Commission for the five successive 12-month test periods beginning January 1, 2015, and ending December 31, 2019. The legislation states that Virginia Power’s 2015 biennial review, filed in March 2015, would proceed for the sole purpose of reviewing and determining whether any refunds are due to customers based on earnings performance for generation and distribution services during the 2013 and 2014 test periods. In addition, the legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utility’s ROE for use in connection with rate adjustment clauses and requires utilities to file integrated resource plans annually rather than biennially. In November 2015, the Virginia Commission ordered testimony, briefs and a separate bifurcated hearing in Virginia Power’s then-pending Rider B, R, S, and W cases on whether the Virginia Commission can adjust the ROE applicable to these rate adjustment clauses prior to 2017. In February 2016, the Virginia Commission issued final orders in these cases, stating that it could adjust the ROE for the projects. After separate, additional bifurcated hearings, the Virginia Commission issued final orders setting base ROEs for the Rider GV, C1A and C2A, BW, US-2 and U cases.

In February 2016, certain industrial customers of APCo petitioned the Virginia Commission to issue a declaratory judgment that Virginia legislation enacted in 2015 keeping APCo’s base rates unchanged until at least 2020 (and Virginia Power’s base rates unchanged until at least 2022) is unconstitutional, and to require APCo to make biennial review filings in 2016 and 2018. Virginia Power intervened to support the constitutionality of this legislation. In July 2016, the Virginia Commission held in a divided opinion that this legislation is constitutional, and the industrial customers appealed this order to the Supreme Court of Virginia. In November 2016, the Supreme Court of Virginia granted the appeal as a matter of right and consolidated it for oral argument with other similar appeals from the Virginia Commission’s order. In September 2017, the Supreme Court of Virginia affirmed that the legislation is constitutional.

In March 2017, as required by Regulation Act legislation enacted in February 2015, Virginia Power filed an application for the Virginia Commission to determine the general ROE for Virginia Power’s non-transmission rate adjustment clauses. The application supported a 10.5% ROE for these rate adjustment clauses. In November 2017, the Virginia Commission approved a general 9.2% ROE for these rate adjustment clauses.

2015 Biennial Review

In November 2015, the Virginia Commission issued the 2015 Biennial Review Order. After deciding several contested regulatory earnings adjustments, the Virginia Commission ruled that Virginia Power earned on average an ROE of approximately 10.89% on its generation and distribution services for the combined 2013 and 2014 test periods. Because this ROE was more than 70 basis points above Virginia Power’s authorized ROE of

10.0%, the Virginia Commission ordered that approximately $20 million in excess earnings be credited to customer bills based on usage in 2013 and 2014 over a six-month period beginning within 60 days of the 2015 Biennial Review Order.

Virginia Fuel Expenses

In May 2017, Virginia Power submitted its annual fuel factor to the Virginia Commission to recover an estimated $1.6 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2017. Virginia Power’s proposed fuel rate represented a fuel revenue increase of $279 million when applied to projected kilowatt-hour sales for the period July 1, 2017 to June 30, 2018. In June 2017, the Virginia Commission approved Virginia Power’s proposed fuel rate.

Solar Facility Projects

In February 2017, Virginia Power received approval from the Virginia Commission for a CPCN to construct and operate the Remington solar facility and related distribution interconnection facilities. The 20 MW facility began operations in October 2017 at a total cost of $45 million, excluding financing costs. The facility is the subject of a public-private partnership whereby the Commonwealth of Virginia, a non-jurisdictional customer, compensates Virginia Power for the facility’s net electrical energy output, and Microsoft Corporation purchases all environmental attributes (including renewable energy certificates) generated by the facility. There is no rate adjustment clause associated with this CPCN, nor will any costs of the project be recovered from jurisdictional customers.

In March 2017, Virginia Power received Virginia Commission approval for a CPCN to construct and operate the Oceana solar facility and related distribution interconnection facilities. The 18 MW facility began operations in December 2017 at a total cost of $40 million, excluding financing costs. The facility is the subject of a public-private partnership whereby the Commonwealth of Virginia, a non-jurisdictional customer, compensates Virginia Power for the facility’s net electrical energy output. Virginia Power will retire renewable energy certificates on the Commonwealth of Virginia’s behalf in an amount equal to those generated by the facility. There is no rate adjustment clause associated with the facility, nor will any of its costs be recovered from jurisdictional customers.

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 2017, Virginia Power proposed a $625 million total revenue requirement consisting of $490 million for the transmission component of Virginia Power’s base rates and $135 million for Rider T1. This total revenue requirement represents a $55 million decrease versus the revenues to be produced during the rate year under current rates. In July 2017, the Virginia Commission approved the proposed total revenue requirement, including Rider T1, subject to true-up, for the rate year beginning September 1, 2017.

74 |  |  |  |

• |  | The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In February 2017, the Virginia Commission approved a $243 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2017. It also established a 10.4% ROE effective April 1, 2017. In February 2018, the Virginia Commission approved a $218 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2018. It also established a 10.2% base ROE effective April 1, 2018.

• |  | The Virginia Commission previously approved Rider W in conjunction with Warren County. In February 2017, the Virginia Commission approved a $121 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2017. It also established a 10.4% ROE effective April 1, 2017. In February 2018, the Virginia Commission approved a $109 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2018. It also established a 10.2% ROE for Rider W effective April 1, 2018.

• |  | The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In February 2017, the Virginia Commission approved a $72 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2017. It also established a 10.4% ROE effective April 1, 2017. In February 2018, the Virginia Commission approved a $66 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2018. It also established a 10.2% ROE for Rider R effective April 1, 2018.

• |  | The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In February 2017, the Virginia Commission approved a $27 million revenue requirement for the rate year beginning April 1, 2017. It also established an 11.4% ROE effective April 1, 2017. In June 2017, Virginia Power proposed a $42 million revenue requirement for the rate year beginning April 1, 2018, which represents a $15 million increase over the previous year. This case is pending.

• |  | The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by prior Virginia legislation. In September 2017, the Virginia Commission approved a total $22 million annual revenue requirement effective October 1, 2017, using a 9.4% ROE, and a total capital investment of $40 million for second phase conversions.

• |  | The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In June 2017, the Virginia Commission approved a $28 million revenue requirement, subject to true-up, for the rate year beginning July 1, 2017. It also established a 9.4% ROE for Riders C1A and C2A effective July 1, 2017. In October 2017, Virginia Power requested approval to extend one existing energy efficiency program for five years with a new $25 million cost cap, and proposed a total $31 million revenue requirement for the rate year beginning July 1, 2018, which represents a $3 million increase over the previous year. This case is pending.

• |  | The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In April 2017, the Virginia Commission established a 10.4% ROE for Rider BW effective September 1, 2017. In June 2017, it approved a

|  | $127 million revenue requirement, subject to true-up, for the rate year beginning September 1, 2017. In October 2017, Virginia Power proposed a $132 million revenue requirement for the rate year beginning September 1, 2018, which represents a $5 million increase over the previous year. This case is pending.

• |  | The Virginia Commission previously approved Rider US-2 in conjunction with the Scott Solar, Whitehouse, and Woodland solar facilities. In April 2017, the Virginia Commission established a 9.4% ROE for Rider US-2 effective September 1, 2017. In June 2017, the Virginia Commission approved a $10 million revenue requirement, subject to true-up, for the rate year beginning September 1, 2017. In October 2017, Virginia Power proposed a $15 million revenue requirement for the rate year beginning September 1, 2018, which represents a $5 million increase over the previous year. This case is pending.

• |  | The Virginia Commission previously approved Rider GV in conjunction with Greensville County. In February 2017, the Virginia Commission approved an $82 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2017. It also established a 9.4% ROE effective April 1, 2017. In February 2018, the Virginia Commission approved an $82 million revenue requirement, subject to true-up, for the rate year beginning April 1, 2018. It also established a 9.2% ROE effective April 1, 2018.

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. These lawsuits are pending.

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

75

Combined Notes to Consolidated Financial Statements, Continued

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 $55 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. This matter is pending.

In November 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to construct and operate in multiple Virginia counties an approximately 38 mile overhead 230 kV transmission line between the Remington and Gordonsville substations, along with associated facilities. In August 2017, the Virginia Commission granted a CPCN for the project. The total estimated cost of the project is approximately $105 million.

In March 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in multiple Virginia counties approximately 33 miles of the existing 500 kV transmission line between the Cunningham switching station and the Dooms substation, along with associated station work. In May 2017, the Virginia Commission granted a CPCN to construct and operate the project. The total estimated cost of the project is approximately $60 million.

In August 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in multiple Virginia counties approximately 28 miles of the existing 500 kV transmission line between the Carson switching station and a terminus located near the Rogers Road switching station under construction in Greensville County, Virginia, along with associated work at the Carson switching station. In March 2017, the Virginia Commission granted a CPCN to construct and operate the project. The total estimated cost of the project is approximately $55 million.

In January 2017, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and rearrange its Idylwood substation in Fairfax County, Virginia. In September 2017, the Virginia Commission granted a CPCN for the project. The total estimated cost of the project is approximately $110 million.

In June 2017, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in Prince William County, Virginia, approximately 9 miles of existing 115 kV transmission lines between Possum Point Switching Station and NOVEC’s Smoketown delivery point, utilizing 230 kV design on the majority of the route, for total estimated cost of approximately $20 million. In February 2018, the Virginia Commission granted a CPCN for the project.

In September 2017, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in Augusta County, Virginia approximately 18 miles of the existing 500 kV transmission line between the Dooms substation and the Valley substation, along with associated substation work, for a total estimated cost of approximately $65 million. This case is pending.

In November 2017, Virginia Power filed an application with the Virginia Commission for a CPCN to build and operate in Fairfax County, Virginia approximately 4 miles of 230 kV transmission line between the Idylwood and Tysons substations, along with associated substation work. The total estimated cost of the project is approximately $125 million. This case is pending.

In February 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in Lancaster County, Virginia and Middlesex County, Virginia and across the Rappahannock River, approximately 2 miles of existing 115 kV transmission lines between Harmony Village Substation and White Stone Substation. In December 2017, the Virginia Commission granted a CPCN for the project to be constructed under the Rappahannock River. The total estimated cost of the project is approximately $85 million.

North Anna

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna nuclear power station. If Virginia Power decides to build a new unit, it would require a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In June 2017, the NRC issued the COL. Virginia Power has not yet committed to building a new nuclear unit at North Anna nuclear power station.

Requests by BREDL for a contested NRC hearing on Virginia Power’s COL application were dismissed, and in September 2016, the U.S. Court of Appeals for the D.C. Circuit dismissed with prejudice petitions for judicial review that BREDL and other organizations had filed challenging the NRC’s reliance on a rule generically assessing the environmental impacts of continued onsite storage of spent nuclear fuel in various licensing proceedings, including Virginia Power’s COL proceeding. This dismissal followed the Court’s June 2016 decision in New York v. NRC, upholding the NRC’s continued storage rule and August 2016 denial of requests for rehearing en banc. Therefore, the contested portion of the COL proceeding was closed. The NRC is required to conduct a hearing in all COL proceedings. This mandatory NRC hearing was held in March 2017, was uncontested and the resulting NRC decision authorized issuance of the COL.

In August 2016, Virginia Power received a 60-day notice of intent to sue from the Sierra Club alleging Endangered Species Act violations. The notice alleges that the U.S. Army Corps of Engineers failed to conduct adequate environmental and consultation reviews, related to a potential third nuclear unit located at North Anna, prior to issuing a CWA section 404 permit to Virginia Power in September 2011. No lawsuit was filed and in November 2016, the Army Corps of Engineers suspended the section 404 permit while it gathered additional information. The section 404 permit was reinstated in April 2017.

NORTH CAROLINA REGULATION

In August 2017, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its

76 |  |  |  |

electric rates. Virginia Power proposed a total $15 million increase to the fuel component of its electric rates for the rate year beginning January 1, 2018. In January 2018, the North Carolina Commission approved Virginia Power’s proposed fuel charge adjustment.

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 2017, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2016 costs. The filing reflects gross plant investment for 2016 of $188 million, cumulative gross plant investment of $1.2 billion and a revenue requirement of $157 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 2017, the Ohio Commission approved East Ohio’s application to adjust its AMR cost recovery rate for 2016 costs. The filing reflects a revenue requirement of approximately $6 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 July 2017, East Ohio’s annual update of the PIPP Rider was automatically approved by the Ohio Commission after a 45-day waiting period from the date of the filing. The revised rider rate reflects the recovery over the twelve-month period from July 2017 through June 2018 of projected deferred program costs of approximately $19 million from April 2017 through June 2018, net of a refund for over-recovery of accumulated arrearages of approximately $20 million as of March 31, 2017.

