10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2017

OR

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

For the transition period from                      to                     

 

Commission File Number    Exact name of registrants as specified in their charters   

I.R.S. Employer

Identification Number

001-08489    DOMINION ENERGY, INC.    54-1229715
000-55337    VIRGINIA ELECTRIC AND POWER COMPANY    54-0418825
001-37591    DOMINION ENERGY GAS HOLDINGS, LLC    46-3639580
  

VIRGINIA

(State or other jurisdiction of incorporation or organization)

  
  

120 TREDEGAR STREET

RICHMOND, VIRGINIA

(Address of principal executive offices)

  

23219

(Zip Code)

    

(804) 819-2000

(Registrants’ telephone number)

    

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

 

Registrant

 

Title of Each Class

 

Name of Each Exchange

on Which Registered

DOMINION ENERGY, INC.   Common Stock, no par value   New York Stock Exchange
  2016 Series A 6.75% Corporate Units   New York Stock Exchange
  2016 Series A 5.25% Enhanced Junior Subordinated Notes   New York Stock Exchange
DOMINION ENERGY GAS HOLDINGS, LLC   2014 Series C 4.6% Senior Notes   New York Stock Exchange

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

VIRGINIA ELECTRIC AND POWER COMPANY

Common Stock, no par value

DOMINION ENERGY GAS HOLDINGS, LLC

Limited Liability Company Membership Interests

 

 

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

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

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

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

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

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

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

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

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

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

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

Dominion Energy, Inc.

 

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

(Do not check if a smaller

reporting company)

  Emerging growth company  ☐

Virginia Electric and Power Company

 

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

(Do not check if a smaller

reporting company)

  Emerging growth company  ☐

Dominion Energy Gas Holdings, LLC

 

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

(Do not check if a smaller

reporting company)

  Emerging growth company  ☐

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

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

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

The aggregate market value of Dominion Energy, Inc. common stock held by non-affiliates of Dominion Energy was approximately $48.1 billion based on the closing price of Dominion Energy’s common stock as reported on the New York Stock Exchange as of the last day of Dominion Energy’s most recently completed second fiscal quarter. Dominion Energy is the sole holder of Virginia Electric and Power Company common stock. At February 15, 2018, Dominion Energy had 651,524,668 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding. Dominion Energy, Inc. holds all of the membership interests of Dominion Energy Gas Holdings, LLC.

DOCUMENT INCORPORATED BY REFERENCE.

Portions of Dominion Energy’s 2018 Proxy Statement are incorporated by reference in Part III.

This combined Form 10-K represents separate filings by Dominion Energy, Inc., Virginia Electric and Power Company and Dominion Energy Gas Holdings, LLC. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Virginia Electric and Power Company and Dominion Energy Gas Holdings, LLC make no representations as to the information relating to Dominion Energy, Inc.’s other operations.

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

 

 

 


Table of Contents

Dominion Energy, Inc., Virginia Electric and

Power Company and Dominion Energy Gas Holdings, LLC

 

 

Item

Number

         

Page

Number

 

 

  

Glossary of Terms

     3  

Part I

  

1.

  

Business

     8  

1A.

  

Risk Factors

     27  

1B.

  

Unresolved Staff Comments

     36  

2.

  

Properties

     37  

3.

  

Legal Proceedings

     40  

4.

  

Mine Safety Disclosures

     40  
  

Executive Officers of Dominion Energy

     41  

Part II

  

5.

  

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

     43  

6.

  

Selected Financial Data

     44  

7.

  

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

     45  

7A.

  

Quantitative and Qualitative Disclosures About Market Risk

     63  

8.

  

Financial Statements and Supplementary Data

     65  

9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     176  

9A.

  

Controls and Procedures

     176  

9B.

  

Other Information

     179  

Part III

  

10.

  

Directors, Executive Officers and Corporate Governance

     180  

11.

  

Executive Compensation

     180  

12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     180  

13.

  

Certain Relationships and Related Transactions, and Director Independence

     180  

14.

  

Principal Accountant Fees and Services

     181  

Part IV

  

15.