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 2017, 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 $12 million as of March 31, 2017, and recovery of prospective net bad debt expense projected to total approximately $22 million for the twelve-month period from April 2017 to March 2018.

Ohio Legislation

In March 2017, the Governor of Ohio signed legislation into law that allows utilities to file an application to recover infrastructure development costs associated with economic development projects. The new cost recovery provision allows for projects totaling up to $22 million for East Ohio subject to Ohio Commission approval.

DSM Rider

East Ohio has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In December 2017, East Ohio filed an application with the Ohio Commission seeking approval of an adjustment to the DSM rider to recover a total of $5 million, which includes an under-recovery of costs during the preceding 12-month period. This application is pending.

WEST VIRGINIA REGULATION

In October 2017, the West Virginia Commission approved Hope’s application for new PREP customer rates, for the year beginning November 1, 2017, that provide for projected revenue of $4 million related to capital investments of $21 million, $27 million and $31 million for 2016, 2017 and 2018, respectively.

UTAH AND WYOMING REGULATION

In October 2017, Questar Gas submitted filings with both the Utah Commission and the Wyoming Commission for an approximately $25 million gas cost increase reflecting forecasted increases in commodity and transportation costs. The Utah Commission and the Wyoming Commission both approved the filings in October 2017 with rates effective November 2017.

FERC—GAS

Cove Point

In November 2016, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with 23 proposed rates to be effective January 1, 2017. Cove Point proposed an annual cost-of-service of approximately $140 million. In December 2016, FERC accepted a January 1, 2017 effective date for all proposed rates but five which were suspended to be effective June 1, 2017. Under the terms of the settlement agreement filed by Cove Point in August 2017 and approved by FERC in November 2017, Cove Point’s rates effective October 2017 result in decreases to annual revenues and depreciation expense of approximately $18 million and $3 million, respectively, compared to the rates in effect through December 2016.

DETI

In September 2017, DETI submitted its annual transportation cost rate adjustment to FERC requesting approval to recover $39 million. Also in September 2017, DETI submitted its annual electric power cost adjustment to FERC requesting approval to recover $6 million. In October 2017, FERC approved these adjustments.

77

Combined Notes to Consolidated Financial Statements, Continued

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’s 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’s 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’s and Virginia Power’s generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs during 2016 and 2017 were as follows:

|  | Amount |
(millions) |  |  |
Dominion Energy |  |  |  |
AROs at December 31, 2015 |  | $ | 2,103 |
Obligations incurred during the period(1) |  |  | 204 |
Obligations settled during the period |  |  | (171 | )
Revisions in estimated cash flows(2) |  |  | 245 |
Accretion |  |  | 104 |
AROs at December 31, 2016(3) |  | $ | 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(3) |  | $ | 2,432 |
Virginia Power |  |  |  |
AROs at December 31, 2015 |  | $ | 1,247 |
Obligations incurred during the period |  |  | 9 |
Obligations settled during the period |  |  | (115 | )
Revisions in estimated cash flows(2) |  |  | 245 |
Accretion |  |  | 57 |
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 |
Dominion Energy Gas |  |  |  |
AROs at December 31, 2015 |  | $ | 149 |
Obligations incurred during the period |  |  | 6 |
Obligations settled during the period |  |  | (8 | )
Accretion |  |  | 9 |
AROs at December 31, 2016(4) |  | $ | 156 |
Obligations incurred during the period |  |  | 2 |
Obligations settled during the period |  |  | (7 | )
Accretion |  |  | 9 |
AROs at December 31, 2017(4) |  | $ | 160 |

(1) | Primarily reflects AROs assumed in the Dominion Energy Questar Combination. See Note 3 for further information.

(2) | Primarily reflects future ash pond and landfill closure costs at certain utility generation facilities. See Note 22 for further information.

(3) | Includes $249 million and $263 million reported in other current liabilities at December 31, 2016, and 2017, respectively.

(4) | Includes $147 million and $146 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities, at December 31, 2016 and 2017, respectively.

Dominion Energy and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31, 2017 and 2016, the aggregate fair value of Dominion Energy’s trusts, consisting primarily of equity and debt securities, totaled $5.1 billion and $4.5 billion, respectively. At December 31, 2017 and 2016, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $2.4 billion and $2.1 billion, respectively.

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, 2017, Dominion Energy owns the general partner, 50.6% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owns a preferred equity interest and the general partner interest in Cove Point. Additionally, 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 limited partners or 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 Dominion Energy Midstream, SBL Holdco and the merchant solar facilities, and Dominion Energy Midstream is the primary beneficiary of Cove Point, as they have the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Dominion Energy’s securities due within one year and long-term debt include $30 million and $332 million, respectively, of debt issued in 2016 by SBL Holdco net of issuance costs that is nonrecourse to Dominion Energy and is secured by SBL Holdco’s interest in the 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

78 |  |  |  |

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’s 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 five 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 2015 and two additional contracts 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 $200 million as of December 31, 2017. Virginia Power paid $86 million, $144 million, and $200 million for electric capacity and $24 million, $31 million, and $83 million for electric energy to these entities for the years ended December 31, 2017, 2016 and 2015, 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 $340 million and $126 million, $346 million and $123 million, and $318 million and $115 million for the years ended December 31, 2017, 2016 and 2015, respectively. 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.

DOMINION ENERGY

Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:

|  | Facility Limit |  |  | Outstanding Commercial Paper(2) |  |  | Outstanding Letters of Credit |  |  | Facility Capacity Available |
(millions) |  |  |  |  |  |  |  |  |  |  |  |
At December 31, 2017 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Joint revolving credit facility(1) |  | $ | 5,000 |  |  |  | $3,298 |  |  |  | $ — |  |  | $ | 1,702 |
Joint revolving credit facility(1) |  |  | 500 |  |  |  | — |  |  |  | 76 |  |  |  | 424 |
Total |  | $ | 5,500 |  |  |  | $3,298 |  |  |  | $76 |  |  | $ | 2,126 |
At December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Joint revolving credit facility(1) |  | $ | 5,000 |  |  |  | $3,155 |  |  |  | $ — |  |  | $ | 1,845 |
Joint revolving credit facility(1) |  |  | 500 |  |  |  | — |  |  |  | 85 |  |  |  | 415 |
Total |  | $ | 5,500 |  |  |  | $3,155 |  |  |  | $85 |  |  | $ | 2,260 |

79

Combined Notes to Consolidated Financial Statements, Continued

(1) | These credit facilities mature in April 2020 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.

(2) | The weighted-average interest rates of the outstanding commercial paper supported by Dominion Energy’s credit facilities were 1.61% and 1.05% at December 31, 2017 and 2016, respectively.

Questar Gas’ short-term financing is supported through its access as co-borrower to the two joint revolving credit facilities discussed above with Dominion Energy, Virginia Power and Dominion Energy Gas. At December 31, 2017, the aggregate sub-limit for Questar Gas was $250 million. In December 2016, Questar Gas entered into a commercial paper program pursuant to which it began accessing the commercial paper markets.

Dominion Energy has indicated its intention to replace the existing two joint revolving credit facilities with a $6.0 billion joint revolving credit facility in the first quarter of 2018. Terms and covenants of the new credit facility are expected to be similar to the existing credit facilities, including that Virginia Power, Dominion Energy Gas and Questar Gas will remain as co-borrowers, except that the maturity will be in five years and the maximum allowed total debt to total capital ratio, with respect to Dominion Energy only, will be increased from 65% to 67.5%. In February 2018, Virginia Power, as co-borrower, filed with the Virginia Commission for approval.

In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which have 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 have 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, 2017, no amounts were outstanding under either of these facilities.

In February 2018, Dominion Energy borrowed $950 million under a 364-Day Term Loan Agreement that bears interest at a variable rate. In addition, the agreement contains a maximum allowed total debt to total capital ratio of 67.5%.

VIRGINIA POWER

Virginia Power’s short-term financing is supported through its access as co-borrower to the two joint revolving credit facilities. These credit facilities can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

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(1) |  |  | Outstanding Commercial Paper(2) |  |  | Outstanding Letters of Credit |
(millions) |  |  |  |  |  |  |  |  |
At December 31, 2017 |  |  |  |  |  |  |  |  |  |  |  |
Joint revolving credit facility(1) |  |  | $5,000 |  |  |  | $542 |  |  |  | $— |
Joint revolving credit facility(1) |  |  | 500 |  |  |  | — |  |  |  | — |
Total |  |  | $5,500 |  |  |  | $542 |  |  |  | $— |
At December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |
Joint revolving credit facility(1) |  |  | $5,000 |  |  |  | $ 65 |  |  |  | $— |
Joint revolving credit facility(1) |  |  | 500 |  |  |  | — |  |  |  | 1 |
Total |  |  | $5,500 |  |  |  | $ 65 |  |  |  | $ 1 |

(1) | The full amount of the facilities is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. Sub-limits for Virginia Power are set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2017, the sub-limit for Virginia Power was an aggregate $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. These facilities mature in April 2020 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.

(2) | The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 1.65% and 0.97% at December 31, 2017 and 2016, respectively.

In addition to the credit facility commitments mentioned above, Virginia Power also has a $100 million credit facility with a maturity date of April 2020. As of December 31, 2017, this facility supports $100 million of certain variable rate tax-exempt financings of Virginia Power. In February 2018, Virginia Power provided notice to redeem all $100 million of outstanding variable rate tax-exempt financings supported by this credit facility.

DOMINION ENERGY GAS

Dominion Energy Gas’ short-term financing is supported by its access as co-borrower to the two joint revolving credit facilities. These credit facilities can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

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(1) |  |  | Outstanding Commercial Paper(2) |  |  | Outstanding Letters of Credit |
(millions) |  |  |  |  |  |  |  |  |
At December 31, 2017 |  |  |  |  |  |  |  |  |  |  |  |
Joint revolving credit facility(1) |  |  | $1,000 |  |  |  | $629 |  |  |  | $— |
Joint revolving credit facility(1) |  |  | 500 |  |  |  | — |  |  |  | — |
Total |  |  | $1,500 |  |  |  | $629 |  |  |  | $— |
At December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |
Joint revolving credit facility(1) |  |  | $1,000 |  |  |  | $460 |  |  |  | $— |
Joint revolving credit facility(1) |  |  | 500 |  |  |  | — |  |  |  | — |
Total |  |  | $1,500 |  |  |  | $460 |  |  |  | $— |

(1) | A maximum of a combined $1.5 billion of the facilities 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. Sub-limits for Dominion Energy Gas are set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2017, the sub-limit for Dominion Energy Gas was an aggregate $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. These credit facilities mature in April 2020 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.

(2) | The weighted-average interest rate of the outstanding commercial paper supported by these credit facilities was 1.57% and 1.00% at December 31, 2017 and 2016, respectively.

80 |  |  |  |

NOTE 17. LONG-TERM DEBT

At December 31, |  | 2017 Weighted- average Coupon(1) |  |  | 2017 |  |  | 2016 |
(millions, except percentages) |  |  |  |  |  |  |  |  |
Dominion Energy Gas Holdings, LLC: |  |  |  |  |  |  |  |  |  |  |  |
Unsecured Senior Notes: |  |  |  |  |  |  |  |  |  |  |  |
2.5% and 2.8%, due 2019 and 2020 |  |  | 2.68 | % |  | $ | 1,150 |  |  | $ | 1,150 |
2.875% to 4.8%, due 2023 to 2044(2) |  |  | 3.90 | % |  |  | 2,450 |  |  |  | 2,413 |
Dominion Energy Gas Holdings, LLC total principal |  |  |  |  |  | $ | 3,600 |  |  | $ | 3,563 |
Unamortized discount and debt issuance costs |  |  |  |  |  |  | (30 | ) |  |  | (35 | )
Dominion Energy Gas Holdings, LLC total long-term debt |  |  |  |  |  | $ | 3,570 |  |  | $ | 3,528 |
Virginia Electric and Power Company: |  |  |  |  |  |  |  |  |  |  |  |
Unsecured Senior Notes: |  |  |  |  |  |  |  |  |  |  |  |
1.2% to 7.25%, due 2017 to 2022 |  |  | 3.92 | % |  | $ | 1,950 |  |  | $ | 2,554 |
2.75% to 8.875%, due 2023 to 2047 |  |  | 4.53 | % |  |  | 8,690 |  |  |  | 7,190 |
Tax-Exempt Financings(3): |  |  |  |  |  |  |  |  |  |  |  |
Variable rates, due 2017 to 2027 |  |  | 1.27 | % |  |  | 100 |  |  |  | 175 |
1.75% to 5.6%, due 2023 to 2041 |  |  | 2.25 | % |  |  | 678 |  |  |  | 678 |
Virginia Electric and Power Company total principal |  |  |  |  |  | $ | 11,418 |  |  | $ | 10,597 |
Securities due within one year |  |  | 4.17 | % |  |  | (850 | ) |  |  | (678 | )
Unamortized discount, premium and debt issuances costs, net |  |  |  |  |  |  | (72 | ) |  |  | (67 | )
Virginia Electric and Power Company total long-term debt |  |  |  |  |  | $ | 10,496 |  |  | $ | 9,852 |
Dominion Energy, Inc.: |  |  |  |  |  |  |  |  |  |  |  |
Unsecured Senior Notes: |  |  |  |  |  |  |  |  |  |  |  |
Variable rates, due 2019 and 2020 |  |  | 1.99 | % |  | $ | 800 |  |  | $ | — |
1.25% to 6.4%, due 2017 to 2022 |  |  | 2.95 | % |  |  | 5,800 |  |  |  | 5,750 |
2.85% to 7.0%, due 2024 to 2044 |  |  | 4.72 | % |  |  | 5,049 |  |  |  | 4,649 |
Tax-Exempt Financing, variable rate, due 2041(4) |  |  |  |  |  |  | — |  |  |  | 75 |
Unsecured Junior Subordinated Notes: |  |  |  |  |  |  |  |  |  |  |  |
2.579% to 4.104%, due 2019 to 2021 |  |  | 3.08 | % |  |  | 2,100 |  |  |  | 1,100 |
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 |  |  | 4.15 | % |  |  | 422 |  |  |  | 422 |
Remarketable Subordinated Notes, 1.5% and 2.0%, due 2020 to 2024 |  |  | 2.00 | % |  |  | 1,400 |  |  |  | 2,400 |
Unsecured Debentures and Senior Notes(5): |  |  |  |  |  |  |  |  |  |  |  |
6.8% and 6.875%, due 2026 and 2027 |  |  | 6.81 | % |  |  | 89 |  |  |  | 89 |
Term Loan, variable rate, due 2017(6) |  |  |  |  |  |  | — |  |  |  | 250 |
Unsecured Senior and Medium-Term Notes(6): |  |  |  |  |  |  |  |  |  |  |  |
5.31% to 6.85%, due 2017 and 2018 |  |  | 5.72 | % |  |  | 120 |  |  |  | 135 |
2.98% to 7.20%, due 2024 to 2051 |  |  | 4.37 | % |  |  | 600 |  |  |  | 500 |
Term Loans, variable rates, due 2023 and 2024(7) |  |  | 3.74 | % |  |  | 638 |  |  |  | 405 |
Tax-Exempt Financing, 1.55%, due 2033(8) |  |  | 1.55 | % |  |  | 27 |  |  |  | 27 |
Dominion Energy Midstream Partners, LP: |  |  |  |  |  |  |  |  |  |  |  |
Term Loan, variable rate, due 2019 |  |  | 2.74 | % |  |  | 300 |  |  |  | 300 |
Unsecured Senior and Medium-Term Notes, 5.83% and 6.48%, due 2018(9) |  |  | 5.84 | % |  |  | 255 |  |  |  | 255 |
Unsecured Senior Notes, 4.875%, due 2041(9) |  |  | 4.88 | % |  |  | 180 |  |  |  | 180 |
Dominion Energy Gas Holdings, LLC total principal (from above) |  |  |  |  |  |  | 3,600 |  |  |  | 3,563 |
Virginia Electric and Power Company total principal (from above) |  |  |  |  |  |  | 11,418 |  |  |  | 10,597 |
Dominion Energy, Inc. total principal |  |  |  |  |  | $ | 34,293 |  |  | $ | 32,192 |
Fair value hedge valuation(10) |  |  |  |  |  |  | (22 | ) |  |  | (1 | )
Securities due within one year(11) (12) |  |  | 3.44 | % |  |  | (3,078 | ) |  |  | (1,709 | )
Unamortized discount, premium and debt issuance costs, net |  |  |  |  |  |  | (245 | ) |  |  | (251 | )
Dominion Energy, Inc. total long-term debt |  |  |  |  |  | $ | 30,948 |  |  | $ | 30,231 |

(1) | Represents weighted-average coupon rates for debt outstanding as of December 31, 2017.

(2) | Amount includes foreign currency remeasurement adjustments.

(3) | These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. As of December 31, 2017, certain variable rate tax-exempt financings are supported by a $100 million credit facility that terminates in April 2020. In February 2018, Virginia Power provided notice to redeem three series of variable rate tax-exempt financings with an aggregate outstanding principal of $100 million. The financings would otherwise mature in 2024, 2026 and 2027.

(4) | Represents variable rate Massachusetts Development Finance Agency Solid Waste Disposal Revenue Bonds due in 2041 repaid in August 2017.

|  |  |  | 81

Combined Notes to Consolidated Financial Statements, Continued

(5) | Represents debt assumed by Dominion Energy from the merger of its former CNG subsidiary.

(6) | Represents debt obligations of Dominion Energy Questar or Questar Gas. See Note 3 for more information.

(7) | 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’s and Dominion Solar Projects III, Inc.’s interest in certain merchant solar facilities.

(8) | Represents debt obligations of a DGI subsidiary.

(9) | Represents debt obligations of Dominion Energy Questar Pipeline. See Note 3 for more information.

(10) | Represents the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt.

(11) | Excludes $250 million of Dominion Energy Questar Pipeline’s senior notes that matured in February 2018 which were repaid using proceeds from the January 2018 issuance, through private placement, of $100 million of 3.53% senior notes and $150 million of 3.91% senior notes that mature in 2028 and 2038, respectively.

(12) | 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, 2017, were as follows:

|  | 2018 |  |  | 2019 |  |  | 2020 |  |  | 2021 |  |  | 2022 |  |  | Thereafter |  |  | Total |
(millions, except percentages) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy Gas |  | $ | — |  |  | $ | 450 |  |  | $ | 700 |  |  | $ | — |  |  | $ | — |  |  | $ | 2,450 |  |  | $ | 3,600 |
Weighted-average Coupon |  |  |  |  |  |  | 2.50 | % |  |  | 2.80 | % |  |  |  |  |  |  |  |  |  |  | 3.90 | % |  |  |  |
Virginia Power |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unsecured Senior Notes |  | $ | 850 |  |  | $ | 350 |  |  | $ | — |  |  | $ | — |  |  | $ | 750 |  |  | $ | 8,690 |  |  | $ | 10,640 |
Tax-Exempt Financings |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 778 |  |  |  | 778 |
Total |  | $ | 850 |  |  | $ | 350 |  |  | $ | — |  |  | $ | — |  |  | $ | 750 |  |  | $ | 9,468 |  |  | $ | 11,418 |
Weighted-average Coupon |  |  | 4.17 | % |  |  | 5.00 | % |  |  |  |  |  |  |  |  |  |  | 3.15 | % |  |  | 4.33 | % |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Term Loans(1) |  | $ | 36 |  |  | $ | 336 |  |  | $ | 35 |  |  | $ | 35 |  |  | $ | 34 |  |  | $ | 462 |  |  | $ | 938 |
Unsecured Senior Notes(2) |  |  | 3,275 |  |  |  | 3,400 |  |  |  | 1,000 |  |  |  | 900 |  |  |  | 1,500 |  |  |  | 17,058 |  |  |  | 27,133 |
Tax-Exempt Financings |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 805 |  |  |  | 805 |
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 |
Total |  | $ | 3,311 |  |  | $ | 4,286 |  |  | $ | 2,035 |  |  | $ | 2,185 |  |  | $ | 1,534 |  |  | $ | 20,942 |  |  | $ | 34,293 |
Weighted-average Coupon |  |  | 3.62 | % |  |  | 2.89 | % |  |  | 2.58 | % |  |  | 3.12 | % |  |  | 2.97 | % |  |  | 4.38 | % |  |  |  |

(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, 2017, $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 2018, $250 million of Dominion Energy Questar Pipeline’s senior notes were repaid using proceeds from the January 2018 issuance, through private placements, of $100 million of 3.53% senior notes and $150 million of 3.91% senior notes that mature in 2028 and 2038, respectively. As a result, at December 31, 2017, $250 million was included in long-term debt in the Consolidated Balance Sheets.

The Companies short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2017, there were no events of default under these covenants.

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. Beginning June 30, 2016, 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 pro-

82 |  |  |  |

ceeds Dominion Energy receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.

In 2015, Dominion Energy purchased and cancelled $14 million and $3 million of the June 2006 hybrids and the September 2006 hybrids, respectively. 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, 2017, 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 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.

83

Combined Notes to Consolidated Financial Statements, Continued

Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion Energy will issue between 15.0 million and 18.8 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 $101 million and $94 million were made in 2017 and 2016, respectively, including payments for the remarketed 2013 Series A and B notes and the remarketed 2014 Series A notes. The stock purchase contract liability was $111 million and $212 million at December 31, 2017 and 2016, 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.

84 |  |  |  |

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, 2017 or 2016.

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, 2017 or 2016.

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. In January 2014, Dominion Energy began purchasing its common stock on the open market for these plans. In April 2014, Dominion Energy began issuing new common shares for these direct stock purchase plans.

During 2017, Dominion Energy received cash proceeds, net of fees and commissions, of $1.3 billion from the issuance of approximately 17 million shares of common stock through various programs resulting in approximately 645 million shares of common stock outstanding at December 31, 2017. These proceeds include cash of $302 million received from the issuance of 3.8 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 has 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 has no remaining ability to issue stock under the 2017 sales agency agreements and has completed the program.

VIRGINIA POWER

In 2017, 2016 and 2015, Virginia Power did not issue any shares of its common stock to Dominion Energy.

Shares Reserved for Issuance

At December 31, 2017, Dominion Energy had approximately 67 million shares reserved and available for issuance for Dominion Energy Direct®, employee stock awards, employee savings plans, director stock compensation plans and issuance in connection with stock purchase contracts. See Note 17 for more information.

Repurchase of Common Stock

Dominion Energy did not repurchase any shares in 2017 or 2016 and does not plan to repurchase shares during 2018, 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 and 887,000 common units for $25 million for the years ended December 31, 2016 and 2015, respectively.

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 are entitled to receive cumulative quarterly distributions payable in cash or additional convertible preferred units, subject to certain conditions. The units are 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. The conversion of such units would result in a potential increase to Dominion Energy’s net income attributable to noncontrolling interests.