  

Exhibits and Financial Statement Schedules

     182  

16.

  

Form 10-K Summary

     189  

 

2        


Table of Contents

Glossary of Terms

    

 

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

 

Abbreviation or Acronym    Definition

2013 Equity Units

  

Dominion Energy’s 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013

2014 Equity Units

  

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

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

2018 Proxy Statement

  

Dominion Energy 2018 Proxy Statement, File No. 001-08489

ABO

  

Accumulated benefit obligation

AFUDC

  

Allowance for funds used during construction

AMI

  

Advanced Metering Infrastructure

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

Atlantic Coast Pipeline Project

  

The approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina which will be owned by Dominion Energy, Duke and Southern Company Gas and constructed and operated by DETI

BACT

  

Best available control technology

bcf

  

Billion cubic feet

bcfe

  

Billion cubic feet equivalent

Bear Garden

  

A 590 MW combined cycle, natural gas-fired power station in Buckingham County, Virginia

BGEPA

Blue Racer

  

Bald and Golden Eagle Protection Act

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

BP

  

BP Wind Energy North America Inc.

Brayton Point

  

Brayton Point power station

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

CAO

  

Chief Accounting Officer

CCR

  

Coal combustion residual

CEO

  

Chief Executive Officer

CERCLA

  

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

CFO

  

Chief Financial Officer

CGN Committee

  

Compensation, Governance and Nominating Committee of Dominion Energy’s Board of Directors

Clean Power Plan

  

Regulations issued by the EPA in August 2015 for states to follow in developing plans to reduce CO2 emissions from existing fossil fuel-fired electric generating units, stayed by the U.S. Supreme Court in February 2016 pending resolution of court challenges by certain states

CNG

  

Consolidated Natural Gas Company

CO2

  

Carbon dioxide

COL

  

Combined Construction Permit and Operating License

Companies

  

Dominion Energy, Virginia Power and Dominion Energy Gas, collectively

COO

  

Chief Operating Officer

Cooling degree days

  

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

Corporate Unit

  

A stock purchase contract and 1/20 or 1/40 interest in a RSN issued by Dominion Energy

Cove Point

  

Dominion Energy Cove Point LNG, LP

Cove Point Holdings

  

Cove Point GP Holding Company, LLC

CPCN

  

Certificate of Public Convenience and Necessity

CWA

  

Clean Water Act

DECG

  

Dominion Energy Carolina Gas Transmission, LLC

DES

  

Dominion Energy Services, Inc.

DETI

  

Dominion Energy Transmission, Inc.

DGI

  

Dominion Generation, Inc.

 

        3


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Abbreviation or Acronym    Definition

DGP

  

Dominion Gathering and Processing, Inc.

Dodd-Frank Act

  

The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010

DOE

  

U.S. Department of Energy

Dominion Energy

  

The legal entity, Dominion Energy, Inc., one or more of its consolidated subsidiaries (other than Virginia Power and Dominion Energy Gas) or operating segments, or the entirety of Dominion Energy, Inc. and its consolidated subsidiaries

Dominion Energy Direct®

  

A dividend reinvestment and open enrollment direct stock purchase plan

Dominion Energy Gas

  

The legal entity, Dominion Energy Gas Holdings, LLC, one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion Energy Gas Holdings, LLC and its consolidated subsidiaries

Dominion Energy Midstream

  

The legal entity, Dominion Energy Midstream Partners, LP, one or more of its consolidated subsidiaries, Cove Point Holdings, Iroquois GP Holding Company, LLC, DECG and Dominion Energy Questar Pipeline (beginning December 1, 2016) or 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

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

Dominion Iroquois

  

Dominion Iroquois, Inc., which, effective May 2016, holds a 24.07% noncontrolling partnership interest in Iroquois

DSM

  

Demand-side management

Dth

  

Dekatherm

Duke

  

The legal entity, Duke Energy Corporation, one or more of its consolidated subsidiaries or operating segments, or the entirety of Duke Energy Corporation and its consolidated subsidiaries

East Ohio

  

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

Eastern Market Access Project

  