85

Combined Notes to Consolidated Financial Statements, Continued

Accumulated Other Comprehensive Income (Loss)

Presented in the table below is a summary of AOCI by component:

At December 31, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |
Net deferred losses on derivatives-hedging activities, net of tax of $188 and $173 |  | $ | (301 | ) |  | $ | (280 | )
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(419) and $(318) |  |  | 747 |  |  |  | 569 |
Net unrecognized pension and other postretirement benefit costs, net of tax of $692 and $691 |  |  | (1,101 | ) |  |  | (1,082 | )
Other comprehensive loss from equity method investees, net of tax of $2 and $4 |  |  | (3 | ) |  |  | (6 | )
Total AOCI, including noncontrolling interest |  | $ | (658 | ) |  | $ | (799 | )
Less other comprehensive income attributable to noncontrolling interest |  |  | 1 |  |  |  | — |
Total AOCI, excluding noncontrolling interest |  | $ | (659 | ) |  | $ | (799 | )
Virginia Power |  |  |  |  |  |  |  |
Net deferred losses on derivatives-hedging activities, net of tax of $8 and $5 |  | $ | (12 | ) |  | $ | (8 | )
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(47) and $(35) |  |  | 74 |  |  |  | 54 |
Total AOCI |  | $ | 62 |  |  | $ | 46 |
Dominion Energy Gas |  |  |  |  |  |  |  |
Net deferred losses on derivatives-hedging activities, net of tax of $15 and $15 |  | $ | (23 | ) |  | $ | (24 | )
Net unrecognized pension costs, net of tax of $59 and $68 |  |  | (75 | ) |  |  | (99 | )
Total AOCI |  | $ | (98 | ) |  | $ | (123 | )

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, 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 attributable to noncontrolling interest |  |  | 1 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1 |
Ending balance |  |  | $(302 | ) |  |  | $747 |  |  |  | $(1,101 | ) |  |  | $(3 | ) |  |  | $(659 | )
Year Ended December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Beginning balance |  |  | $(176 | ) |  |  | $504 |  |  |  | $ (797 | ) |  |  | $(5 | ) |  |  | $(474 | )
Other comprehensive income before reclassifications: gains (losses) |  |  | 55 |  |  |  | 93 |  |  |  | (319 | ) |  |  | (1 | ) |  |  | (172 | )
Amounts reclassified from AOCI: (gains) losses(1) |  |  | (159 | ) |  |  | (28) |  |  |  | 34 |  |  |  | — |  |  |  | (153 | )
Net current period other comprehensive income (loss) |  |  | (104 | ) |  |  | 65 |  |  |  | (285 | ) |  |  | (1 | ) |  |  | (325 | )
Ending balance |  |  | $(280 | ) |  |  | $569 |  |  |  | $(1,082 | ) |  |  | $(6 | ) |  |  | $(799 | )

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

86 |  |  |  |

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, 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: |  |  |  |  |  |  |  |
Amortization of prior-service costs (credits) |  |  | $ (21 | ) |  |  | Other income |
Amortization of actuarial losses |  |  | 103 |  |  |  | Other income |
Total |  |  | 82 |  |  |  |  |
Tax |  |  | (32 | ) |  |  | Income tax expense |
Total, net of tax |  |  | $ 50 |  |  |  |  |
Year Ended December 31, 2016 |  |  |  |  |  |  |  |
Deferred (gains) and losses on derivatives-hedging activities: |  |  |  |  |  |  |  |
Commodity contracts |  |  | $(330 | ) |  |  | Operating revenue |
|  |  | 13 |  |  |  | Purchased gas |
|  |  | 10 |  |  |  | Electric fuel and other energy-related purchases |
Interest rate contracts |  |  | 31 |  |  |  | Interest and related charges |
Foreign currency contracts |  |  | 17 |  |  |  | Other Income |
Total |  |  | (259 | ) |  |  |  |
Tax |  |  | 100 |  |  |  | Income tax expense |
Total, net of tax |  |  | $(159 | ) |  |  |  |
Unrealized (gains) and losses on investment securities: |  |  |  |  |  |  |  |
Realized (gain) loss on sale of securities |  |  | $ (66 | ) |  |  | Other income |
Impairment |  |  | 23 |  |  |  | Other income |
Total |  |  | (43 | ) |  |  |  |
Tax |  |  | 15 |  |  |  | Income tax expense |
Total, net of tax |  |  | $ (28 | ) |  |  |  |
Unrecognized pension and other postretirement benefit costs: |  |  |  |  |  |  |  |
Prior-service costs (credits) |  |  | $ (15 | ) |  |  | Other income |
Actuarial losses |  |  | 71 |  |  |  | Other income |
Total |  |  | 56 |  |  |  |  |
Tax |  |  | (22 | ) |  |  | Income tax expense |
Total, net of tax |  |  | $ 34 |  |  |  |  |

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, 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 |
Year Ended December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |
Beginning balance |  |  | $ (7 | ) |  |  | $47 |  |  |  | $40 |
Other comprehensive income before reclassifications: gains (losses) |  |  | (2 | ) |  |  | 11 |  |  |  | 9 |
Amounts reclassified from AOCI: (gains) losses(1) |  |  | 1 |  |  |  | (4 | ) |  |  | (3 | )
Net current period other comprehensive income (loss) |  |  | (1 | ) |  |  | 7 |  |  |  | 6 |
Ending balance |  |  | $ (8 | ) |  |  | $54 |  |  |  | $46 |

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

87

Combined Notes to Consolidated Financial Statements, Continued

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, 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 | ) |  |  |  |
Year Ended December 31, 2016 |  |  |  |  |  |  |  |
(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 |  |  | 3 |  |  |  | Other income |
Total |  |  | (6 | ) |  |  |  |
Tax |  |  | 2 |  |  |  | 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 costs |  |  | Total |
(millions) |  |  |  |  |  |  |  |  |
Year Ended December 31, 2017 |  |  |  |  |  |  |  |  |  |  |  |
Beginning balance |  |  | $(24 | ) |  |  | $(99 | ) |  |  | $(123 | )
Other comprehensive income before reclassifications: gains (losses) |  |  | 5 |  |  |  | 20 |  |  |  | 25 |
Amounts reclassified from AOCI(1): (gains) losses |  |  | (4 | ) |  |  | 4 |  |  |  | — |
Net current period other comprehensive income (loss) |  |  | 1 |  |  |  | 24 |  |  |  | 25 |
Ending balance |  |  | $(23 | ) |  |  | $(75 | ) |  |  | $ (98 | )
Year Ended December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |
Beginning balance |  |  | $(17 | ) |  |  | $(82 | ) |  |  | $ (99 | )
Other comprehensive income before reclassifications: gains (losses) |  |  | (16 | ) |  |  | (20 | ) |  |  | (36 | )
Amounts reclassified from AOCI(1): (gains) losses |  |  | 9 |  |  |  | 3 |  |  |  | 12 |
Net current period other comprehensive income (loss) |  |  | (7 | ) |  |  | (17 | ) |  |  | (24 | )
Ending balance |  |  | $(24 | ) |  |  | $(99 | ) |  |  | $(123 | )

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

88 |  |  |  |

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, 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 |  |  |
Year Ended December 31, 2016 |  |  |  |  |  |
Deferred (gains) and losses on derivatives-hedging activities: |  |  |  |  |  |
Commodity contracts |  |  | $ (4 | ) |  | Operating revenue
Interest rate contracts |  |  | 2 |  |  | Interest and related charges
Foreign currency contracts |  |  | 17 |  |  | Other income
Total |  |  | 15 |  |  |
Tax |  |  | (6 | ) |  | Income tax expense
Total, net of tax |  |  | $ 9 |  |  |
Unrecognized pension costs: |  |  |  |  |  |
Actuarial losses |  |  | $ 5 |  |  | Other income
Total |  |  | 5 |  |  |
Tax |  |  | (2 | ) |  | Income tax expense
Total, net of tax |  |  | $ 3 |  |  |

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. At December 31, 2017, approximately 23 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,

2017, 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, 2017, 2016 and 2015 include $45 million, $33 million, and $39 million, respectively, of compensation costs and $16 million, $11 million, and $14 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 from time to time. 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, 2017, 2016 and 2015:

|  | Shares |  |  | Weighted - average Grant Date Fair Value |
|  | (thousands) |  |  |  |
Nonvested at December 31, 2014 |  |  | 1,065 |  |  |  | $56.74 |
Granted |  |  | 302 |  |  |  | 73.26 |
Vested |  |  | (510 | ) |  |  | 50.71 |
Cancelled and forfeited |  |  | (2 | ) |  |  | 62.62 |
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 |

As of December 31, 2017, unrecognized compensation cost related to nonvested restricted stock awards totaled $42 million and is expected to be recognized over a weighted-average period of 2.0 years. The fair value of restricted stock awards that vested was $21 million, $21 million, and $37 million in 2017, 2016 and 2015, 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%

89

Combined Notes to Consolidated Financial Statements, Continued

of the targeted amount based on the level of performance metrics achieved.

In February 2015, a cash-based performance grant was made to officers. Payout of the performance grant occurred in January 2017 based on the achievement of two performance metrics during 2015 and 2016: 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 $10 million.

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 the Company transitioned from a two-year performance period to a three-year performance period. Payout of the two-year grant is expected to occur by March 15, 2019 based on the achievement of two performance metrics during 2017 and 2018: TSR relative to that of companies that are members of the Company’s compensation peer group and ROIC. At December 31, 2017, the targeted amount of the two-year grant was $15 million and a liability of $7 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 the Company’s compensation peer group and ROIC. At December 31, 2017, the targeted amount of the three-year grant was $15 million and a liability of $5 million had been accrued for the 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, 2017, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

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, 2017, the Ohio Commission had not restricted the payment of dividends by East Ohio.

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, 2017, the Utah Commission had not restricted the payment of dividends by Questar Gas.

Certain agreements associated with the Companies’ credit facilities contain 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, 2017.

As part of the SCANA Merger Agreement, Dominion Energy shall 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 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 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

90 |  |  |  |

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 of $1.6 billion and $534 million in 2017 and 2016, respectively, versus expected returns of $767 million and $691 million, respectively. Dominion Energy Gas’ pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual returns of $335 million and $130 million in 2017 and 2016, respectively, versus expected returns of $165 million and $157 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.

In October 2014, the Society of Actuaries published new mortality tables and mortality improvement scales. Such tables and scales are used to develop mortality assumptions for use in determining pension and other postretirement benefit liabilities and expense. Following evaluation of the new tables, Dominion Energy changed its assumption for mortality rates to reflect a generational improvement scale. This change in assumption increased net periodic benefit cost for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units) by $25 million and $3 million, respectively, for 2015.

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’s 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.