Project to provide 294,000 Dths/day of firm transportation service to help meet demand for natural gas for Washington Gas Light Company, a local gas utility serving customers in D.C., Virginia and Maryland, and Mattawoman Energy, LLC for its new electric power generation facility to be built in Maryland

Elwood

  

Elwood power station

Energy Choice

  

Program authorized by the Ohio Commission which provides energy customers with the ability to shop for energy options from a group of suppliers certified by the Ohio Commission

EPA

  

U.S. Environmental Protection Agency

EPACT

  

Energy Policy Act of 2005

EPS

  

Earnings per share

ERISA

  

Employee Retirement Income Security Act of 1974

ERM

  

Enterprise Risk Management

ERO

  

Electric Reliability Organization

ESA

Excess Tax Benefits

  

Endangered Species Act

Benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation

FASB

  

Financial Accounting Standards Board

FERC

  

Federal Energy Regulatory Commission

Fitch

  

Fitch Ratings Ltd.

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 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

Hastings

  

A natural gas processing and fractionation facility located near Pine Grove, West Virginia

HATFA of 2014

  

Highway and Transportation Funding Act of 2014

 

4        


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Abbreviation or Acronym    Definition

Heating degree days

  

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

Hope

  

Hope Gas, Inc., doing business as Dominion Energy West Virginia

Idaho Commission

  

Idaho Public Utilities Commission

IRCA

  

Intercompany revolving credit agreement

Iron Springs

  

Iron Springs Holdings, LLC, a limited liability company owned by Dominion Energy and Iron Springs Renewables, LLC, a 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

Kincaid

  

Kincaid power station

kV

  

Kilovolt

Liability Management Exercise

  

Dominion Energy exercise in 2014 to redeem certain debt and preferred securities

LIBOR

  

London Interbank Offered Rate

LIFO

  

Last-in-first-out inventory method

Line TL-388

  

A 37-mile, 24-inch gathering pipeline extending from Texas Eastern, LP in Noble County, Ohio to its terminus at Dominion Energy’s Gilmore Station in Tuscarawas County, Ohio

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

MBTA

mcf

  

Migratory Bird Treaty Act of 1918

Thousand cubic feet

mcfe

  

Thousand cubic feet equivalent

MD&A

  

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

MGD

  

Million gallons a day

Millstone

  

Millstone nuclear power station

MISO

  

Midcontinent Independent System Operator, Inc.

MLP

  

Master limited partnership, also known as publicly traded partnership

Moody’s

  

Moody’s Investors Service

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 in Grant County, West Virginia

NEIL

  

Nuclear Electric Insurance Limited

NERC

  

North American Electric Reliability Corporation

NGL

  

Natural gas liquid

NJNR

  

NJNR Pipeline Company

North Anna

  

North Anna nuclear power station

North Carolina Commission

  

North Carolina Utilities Commission

Northern System

  

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

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

 

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Table of Contents

    

    

 

Abbreviation or Acronym    Definition

ODEC

  

Old Dominion Electric Cooperative

Ohio Commission

  

Public Utilities Commission of Ohio

Order 1000

  

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

Philadelphia Utility Index

  

Philadelphia Stock Exchange Utility Index

PHMSA

  

Pipeline and Hazardous Materials Safety Administration

PIPP

  

Percentage of Income Payment Plan deployed by East Ohio

PIR

  

Pipeline Infrastructure Replacement program deployed by East Ohio

PJM

  

PJM Interconnection, L.L.C.

Power Delivery

  

Power Delivery Group operating segment

Power Generation

  

Power Generation Group operating segment

ppb

  

Parts-per-billion

PREP

  

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

PSMP

  

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

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

RGGI

  

Regional Greenhouse Gas Initiative

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

RTEP

  

Regional transmission expansion plan

RTO

  

Regional transmission organization

SAFSTOR

  

A method of nuclear decommissioning, as defined by the NRC, in which a nuclear facility is placed and maintained in a condition that allows the facility to be safely stored and subsequently decontaminated to levels that permit release for unrestricted use

SAIDI

  

System Average Interruption Duration Index, metric used to measure electric service reliability

SBL Holdco

  

SBL Holdco, LLC, a wholly-owned subsidiary of DGI

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

Shell

  

Shell WindEnergy, Inc.

SO2

  

Sulfur dioxide

South Carolina Commission

  

South Carolina Public Service Commission

Standard & Poor’s

  

Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.

 

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Table of Contents

    

    

 

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

West Virginia Commission

  

Public Service Commission of West 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

Wexpro Agreement

  

An agreement effective August 1981, which sets forth the rights of Questar Gas to receive certain benefits from Wexpro’s operations, including cost-of-service gas

Wexpro II Agreement

  

An agreement with the states of Utah and Wyoming modeled after the Wexpro Agreement that allows for the addition of properties under the cost-of-service methodology for the benefit of Questar Gas customers

Whitehouse

  

A 20 MW utility-scale solar power station in Louisa County, VA

White River Hub

  

White River Hub, LLC

Woodland

  

A 19 MW utility-scale solar power station in Isle of Wight County, VA

Wyoming Commission

  

Wyoming Public Service Commission

 

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Table of Contents

Part I

    

 

 

Item 1. Business

GENERAL

Dominion Energy, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Dominion Energy’s strategy is to be a leading provider of electricity, natural gas and related services to customers primarily in the eastern and Rocky Mountain regions of the U.S. As of December 31, 2017, Dominion Energy’s portfolio of assets includes approximately 26,000 MW of generating capacity, 6,600 miles of electric transmission lines, 57,900 miles of electric distribution lines, 14,800 miles of natural gas transmission, gathering and storage pipelines and 51,800 miles of gas distribution pipeline, exclusive of service lines. As of December 31, 2017, Dominion Energy serves nearly 6 million utility and retail energy customers and operates one of the nation’s largest underground natural gas storage systems, with approximately 1 trillion cubic feet of storage capacity.

In September 2016, Dominion Energy completed the Dominion Energy Questar Combination for total consideration of $4.4 billion and Dominion Energy Questar, a Rockies-based integrated natural gas company, became a wholly-owned subsidiary of Dominion Energy. Questar Gas, a wholly-owned subsidiary of Dominion Energy Questar, is consolidated by Dominion Energy, and is a voluntary SEC filer. However, its Form 10-K is filed separately and is not combined herein.

In March 2014, Dominion Energy formed Dominion Energy Midstream, an MLP designed to grow a portfolio of natural gas terminaling, processing, storage, transportation and related assets. In October 2014, Dominion Energy Midstream launched its initial public offering and issued 20,125,000 common units representing limited partner interests. Dominion Energy has and may continue to investigate opportunities to acquire assets that meet its strategic objective for Dominion Energy Midstream. 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. Dominion Energy Midstream is consolidated by Dominion Energy, and is an SEC registrant. However, its Form 10-K is filed separately and is not combined herein.

Dominion Energy is focused on expanding its investment in regulated electric generation, transmission and distribution and regulated natural gas transmission and distribution infrastructure. Dominion Energy expects approximately 90% of earnings from its primary operating segments to come from regulated and long-term contracted businesses.

Dominion Energy continues to expand and improve its regulated and long-term contracted electric and natural gas businesses, in accordance with its existing five-year capital investment program. A major impetus for this program is to meet the anticipated increase in demand in its electric utility service territory. Other drivers for the capital investment program include the construction of infrastructure to handle the increase in natural gas production from the Marcellus and Utica Shale formations, to upgrade Dominion Energy’s gas and electric transmission and distribution networks, and to meet environmental requirements

and standards set by various regulatory bodies. Investments in utility-scale solar generation are expected to be a focus in meeting such environmental requirements, particularly in Virginia. In September 2014, Dominion Energy announced the formation of Atlantic Coast Pipeline. Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, to increase natural gas supplies in the region.

Dominion Energy has transitioned over the past decade to a more regulated, less volatile earnings mix as evidenced by its capital investments in regulated infrastructure, including the Dominion Energy Questar Combination, and in infrastructure whose output is sold under long-term purchase agreements as well as the sale of the electric retail energy marketing business in March 2014. Dominion Energy’s nonregulated operations include merchant generation, energy marketing and price risk management activities and natural gas retail energy marketing operations. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Energy Gas.