91

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, |  | 2017 |  |  | 2016 |  |  | 2017 |  |  | 2016 |
(millions, except percentages) |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Changes in benefit obligation: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Benefit obligation at beginning of year |  | $ | 8,132 |  |  | $ | 6,391 |  |  | $ | 1,478 |  |  | $ | 1,430 |
Dominion Energy Questar Combination |  |  | — |  |  |  | 817 |  |  |  | — |  |  |  | 85 |
Service cost |  |  | 138 |  |  |  | 118 |  |  |  | 26 |  |  |  | 31 |
Interest cost |  |  | 345 |  |  |  | 317 |  |  |  | 60 |  |  |  | 65 |
Benefits paid |  |  | (323 | ) |  |  | (286 | ) |  |  | (83 | ) |  |  | (83 | )
Actuarial (gains) losses during the year |  |  | 830 |  |  |  | 784 |  |  |  | 119 |  |  |  | 166 |
Plan amendments(1) |  |  | 5 |  |  |  | — |  |  |  | (73 | ) |  |  | (216 | )
Settlements and curtailments(2) |  |  | (75 | ) |  |  | (9 | ) |  |  | 2 |  |  |  | — |
Benefit obligation at end of year |  | $ | 9,052 |  |  | $ | 8,132 |  |  | $ | 1,529 |  |  | $ | 1,478 |
Changes in fair value of plan assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fair value of plan assets at beginning of year |  | $ | 7,016 |  |  | $ | 6,166 |  |  | $ | 1,512 |  |  | $ | 1,382 |
Dominion Energy Questar Combination |  |  | — |  |  |  | 704 |  |  |  | — |  |  |  | 45 |
Actual return (loss) on plan assets |  |  | 1,327 |  |  |  | 426 |  |  |  | 236 |  |  |  | 108 |
Employer contributions |  |  | 118 |  |  |  | 15 |  |  |  | 13 |  |  |  | 12 |
Benefits paid |  |  | (323 | ) |  |  | (286 | ) |  |  | (32 | ) |  |  | (35 | )
Settlements(2) |  |  | (76 | ) |  |  | (9 | ) |  |  | — |  |  |  | — |
Fair value of plan assets at end of year |  | $ | 8,062 |  |  | $ | 7,016 |  |  | $ | 1,729 |  |  | $ | 1,512 |
Funded status at end of year |  | $ | (990 | ) |  | $ | (1,116 | ) |  | $ | 200 |  |  | $ | 34 |
Amounts recognized in the Consolidated Balance Sheets at December 31: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Noncurrent pension and other postretirement benefit assets |  | $ | 1,117 |  |  | $ | 930 |  |  | $ | 261 |  |  | $ | 148 |
Other current liabilities |  |  | (8 | ) |  |  | (43 | ) |  |  | — |  |  |  | (5 | )
Noncurrent pension and other postretirement benefit liabilities |  |  | (2,099 | ) |  |  | (2,003 | ) |  |  | (61 | ) |  |  | (109 | )
Net amount recognized |  | $ | (990 | ) |  | $ | (1,116 | ) |  | $ | 200 |  |  | $ | 34 |
Significant assumptions used to determine benefit obligations as of December 31: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount rate |  |  | 3.80%–3.81 | % |  |  | 3.31%–4.50 | % |  |  | 3.76% |  |  |  | 3.92%–4.47 | %
Weighted average rate of increase for compensation |  |  | 4.09 | % |  |  | 4.09 | % |  |  | 3.95%-4.11% |  |  |  | 3.29 | %
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Changes in benefit obligation: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Benefit obligation at beginning of year |  | $ | 683 |  |  | $ | 608 |  |  | $ | 320 |  |  | $ | 292 |
Service cost |  |  | 15 |  |  |  | 13 |  |  |  | 4 |  |  |  | 5 |
Interest cost |  |  | 30 |  |  |  | 30 |  |  |  | 12 |  |  |  | 14 |
Benefits paid |  |  | (33 | ) |  |  | (32 | ) |  |  | (19 | ) |  |  | (19 | )
Actuarial (gains) losses during the year |  |  | 78 |  |  |  | 64 |  |  |  | 34 |  |  |  | 28 |
Plan amendments(1) |  |  | — |  |  |  | — |  |  |  | (61 | ) |  |  | — |
Benefit obligation at end of year |  | $ | 773 |  |  | $ | 683 |  |  | $ | 290 |  |  | $ | 320 |
Changes in fair value of plan assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fair value of plan assets at beginning of year |  | $ | 1,542 |  |  | $ | 1,467 |  |  | $ | 299 |  |  | $ | 283 |
Actual return (loss) on plan assets |  |  | 294 |  |  |  | 107 |  |  |  | 41 |  |  |  | 23 |
Employer contributions |  |  | — |  |  |  | — |  |  |  | 12 |  |  |  | 12 |
Benefits paid |  |  | (33 | ) |  |  | (32 | ) |  |  | (19 | ) |  |  | (19 | )
Fair value of plan assets at end of year |  | $ | 1,803 |  |  | $ | 1,542 |  |  | $ | 333 |  |  | $ | 299 |
Funded status at end of year |  | $ | 1,030 |  |  | $ | 859 |  |  | $ | 43 |  |  | $ | (21 | )
Amounts recognized in the Consolidated Balance Sheets at December 31: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Noncurrent pension and other postretirement benefit assets |  | $ | 1,030 |  |  | $ | 859 |  |  | $ | 57 |  |  | $ | — |
Noncurrent pension and other postretirement benefit liabilities(3) |  |  | — |  |  |  | — |  |  |  | (14 | ) |  |  | (21 | )
Net amount recognized |  | $ | 1,030 |  |  | $ | 859 |  |  | $ | 43 |  |  | $ | (21 | )
Significant assumptions used to determine benefit obligations as of December 31: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount rate |  |  | 3.81 | % |  |  | 4.50 | % |  |  | 3.76 | % |  |  | 4.47 | %
Weighted average rate of increase for compensation |  |  | 4.11 | % |  |  | 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. 2016 amount relates primarily to a plan amendment that changed post-65 retiree medical coverage for certain current and future Local 50 retirees effective April 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. 2016 amount relates primarily to a settlement for certain executives.

(3) | Reflected in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.

92 |  |  |  |

The ABO for all of Dominion Energy’s defined benefit pension plans was $8.2 billion and $7.3 billion at December 31, 2017 and 2016, respectively. The ABO for the defined benefit pension plans covering Dominion Energy Gas employees represented by collective bargaining units was $724 million and $640 million at December 31, 2017 and 2016, 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 2017, Dominion Energy and Dominion Energy Gas made no contributions to the qualified defined benefit pension plans other than a $75 million contribution to Dominion Energy’s qualified pension plan to satisfy a regulatory condition to closing of the Dominion Energy Questar Combination and no contributions are currently expected in 2018. In July 2012, the MAP 21 Act was signed into law. This Act includes an increase in the interest rates used to determine plan sponsors’ pension contributions for required funding purposes. In 2014, the HATFA of 2014 was signed into law. Similar to the MAP 21 Act, the HATFA of 2014 adjusts the rules for calculating interest rates used in determining funding obligations. It is estimated that the new interest rates will reduce required pension contributions through 2019. Dominion Energy believes that required pension contributions will rise subsequent to 2019, resulting in an estimated $200 million reduction in net cumulative required contributions over a 10-year period.

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 2017 and 2016, and Dominion Energy expects to contribute approximately $12 million to the Dominion Energy VEBAs in 2018, 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 2018.

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, |  | 2017 |  |  | 2016 |  |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Benefit obligation |  | $ | 8,209 |  |  | $ | 7,386 |  |  |  | $191 |  |  |  | $470 |
Fair value of plan assets |  |  | 6,103 |  |  |  | 5,340 |  |  |  | 156 |  |  |  | 356 |
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Benefit obligation |  | $ | — |  |  | $ | — |  |  |  | $157 |  |  |  | $320 |
Fair value of plan assets |  |  | — |  |  |  | — |  |  |  | 143 |  |  |  | 299 |

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, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
Accumulated benefit obligation |  | $ | 7,392 |  |  | $ | 5,987 |
Fair value of plan assets |  |  | 6,103 |  |  |  | 4,653 |

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for Dominion Energy’s and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans:

|  | Estimated Future Benefit Payments |
|  | Pension Benefits |  |  | Other Postretirement Benefits |
(millions) |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |
2018 |  |  | $373 |  |  |  | $ 99 |
2019 |  |  | 378 |  |  |  | 101 |
2020 |  |  | 402 |  |  |  | 102 |
2021 |  |  | 418 |  |  |  | 102 |
2022 |  |  | 434 |  |  |  | 102 |
2023-2027 |  | 2,437 |  |  | 486 |
Dominion Energy Gas |  |  |  |  |  |  |  |
2018 |  |  | $ 35 |  |  |  | $ 19 |
2019 |  |  | 37 |  |  |  | 19 |
2020 |  |  | 38 |  |  |  | 20 |
2021 |  |  | 39 |  |  |  | 20 |
2022 |  |  | 41 |  |  |  | 20 |
2023-2027 |  |  | 214 |  |  |  | 94 |

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

93

Combined Notes to Consolidated Financial Statements, Continued

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.

94 |  |  |  |

The fair values of Dominion Energy’s and Dominion Energy Gas’ (for employees represented by collective bargaining units) pension plan assets by asset category are as follows:

At December 31, |  | 2017 |  |  | 2016 |
|  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |  |  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 18 |  |  | $ | — |  |  |  | $— |  |  | $ | 18 |  |  | $ | 12 |  |  | $ | 2 |  |  |  | $— |  |  | $ | 14 |
Common and preferred stocks: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. |  |  | 1,902 |  |  |  | — |  |  |  | — |  |  |  | 1,902 |  |  |  | 1,705 |  |  |  | — |  |  |  | — |  |  |  | 1,705 |
International |  |  | 1,151 |  |  |  | — |  |  |  | — |  |  |  | 1,151 |  |  |  | 928 |  |  |  | — |  |  |  | — |  |  |  | 928 |
Insurance contracts |  |  | — |  |  |  | 352 |  |  |  | — |  |  |  | 352 |  |  |  | — |  |  |  | 334 |  |  |  | — |  |  |  | 334 |
Corporate debt instruments |  |  | 41 |  |  |  | 729 |  |  |  | — |  |  |  | 770 |  |  |  | 35 |  |  |  | 682 |  |  |  | — |  |  |  | 717 |
Government securities |  |  | 9 |  |  |  | 676 |  |  |  | — |  |  |  | 685 |  |  |  | 13 |  |  |  | 522 |  |  |  | — |  |  |  | 535 |
Total recorded at fair value |  | $ | 3,121 |  |  | $ | 1,757 |  |  |  | $— |  |  | $ | 4,878 |  |  | $ | 2,693 |  |  | $ | 1,540 |  |  |  | $— |  |  | $ | 4,233 |
Assets recorded at NAV(1): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common/collective trust funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2,272 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,960 |
Alternative investments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Real estate funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 111 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 121 |
Private equity funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 606 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 506 |
Debt funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 161 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 153 |
Hedge funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 19 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 25 |
Total recorded at NAV |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 3,169 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 2,765 |
Total investments(2) |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 8,047 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 6,998 |
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 4 |  |  | $ | — |  |  |  | $— |  |  | $ | 4 |  |  | $ | 3 |  |  | $ | — |  |  |  | $— |  |  | $ | 3 |
Common and preferred stocks: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. |  |  | 425 |  |  |  | — |  |  |  | — |  |  |  | 425 |  |  |  | 375 |  |  |  | — |  |  |  | — |  |  |  | 375 |
International |  |  | 257 |  |  |  | — |  |  |  | — |  |  |  | 257 |  |  |  | 203 |  |  |  | — |  |  |  | — |  |  |  | 203 |
Insurance contracts |  |  | — |  |  |  | 79 |  |  |  | — |  |  |  | 79 |  |  |  | — |  |  |  | 73 |  |  |  | — |  |  |  | 73 |
Corporate debt instruments |  |  | 9 |  |  |  | 163 |  |  |  | — |  |  |  | 172 |  |  |  | 8 |  |  |  | 150 |  |  |  | — |  |  |  | 158 |
Government securities |  |  | 2 |  |  |  | 151 |  |  |  | — |  |  |  | 153 |  |  |  | 3 |  |  |  | 115 |  |  |  | — |  |  |  | 118 |
Total recorded at fair value |  | $ | 697 |  |  | $ | 393 |  |  |  | $— |  |  | $ | 1,090 |  |  | $ | 592 |  |  | $ | 338 |  |  |  | $— |  |  | $ | 930 |
Assets recorded at NAV(1): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common/collective trust funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 509 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 430 |
Alternative investments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Real estate funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 25 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 27 |
Private equity funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 135 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 111 |
Debt funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 36 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 34 |
Hedge funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 4 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 6 |
Total recorded at NAV |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 709 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 608 |
Total investments(3) |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 1,799 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 1,538 |

(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 $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. Excludes net assets related to pending sales of securities of $46 million, net accrued income of $19 million, and includes net assets related to pending purchases of securities of $47 million at December 31, 2016.

(3) | 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. Excludes net assets related to pending sales of securities of $10 million, net accrued income of $4 million, and includes net assets related to pending purchases of securities of $10 million at December 31, 2016.

|  |  |  | 95

Combined Notes to Consolidated Financial Statements, Continued

The fair values of Dominion Energy’s and Dominion Energy Gas’ (for employees represented by collective bargaining units) other postretirement plan assets by asset category are as follows:

At December 31, |  | 2017 |  |  | 2016 |
|  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |  |  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  |  | $ 1 |  |  |  | $ 2 |  |  |  | $— |  |  | $ | 3 |  |  |  | $ 1 |  |  |  | $ 1 |  |  |  | $— |  |  |  | $ 2 |
Common and preferred stocks: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. |  |  | 636 |  |  |  | — |  |  |  | — |  |  |  | 636 |  |  |  | 571 |  |  |  | — |  |  |  | — |  |  |  | 571 |
International |  |  | 196 |  |  |  | — |  |  |  | — |  |  |  | 196 |  |  |  | 143 |  |  |  | — |  |  |  | — |  |  |  | 143 |
Insurance contracts |  |  | — |  |  |  | 21 |  |  |  | — |  |  |  | 21 |  |  |  | — |  |  |  | 19 |  |  |  | — |  |  |  | 19 |
Corporate debt instruments |  |  | 2 |  |  |  | 44 |  |  |  | — |  |  |  | 46 |  |  |  | 2 |  |  |  | 40 |  |  |  | — |  |  |  | 42 |
Government securities |  |  | 1 |  |  |  | 41 |  |  |  | — |  |  |  | 42 |  |  |  | 1 |  |  |  | 30 |  |  |  | — |  |  |  | 31 |
Total recorded at fair value |  |  | $836 |  |  |  | $108 |  |  |  | $— |  |  | $ | 944 |  |  |  | $718 |  |  |  | $90 |  |  |  | $— |  |  |  | $ 808 |
Assets recorded at NAV(1): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common/collective trust funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 689 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 621 |
Alternative investments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Real estate funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9 |
Private equity funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 73 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 59 |
Debt funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 11 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 12 |
Hedge funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |
Total recorded at NAV |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 783 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ 702 |
Total investments(2) |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 1,727 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $1,510 |
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common and preferred stocks: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. |  |  | $130 |  |  |  | $ — |  |  |  | $— |  |  | $ | 130 |  |  |  | $121 |  |  |  | $— |  |  |  | $— |  |  |  | $ 121 |
International |  |  | 33 |  |  |  | — |  |  |  | — |  |  |  | 33 |  |  |  | 24 |  |  |  | — |  |  |  | — |  |  |  | 24 |
Total recorded at fair value |  |  | $163 |  |  |  | $ — |  |  |  | $— |  |  | $ | 163 |  |  |  | $145 |  |  |  | $— |  |  |  | $— |  |  |  | $ 145 |
Assets recorded at NAV(1): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common/collective trust funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 154 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 140 |
Alternative investments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Real estate funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |
Private equity funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 15 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 12 |
Debt funds |  |  |  |  |  |  |  |  |  |  |  |  |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1 |
Total recorded at NAV |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 170 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ 154 |
Total investments |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 333 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ 299 |

(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 $1 million at December 31, 2017. Excludes net assets related to pending sales of securities of $5 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $5 million at December 31, 2016.

96 |  |  |  |

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.

97

Combined Notes to Consolidated Financial Statements, Continued

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’s and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans are as follows:

|  | Pension Benefits |  |  | Other Postretirement Benefits |
Year Ended December 31, |  | 2017 |  |  | 2016 |  |  | 2015 |  |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions, except percentages) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Service cost |  | $ | 138 |  |  | $ | 118 |  |  | $ | 126 |  |  | $ | 26 |  |  | $ | 31 |  |  | $ | 40 |
Interest cost |  |  | 345 |  |  |  | 317 |  |  |  | 287 |  |  |  | 60 |  |  |  | 65 |  |  |  | 67 |
Expected return on plan assets |  |  | (639 | ) |  |  | (573 | ) |  |  | (531 | ) |  |  | (128 | ) |  |  | (118 | ) |  |  | (117 | )
Amortization of prior service (credit) cost |  |  | 1 |  |  |  | 1 |  |  |  | 2 |  |  |  | (51 | ) |  |  | (35 | ) |  |  | (27 | )
Amortization of net actuarial loss |  |  | 162 |  |  |  | 111 |  |  |  | 160 |  |  |  | 13 |  |  |  | 8 |  |  |  | 6 |
Settlements and curtailments |  |  | — |  |  |  | 1 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Net periodic benefit (credit) cost |  | $ | 7 |  |  | $ | (25 | ) |  | $ | 44 |  |  | $ | (80 | ) |  | $ | (49 | ) |  | $ | (31 | )
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current year net actuarial (gain) loss |  | $ | 142 |  |  | $ | 931 |  |  | $ | 159 |  |  | $ | 12 |  |  | $ | 178 |  |  | $ | (18 | )
Prior service (credit) cost |  |  | 5 |  |  |  | — |  |  |  | — |  |  |  | (73 | ) |  |  | (216 | ) |  |  | (31 | )
Settlements and curtailments |  |  | 1 |  |  |  | (1 | ) |  |  | — |  |  |  | 2 |  |  |  | — |  |  |  | — |
Less amounts included in net periodic benefit cost: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Amortization of net actuarial loss |  |  | (162 | ) |  |  | (111 | ) |  |  | (160 | ) |  |  | (13 | ) |  |  | (8 | ) |  |  | (6 | )
Amortization of prior service credit (cost) |  |  | (1 | ) |  |  | (1 | ) |  |  | (2 | ) |  |  | 51 |  |  |  | 35 |  |  |  | 27 |
Total recognized in other comprehensive income and regulatory assets and liabilities |  | $ | (15 | ) |  | $ | 818 |  |  | $ | (3 | ) |  | $ | (21 | ) |  | $ | (11 | ) |  | $ | (28 | )
Significant assumptions used to determine periodic cost: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount rate |  |  | 3.31%-4.50 | % |  |  | 2.87%-4.99 | % |  |  | 4.40 | % |  |  | 3.92%-4.47 | % |  |  | 3.56%-4.94 | % |  |  | 4.40 | %
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 | % |  |  | 4.22 | % |  |  | 4.22 | % |  |  | 3.29 | % |  |  | 4.22 | % |  |  | 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) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2021 |  |  |  | 2020 |  |  |  | 2019 |
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Service cost |  | $ | 15 |  |  | $ | 13 |  |  | $ | 15 |  |  | $ | 4 |  |  | $ | 5 |  |  | $ | 7 |
Interest cost |  |  | 30 |  |  |  | 30 |  |  |  | 27 |  |  |  | 12 |  |  |  | 14 |  |  |  | 14 |
Expected return on plan assets |  |  | (141 | ) |  |  | (134 | ) |  |  | (126 | ) |  |  | (24 | ) |  |  | (23 | ) |  |  | (24 | )
Amortization of prior service (credit) cost |  |  | — |  |  |  | — |  |  |  | 1 |  |  |  | (3 | ) |  |  | 1 |  |  |  | (1 | )
Amortization of net actuarial loss |  |  | 16 |  |  |  | 13 |  |  |  | 20 |  |  |  | 2 |  |  |  | 1 |  |  |  | 2 |
Net periodic benefit (credit) cost |  | $ | (80 | ) |  | $ | (78 | ) |  | $ | (63 | ) |  | $ | (9 | ) |  | $ | (2 | ) |  | $ | (2 | )
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current year net actuarial (gain) loss |  | $ | (75 | ) |  | $ | 91 |  |  | $ | 97 |  |  | $ | 18 |  |  | $ | 28 |  |  | $ | (9 | )
Prior service cost |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (61 | ) |  |  | — |  |  |  | — |
Less amounts included in net periodic benefit cost: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Amortization of net actuarial loss |  |  | (16 | ) |  |  | (13 | ) |  |  | (20 | ) |  |  | (2 | ) |  |  | (1 | ) |  |  | (2 | )
Amortization of prior service credit (cost) |  |  | — |  |  |  | — |  |  |  | (1 | ) |  |  | 3 |  |  |  | (1 | ) |  |  | 1 |
Total recognized in other comprehensive income and regulatory assets and liabilities |  | $ | (91 | ) |  | $ | 78 |  |  | $ | 76 |  |  | $ | (42 | ) |  | $ | 26 |  |  | $ | (10 | )
Significant assumptions used to determine periodic cost: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount rate |  |  | 4.50 | % |  |  | 4.99 | % |  |  | 4.40 | % |  |  | 4.47 | % |  |  | 4.93 | % |  |  | 4.40 | %
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 | % |  |  | 3.93 | % |  |  | 3.93 | % |  |  | 4.11 | % |  |  | 3.93 | % |  |  | 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)(2) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2021 |  |  |  | 2020 |  |  |  | 2019 |

(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.

98 |  |  |  |

The components of AOCI and regulatory assets and liabilities for Dominion Energy’s 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, |  | 2017 |  |  | 2016 |  |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net actuarial loss |  | $ | 3,181 |  |  | $ | 3,200 |  |  | $ | 283 |  |  | $ | 283 |
Prior service (credit) cost |  |  | 8 |  |  |  | 4 |  |  |  | (440 | ) |  |  | (419 | )
Total(1) |  | $ | 3,189 |  |  | $ | 3,204 |  |  | $ | (157 | ) |  | $ | (136 | )
Dominion Energy Gas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net actuarial loss |  | $ | 367 |  |  | $ | 458 |  |  | $ | 76 |  |  | $ | 60 |
Prior service (credit) cost |  |  | — |  |  |  | — |  |  |  | (52 | ) |  |  | 7 |
Total(2) |  | $ | 367 |  |  | $ | 458 |  |  | $ | 24 |  |  | $ | 67 |

(1) | 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. As of December 31, 2016, of the $3.2 billion and $(136) million related to pension benefits and other postretirement benefits, $1.9 billion and $(103) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.

(2) | 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. As of December 31, 2016, of the $458 million related to pension benefits, $167 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $67 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’s and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans as of December 31, 2017 that are expected to be amortized as components of net periodic benefit (credit) cost in 2018:

|  | Pension Benefits |  |  | Other Postretirement Benefits |
(millions) |  |  |  |  |  |
Dominion Energy |  |  |  |  |  |  |  |
Net actuarial loss |  |  | $193 |  |  |  | $ 11 |
Prior service (credit) cost |  |  | 1 |  |  |  | (52 | )
Dominion Energy Gas |  |  |  |  |  |  |  |
Net actuarial loss |  |  | $ 19 |  |  |  | $ 3 |
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 volatilities and correlations;

| • |  | Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major stock market indices; 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’s 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 2018 |  |  | $ 24 |  |  |  | $ (15 | )
Effect on other postretirement benefit obligation at December 31, 2017 |  |  | 158 |  |  |  | (132 | )
Dominion Energy Gas |  |  |  |  |  |  |  |
Effect on net periodic cost for 2018 |  |  | $ 4 |  |  |  | $ (3 | )
Effect on other postretirement benefit obligation at December 31, 2017 |  |  | 31 |  |  |  | (26 | )

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 2017, Virginia Power and Dominion Energy Gas made no con-

99

Combined Notes to Consolidated Financial Statements, Continued

tributions to the Dominion Energy Pension Plan, and no contributions to this plan are currently expected in 2018. Virginia Power’s net periodic pension cost related to this plan was $110 million, $79 million and $97 million in 2017, 2016 and 2015, respectively. Dominion Energy Gas’ net periodic pension credit related to this plan was $(37) million, $(45) million and $(38) million in 2017, 2016 and 2015, 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 $(42) million, $(29) million and $(16) million in 2017, 2016 and 2015, respectively. Dominion Energy Gas’ net periodic benefit (credit) cost related to this plan was $(5) million, $(4) million and $(5) million for 2017, 2016 and 2015, 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 2017 and 2016, Virginia Power made no contributions to the VEBA and does not expect to contribute to the VEBA in 2018. Dominion Energy Gas made no contributions to the VEBAs for employees not represented by collective bargaining units during 2017 and 2016 and does not expect to contribute in 2018.

Defined Contribution Plans

Dominion Energy also sponsors defined contribution employee savings plans that cover substantially all employees. During 2017, 2016 and 2015, Dominion Energy recognized $45 million, $44 million and $43 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 sub-

sidiaries. During 2017, 2016 and 2015, Dominion Energy Gas recognized $7 million as employer matching contributions to these plans. Virginia Power also participates in these employee savings plans. During 2017, 2016 and 2015, Virginia Power recognized $19 million, $19 million and $18 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 for which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial position, liquidity or results of operations of the Companies.

100 |  |  |  |

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. Following a one-year compliance extension granted by VDEQ and an additional one-year extension under an EPA Administrative Order, 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 approximately 23 months following the receipt in July 2017 of final permits and approvals for construction. 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 2018. The Sierra Club has challenged the DOE order and certain renewal requests, all of which have been denied by the DOE.

Although litigation of the MATS rule is 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 NOX Reasonable Available Control Technology analysis for Unit 5 at Possum Point power station. In December 2016, the VDEQ determined that NOX reductions are required on Unit 5. In October 2017, Virginia Power proposed to install NOX controls by mid-2019 with an expected cost in the range of $25 million to $35 million.

The statutory deadline for the EPA to complete attainment designations for a new standard was October 2017. States will have three years after final designations, certain of which were issued by the EPA in November 2017, 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.

NOx and VOC Emissions

In April 2016, the Pennsylvania Department of Environmental Protection issued final regulations, with an effective date of January 2017, to reduce NOX and VOC emissions from combustion sources. To comply with the regulations, Dominion Energy Gas is installing emission control systems on existing engines at several compressor stations in Pennsylvania. The compliance costs associated with engineering and installation of controls and compliance demonstration with the regulation are expected to be approximately $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 April 2017, the EPA issued a notice that it is reviewing the rule and, if appropriate, will issue a rulemaking to suspend, revise or rescind the June 2016 final NSPS for certain oil and gas facilities. In June 2017, the EPA published notice of reconsideration and partial stay of the rule for 90 days and proposed extending the stay for two years. In July 2017, the U.S. Court of Appeals for the D.C. Circuit vacated the 90-day stay. In November 2017, the EPA solicited comments on the proposed two-year stay of the June 2016 NSPS rules. 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

101

Combined Notes to Consolidated Financial Statements, Continued

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’s 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. DECG joined the EPA’s voluntary Natural Gas STAR Program in July 2016 and submitted an implementation plan in September 2016. 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. 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’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.

In September 2015, the EPA released a final rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The final rule establishes updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. Virginia Power has eight facilities subject to the final rule. 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’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.

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.

102 |  |  |  |

Dominion Energy has determined that it is associated with 19 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of which pertain to Dominion 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. Another site has been accepted into a state-based voluntary remediation program. Virginia Power is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.

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

Other Legal Matters

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

APPALACHIAN GATEWAY

Pipeline Contractor Litigation

Following the completion of the Appalachian Gateway project in 2012, 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. This case is pending. At December 31, 2017, DETI has accrued a liability of $2 million for this matter. Dominion Energy Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows.

Gas Producers Litigation

In connection with the Appalachian Gateway project, Dominion 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. All other 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. This case is pending.

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. Virginia Power currently operates inactive ash ponds, existing ash ponds, and CCR landfills subject to the final rule at eight different facilities. This rule created a legal obligation for Virginia Power to retrofit or close all of its inactive and existing ash ponds over a certain period of time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary.

In 2015, Virginia Power recorded a $386 million ARO related to future ash pond and landfill closure costs, which resulted in a $99 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $166 million increase in property, plant and equipment associated with asset retirement costs, and a $121 million reduction in other noncurrent liabilities from the reversal of a previously recorded contingent liability since the ARO obligation created by the final CCR rule represents similar

103

Combined Notes to Consolidated Financial Statements, Continued

activities. 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. Litigation concerning the CCR rule is pending and the EPA has submitted to the court a list of which CCR rule provisions the EPA intends to reevaluate. 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 April 2017, the Virginia Governor 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. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the obligation.

COVE POINT

Dominion Energy has constructed the Liquefaction Project at the Cove Point facility, which, once commercially operational, would enable the facility to liquefy domestically-produced natural gas and export it as LNG. In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project.

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. Separately, one party requested a stay of the FERC order until the judicial proceedings are complete, which the court denied in June 2015. In July 2016, the court denied one party’s petition for review of the FERC order authorizing the Liquefaction Project. The court also issued a decision remanding the other party’s petition for review of the FERC order to FERC for further explanation of FERC’s decision that a previous transaction with an existing import shipper was not unduly discriminatory. 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. This case is pending.

In September 2013, the DOE granted Non-FTA Authorization approval for the export of up to 0.77 bcfe/day of natural gas to countries that do not have an FTA for trade in natural gas. In June 2016, a party filed a petition for review of this approval in the U.S. Court of Appeals for the D.C. Circuit. In November 2017, the U.S. Court of Appeals for the D.C. Circuit issued an order denying the petition for review.

In July 2017, Cove Point submitted an application for a temporary operating permit to the Maryland Department of the Environment, as required prior to the date of first production of LNG for commercial purposes of exporting LNG. The permit was received in December 2017. In February 2018, the Public Service Commission of Maryland issued an order approving Cove Point’s August 2017 application to amend the CPCN issued by the Public Service Commission of Maryland in May 2014 to make necessary updates.

FERC

FERC staff in the Office of Enforcement, Division of Investigations, is conducting a non-public investigation of Virginia Power’s offers of combustion turbines generators into the PJM day-ahead markets from April 2010 through September 2014. FERC staff notified Virginia Power of its preliminary findings relating to Virginia Power’s alleged violation of FERC’s rules in connection with these activities. Virginia Power has provided its response to FERC staff’s preliminary findings letter explaining why Virginia Power’s conduct was lawful and refuting any allegation of wrongdoing. Virginia Power is cooperating fully with the investigation; however, it cannot currently predict whether or to what extent it may incur a material liability.

GREENSVILLE COUNTY

Virginia Power is constructing Greensville County and related transmission interconnection facilities. In August 2016, the Sierra Club filed an administrative appeal in the Circuit Court for the City of Richmond challenging certain provisions in Greensville County’s PSD air permit issued by VDEQ in June 2016. In August 2017, the Circuit Court upheld the air permit, and no appeals were filed.

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 appropria-

104 |  |  |  |

tions 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. Reevaluation of the seismic and external flooding hazards is expected to continue through 2018. 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 2017 calculation for the NRC minimum financial assurance amount, aggregated for Dominion Energy’s 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 2017 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2017 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 up to $13.44 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Dominion Energy and Virginia Power have purchased $450 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $127 million for each of their licensed reactors not to exceed $19 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. However, the NRC granted an exemption in March 2015 to remove Kewaunee from the Secondary Financial Protection program. The current levels of nuclear property insurance coverage for Dominion Energy’s and Virginia Power’s nuclear units are as follows:

|  | Coverage |
(billions) |  |  |
Dominion Energy |  |  |  |
Millstone |  |  | $1.70 |
Kewaunee |  |  | 1.06 |
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’s 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. Kewaunee meets the NRC minimum requirement of $1.06 billion. 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’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $86 million and $50 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

105

Combined Notes to Consolidated Financial Statements, Continued

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’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $22 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’s 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 plants have been extended to provide for periodic payments for damages incurred through December 31, 2016, and have been extended to provide for periodic payment of damages through December 31, 2019. Pursuit of or possible settlement of the Kewaunee claims for damages incurred after December 31, 2013 is being evaluated.

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.

In 2015, Virginia Power and Dominion Energy received payments of $8 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2013 through December 31, 2013, and $17 million for resolution of claims incurred at Millstone for the period of July 1, 2013 through June 30, 2014.

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 $46 million and $56 million at December 31, 2017 and 2016, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $30 million and $37 million at December 31, 2017 and 2016, respectively.

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, 2017, 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:

|  | 2018 |  |  | 2019 |  |  | 2020 |  |  | 2021 |  |  | 2022 |  |  | Thereafter |  |  | Total |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Purchased electric capacity(1) |  | $ | 93 |  |  | $ | 61 |  |  | $ | 52 |  |  | $ | 46 |  |  |  | $— |  |  |  | $— |  |  | $ | 252 |

(1) | Commitments represent estimated amounts payable for capacity under a power purchase contract with a qualifying facility and an independent power producer, which ends in 2021. Capacity payments under the contract are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices. At December 31, 2017, the present value of Virginia Power’s total commitment for capacity payments is $221 million. Capacity payments totaled $114 million, $248 million, and $305 million, and energy payments totaled $72 million, $126 million, and $198 million for the years ended 2017, 2016 and 2015, 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 and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2017 are as follows:

|  | 2018 |  |  | 2019 |  |  | 2020 |  |  | 2021 |  |  | 2022 |  |  | Thereafter |  |  | Total |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dominion Energy(1) |  | $ | 68 |  |  | $ | 63 |  |  | $ | 56 |  |  | $ | 48 |  |  | $ | 39 |  |  |  | $361 |  |  | $ | 635 |
Virginia Power |  | $ | 34 |  |  | $ | 31 |  |  | $ | 27 |  |  | $ | 22 |  |  | $ | 15 |  |  |  | $ 28 |  |  | $ | 157 |
Dominion Energy Gas |  | $ | 15 |  |  | $ | 13 |  |  | $ | 10 |  |  | $ | 9 |  |  | $ | 7 |  |  |  | $ 41 |  |  | $ | 95 |

(1) | Amounts include a lease agreement for the Dominion Energy Questar corporate office, which is accounted for as a capital lease. At December 31, 2017 and 2016, the Consolidated Balance Sheets include $27 million and $30 million, respectively, in property, plant and equipment and $33 million and $35 million, respectively, in other deferred credits and other liabilities. The Consolidated Statements of Income include $3 million and less than $1 million recorded in depreciation, depletion and amortization for the years ended December 31, 2017 and 2016.

Rental expense for Dominion Energy totaled $113 million, $104 million, and $99 million for 2017, 2016 and 2015, respectively. Rental expense for Virginia Power totaled $57 million, $52 million, and $51 million for 2017, 2016 and 2015, respectively. Rental expense for Dominion Energy Gas totaled $34 million, $37 million, and $37 million for 2017, 2016 and 2015, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.

106 |  |  |  |

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 $139 million as of December 31, 2017. 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, 2017, Atlantic Coast Pipeline has borrowed $664 million against the revolving credit facility. Dominion Energy’s Consolidated Balance Sheet includes a liability of $28 million associated with this guarantee agreement at December 31, 2017.

In addition, at December 31, 2017, 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, 2017, Dominion Energy had issued the following subsidiary guarantees:

|  | Maximum Exposure |
(millions) |  |  |
Commodity transactions(1) |  |  | $2,027 |
Nuclear obligations(2) |  |  | 227 |
Cove Point(3) |  |  | 1,900 |
Solar(4) |  |  | 1,064 |
Other(5) |  |  | 553 |
Total(6) |  |  | $5,771 |

(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, 2017, Dominion Energy’s maximum remaining cumulative exposure under these equity funding agreements is $17 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $14 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, 2017, Dominion Energy had purchased $153 million of surety bonds, including $63 million at Virginia Power and $24 million at Dominion Energy Gas, and authorized the issuance of letters of credit by financial institutions of $76 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.

As of December 31, 2017, Virginia Power had issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. The related debt matures in 2031 and is included in long-term debt in Virginia Power’s Consolidated Balance Sheets. In the event of default by a conduit, Virginia Power would be obligated to repay such amounts, which are limited to the principal and interest then outstanding.

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

107

Combined Notes to Consolidated Financial Statements, Continued

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, 2017, 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, 2017 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 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, 2017, Dominion Energy’s credit exposure totaled $95 million. Of this amount, investment grade counterparties, including those internally rated, represented 26%, and no single counterparty, whether investment grade or non-investment grade, exceeded $13 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, 2017, Virginia Power’s credit exposure totaled $60 million. Of this amount, investment grade counterparties, including those internally rated, represented 9%, and no single counterparty, whether investment grade or non-investment grade, exceeded $13 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, 2017, Dominion Energy Gas’ credit exposure totaled $15 million. Of this amount, investment grade counterparties, including those internally rated, represented 22%, and no single counterparty, whether investment grade or non-investment grade, exceeded $4 million of exposure.

In 2017, DETI provided service to 289 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 68% 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 98% 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

108 |  |  |  |

specific events, primarily a credit 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, 2017 and 2016, Dominion Energy would have been required to post an additional $62 million and $3 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, 2017 and 2016, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of December 31, 2017 and 2016 was $65 million and $9 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, 2017 and 2016. 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’s 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 commodity swaps, to manage commodity price risks associated with purchases of natural gas. See Notes 7 and 19 for more information. As of December 31, 2017, Virginia Power’s derivative assets and liabilities with affiliates were $11 million and $5 million, respectively. As of December 31, 2016, Virginia Power’s derivative assets and liabilities with affiliates were $41 million and $8 million, respectively.

Virginia Power participates in certain Dominion Energy benefit plans as described in Note 21. At December 31, 2017 and 2016, Virginia Power’s amounts due to Dominion Energy asso-

ciated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets were $505 million and $396 million, respectively. At December 31, 2017 and 2016, 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 $199 million and $130 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, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Commodity purchases from affiliates |  | $ | 674 |  |  | $ | 571 |  |  | $ | 555 |
Services provided by affiliates(1) |  |  | 453 |  |  |  | 454 |  |  |  | 422 |
Services provided to affiliates |  |  | 25 |  |  |  | 22 |  |  |  | 22 |

(1) | Includes capitalized expenditures of $144 million, $144 million and $143 million for the year ended December 31, 2017, 2016 and 2015, respectively.

Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. There were $33 million and $262 million in short-term demand note borrowings from Dominion Energy as of December 31, 2017 and 2016, respectively. The weighted-average interest rate of these borrowings was 1.65% and 0.97% at December 31, 2017 and 2016, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion Energy money pool for its nonregulated subsidiaries as of December 31, 2017 and 2016. Interest charges related to Virginia Power’s borrowings from Dominion Energy were immaterial for the years ended December 31, 2017, 2016 and 2015.

There were no issuances of Virginia Power’s common stock to Dominion Energy in 2017, 2016 or 2015.

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, which are presented separately from contracts involving

109

Combined Notes to Consolidated Financial Statements, Continued

commodities or services. As of December 31, 2017 and 2016, 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, 2017 and 2016, 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 $734 million and $697 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 $7 million and $2 million at December 31, 2017 and 2016, 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, |  | 2017 |  |  | 2016 |  |  | 2015 |
(millions) |  |  |  |  |  |  |  |  |
Purchases of natural gas and transportation and storage services from affiliates |  | $ | 5 |  |  | $ | 9 |  |  | $ | 10 |
Sales of natural gas and transportation and storage services to affiliates |  |  | 70 |  |  |  | 69 |  |  |  | 69 |
Services provided by related parties(1) |  |  | 143 |  |  |  | 141 |  |  |  | 133 |
Services provided to related parties(2) |  |  | 156 |  |  |  | 128 |  |  |  | 101 |

(1) | Includes capitalized expenditures of $45 million, $49 million and $57 million for the year ended December 31, 2017, 2016 and 2015, respectively.

(2) | Amounts primarily attributable to Atlantic Coast Pipeline.

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

At December 31, |  | 2017 |  |  | 2016 |
(millions) |  |  |  |  |  |
Other receivables(1) |  | $ | 12 |  |  | $ | 10 |
Customer receivables from related parties |  |  | 1 |  |  |  | 1 |
Imbalances receivable from affiliates |  |  | 1 |  |  |  | 2 |
Imbalances payable to affiliates(2) |  |  | — |  |  |  | 4 |
Affiliated notes receivable(3) |  |  | 20 |  |  |  | 18 |

(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 $18 million and $118 million as of December 31, 2017 and 2016, respectively. The weighted-average interest rate of these borrowings was 1.60% and 1.08% at December 31, 2017 and 2016, respectively. Interest charges related to Dominion Energy Gas’ total borrowings from Dominion Energy were immaterial for 2017, 2016 and 2015.

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 fleet |  | X |  | X |  |
|  | Merchant electric 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 2017, Dominion Energy reported an after-tax net benefit of $389 million in the Corporate and Other segment, with $861 million of the net benefit attributable to specific items related to its operating segments.

The net benefit 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);

110 |  |  |  |

| • |  | 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).

In 2015, Dominion Energy reported after-tax net expenses of $391 million in the Corporate and Other segment, with $136 million of these net expenses attributable to specific items related to its operating segments.

The net expenses for specific items in 2015 primarily related to the impact of the following items:

• |  | A $99 million ($60 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Power Generation; and

• |  | An $85 million ($52 million after-tax) write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015, attributable to Power Generation.

111

Combined Notes to Consolidated Financial Statements, Continued

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) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
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 |
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 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 |
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 |
Investment in equity method investees |  |  | — |  |  |  | 228 |  |  |  | 1,289 |  |  |  | 44 |  |  |  | — |  |  |  | 1,561 |
Capital expenditures |  |  | 1,320 |  |  |  | 2,440 |  |  |  | 2,322 |  |  |  | 43 |  |  |  | — |  |  |  | 6,125 |
Total assets (billions) |  |  | 15.6 |  |  |  | 27.1 |  |  |  | 26.0 |  |  |  | 10.2 |  |  |  | (7.3 | ) |  |  | 71.6 |
2015 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total revenue from external customers |  |  | $2,091 |  |  |  | $7,001 |  |  |  | $1,877 |  |  |  | $ (27) |  |  |  | $ 741 |  |  |  | $11,683 |
Intersegment revenue |  |  | 20 |  |  |  | 15 |  |  |  | 695 |  |  |  | 554 |  |  |  | (1,284 | ) |  |  | — |
Total operating revenue |  |  | 2,111 |  |  |  | 7,016 |  |  |  | 2,572 |  |  |  | 527 |  |  |  | (543 | ) |  |  | 11,683 |
Depreciation, depletion and amortization |  |  | 498 |  |  |  | 591 |  |  |  | 262 |  |  |  | 44 |  |  |  | — |  |  |  | 1,395 |
Equity in earnings of equity method investees |  |  | — |  |  |  | (15 | ) |  |  | 60 |  |  |  | 11 |  |  |  | — |  |  |  | 56 |
Interest income |  |  | — |  |  |  | 64 |  |  |  | 25 |  |  |  | 13 |  |  |  | (44 | ) |  |  | 58 |
Interest and related charges |  |  | 230 |  |  |  | 262 |  |  |  | 27 |  |  |  | 429 |  |  |  | (44 | ) |  |  | 904 |
Income tax expense (benefit) |  |  | 307 |  |  |  | 465 |  |  |  | 423 |  |  |  | (290 | ) |  |  | — |  |  |  | 905 |
Net income (loss) attributable to Dominion Energy |  |  | 490 |  |  |  | 1,120 |  |  |  | 680 |  |  |  | (391 | ) |  |  | — |  |  |  | 1,899 |
Investment in equity method investees |  |  | — |  |  |  | 245 |  |  |  | 1,042 |  |  |  | 33 |  |  |  | — |  |  |  | 1,320 |
Capital expenditures |  |  | 1,607 |  |  |  | 2,190 |  |  |  | 2,153 |  |  |  | 43 |  |  |  | — |  |  |  | 5,993 |

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 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.

In 2015, Virginia Power reported after-tax net expenses of $153 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net expenses for specific items in 2015 primarily related to the impact of the following items:

• |  | A $99 million ($60 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Power Generation; and

• |  | An $85 million ($52 million after-tax) write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015, attributable to Power Generation.

112 |  |  |  |

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) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
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 |
Total assets (billions) |  |  | 15.6 |  |  |  | 17.8 |  |  |  | — |  |  |  | (0.1 | ) |  |  | 33.3 |
2015 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  |  | $2,099 |  |  |  | $5,566 |  |  |  | $ (43 | ) |  |  | $ — |  |  |  | $7,622 |
Depreciation and amortization |  |  | 498 |  |  |  | 453 |  |  |  | 2 |  |  |  | — |  |  |  | 953 |
Interest income |  |  | — |  |  |  | 7 |  |  |  | — |  |  |  | — |  |  |  | 7 |
Interest and related charges |  |  | 230 |  |  |  | 210 |  |  |  | 4 |  |  |  | (1 | ) |  |  | 443 |
Income tax expense (benefit) |  |  | 308 |  |  |  | 437 |  |  |  | (86 | ) |  |  | — |  |  |  | 659 |
Net income (loss) |  |  | 490 |  |  |  | 750 |  |  |  | (153 | ) |  |  | — |  |  |  | 1,087 |
Capital expenditures |  |  | 1,569 |  |  |  | 1,120 |  |  |  | — |  |  |  | — |  |  |  | 2,689 |

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 2017, Dominion Energy Gas reported after-tax net expenses 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.

In 2015, Dominion Energy Gas reported after-tax net expenses of $21 million in its Corporate and Other segment, with $13 million of these net expenses attributable to specific items related to its operating segment.

The net expenses for specific items in 2015 primarily related to the impact of the following item:

• |  | $16 million ($10 million after-tax) ceiling test impairment charge.

|  |  |  | 113

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) |  |  |  |  |  |  |  |  |
2017 |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  |  | $1,814 |  |  |  | $ — |  |  |  | $1,814 |
Depreciation and amortization |  |  | 227 |  |  |  | — |  |  |  | 227 |
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 |
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 |
Investment in equity method investees |  |  | 98 |  |  |  | — |  |  |  | 98 |
Capital expenditures |  |  | 854 |  |  |  | — |  |  |  | 854 |
Total assets (billions) |  |  | 10.5 |  |  |  | 0.6 |  |  |  | 11.1 |
2015 |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  |  | $1,716 |  |  |  | $ — |  |  |  | $1,716 |
Depreciation and amortization |  |  | 213 |  |  |  | 4 |  |  |  | 217 |
Equity in earnings of equity method investees |  |  | 23 |  |  |  | — |  |  |  | 23 |
Interest income |  |  | 1 |  |  |  | — |  |  |  | 1 |
Interest and related charges |  |  | 72 |  |  |  | 1 |  |  |  | 73 |
Income tax expense (benefit) |  |  | 296 |  |  |  | (13 | ) |  |  | 283 |
Net income (loss) |  |  | 478 |  |  |  | (21 | ) |  |  | 457 |
Investment in equity method investees |  |  | 102 |  |  |  | — |  |  |  | 102 |
Capital expenditures |  |  | 795 |  |  |  | — |  |  |  | 795 |

114 |  |  |  |

NOTE 26. QUARTERLY FINANCIAL AND COMMON STOCK DATA (UNAUDITED)

A summary of the Companies’ quarterly results of operations for the years ended December 31, 2017 and 2016 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, except per share amounts) |  |  |  |  |  |  |  |  |  |  |  |
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 share |  |  | 0.755 |  |  |  | 0.755 |  |  |  | 0.770 |  |  |  | 0.770 |
Common stock prices (intraday high-low) |  | $ | 79.36 - 70.87 |  |  | $ | 81.65 - 76.17 |  |  | $ | 80.67 - 75.40 |  |  | $ | 85.30 - 75.75 |
2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  | $ | 2,921 |  |  | $ | 2,598 |  |  | $ | 3,132 |  |  | $ | 3,086 |
Income from operations |  |  | 841 |  |  |  | 740 |  |  |  | 1,102 |  |  |  | 765 |
Net income including noncontrolling interests |  |  | 531 |  |  |  | 462 |  |  |  | 728 |  |  |  | 491 |
Net income attributable to Dominion Energy |  |  | 524 |  |  |  | 452 |  |  |  | 690 |  |  |  | 457 |
Basic EPS: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income attributable to Dominion Energy |  |  | 0.88 |  |  |  | 0.73 |  |  |  | 1.10 |  |  |  | 0.73 |
Diluted EPS: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income attributable to Dominion Energy |  |  | 0.88 |  |  |  | 0.73 |  |  |  | 1.10 |  |  |  | 0.73 |
Dividends declared per share |  |  | 0.700 |  |  |  | 0.700 |  |  |  | 0.700 |  |  |  | 0.700 |
Common stock prices (intraday high-low) |  | $ | 75.18 - 66.25 |  |  | $ | 77.93 - 68.71 |  |  | $ | 78.97 - 72.49 |  |  | $ | 77.32 - 69.51 |

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

Dominion Energy’s 2016 results include the impact of the following significant item:

• |  | Fourth quarter results include a $122 million after-tax charge related to future ash pond and landfill closure costs at certain utility generation facilities.

VIRGINIA POWER

Virginia Power’s quarterly results of operations were as follows:

|  | First Quarter |  |  | Second Quarter |  |  | Third Quarter |  |  | Fourth Quarter |
(millions) |  |  |  |  |  |  |  |  |  |  |  |
2017 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  | $ | 1,831 |  |  | $ | 1,747 |  |  | $ | 2,154 |  |  | $ | 1,824 |
Income from operations |  |  | 653 |  |  |  | 613 |  |  |  | 847 |  |  |  | 619 |
Net income |  |  | 356 |  |  |  | 318 |  |  |  | 459 |  |  |  | 407 |
2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  | $ | 1,890 |  |  | $ | 1,776 |  |  | $ | 2,211 |  |  | $ | 1,711 |
Income from operations |  |  | 514 |  |  |  | 553 |  |  |  | 914 |  |  |  | 369 |
Net income |  |  | 263 |  |  |  | 280 |  |  |  | 503 |  |  |  | 172 |

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.

Virginia Power’s 2016 results include the impact of the following significant item:

• |  | Fourth quarter results include a $121 million after-tax charge related to future ash pond and landfill closure costs at certain utility generation facilities.

DOMINION ENERGY GAS

Dominion Energy Gas’ quarterly results of operations were as follows:

|  | First Quarter |  |  | Second Quarter |  |  | Third Quarter |  |  | Fourth Quarter |
(millions) |  |  |  |  |  |  |  |  |  |  |  |
2017 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  |  | $490 |  |  |  | $422 |  |  |  | $401 |  |  |  | $501 |
Income from operations |  |  | 156 |  |  |  | 116 |  |  |  | 185 |  |  |  | 181 |
Net income |  | 108 |  |  | 77 |  |  | 117 |  |  | 313 |
2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  |  | $431 |  |  |  | $368 |  |  |  | $382 |  |  |  | $457 |
Income from operations |  |  | 156 |  |  |  | 167 |  |  |  | 114 |  |  |  | 156 |
Net income |  |  | 98 |  |  |  | 105 |  |  |  | 83 |  |  |  | 106 |

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.

There were no significant items impacting Dominion Energy Gas’ 2016 quarterly results.

115