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

Dominion Energy Gas, a limited liability company formed in September 2013, is a wholly-owned subsidiary of Dominion Energy and a holding company. It serves as the intermediate parent company for certain of Dominion Energy’s regulated natural gas operating subsidiaries, which conduct business activities through a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, regulated gas transportation and distribution operations in Ohio, and gas gathering and processing activities primarily in West Virginia, Ohio and Pennsylvania. Dominion Energy Gas’ principal wholly-owned subsidiaries are DETI, East Ohio, DGP and Dominion Iroquois. DETI is an interstate natural gas transmission pipeline company serving a broad mix of customers such as local gas distribution companies, marketers, interstate and intrastate pipelines, electric power generators and natural gas producers. The DETI system links to other major pipelines and markets in the mid-Atlantic, Northeast, and Midwest including Dominion Energy’s Cove Point pipeline. DETI also operates one of the largest underground natural gas storage systems in the U.S. In August 2016, DETI transferred its gathering and processing facilities to DGP. East Ohio is a regulated natural gas distribution operation serving residential, commercial and industrial gas sales and transportation customers. Its service territory includes Cleveland, Akron, Canton, Youngstown and other eastern and western Ohio communities. In May 2016,

 

 

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Dominion Energy Gas sold 0.65% of the noncontrolling partnership interest in Iroquois, a FERC-regulated interstate natural gas pipeline in New York and Connecticut, to TransCanada. At December 31, 2017, Dominion Energy Gas holds a 24.07% noncontrolling partnership interest in Iroquois. All of Dominion Energy Gas’ membership interests are owned by Dominion Energy.

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

 

 

EMPLOYEES

At December 31, 2017, Dominion Energy had approximately 16,200 full-time employees, of which approximately 5,200 are subject to collective bargaining agreements. At December 31, 2017, Virginia Power had approximately 6,900 full-time employees, of which approximately 3,100 are subject to collective bargaining agreements. At December 31, 2017, Dominion Energy Gas had approximately 3,000 full-time employees, of which approximately 2,100 are subject to collective bargaining agreements.

 

 

WHERE YOU CAN FIND MORE INFORMATION ABOUT THE COMPANIES

The Companies file their annual, quarterly and current reports, proxy statements and other information with the SEC. Their SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov. You may also read and copy any document they file at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

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

 

 

ACQUISITIONS AND DISPOSITIONS

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

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 estimated 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. Subject to receipt of SCANA shareholder and any required regulatory approvals and meeting closing conditions, Dominion Energy targets closing by the end of 2018. See Note 3 to the Consolidated Financial Statements for additional information.

ACQUISITION OF DOMINION ENERGY QUESTAR

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

ACQUISITION OF WHOLLY-OWNED MERCHANT SOLAR PROJECTS

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

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

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

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

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

ACQUISITION OF VIRGINIA POWER SOLAR PROJECTS

In 2017, Virginia Power entered into agreements to acquire two solar development projects in North Carolina. The projects are expected to close in 2018 and 2019 with a total expected cost of $280 million once constructed, including the initial acquisition cost, and will generate approximately 155 MW combined. See Note 10 to the Consolidated Financial Statements for additional information.

SALE OF CERTAIN RETAIL ENERGY MARKETING ASSETS

In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy marketing operations for total consideration of $143 million, subject to customary approvals and certain adjustments. Pursuant to the agreement, upon the first closing in December 2017,

 

 

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Dominion Energy entered into a commission agreement under which the buyer will pay a commission in connection with the right to use Dominion Energy’s brand in marketing materials and other services over a ten-year term. See Note 10 to the Consolidated Financial Statements for additional information.

ASSIGNMENT OF TOWER RENTAL PORTFOLIO

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

ACQUISITION OF NON-WHOLLY-OWNED MERCHANT SOLAR PROJECTS

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

SALE OF INTEREST IN MERCHANT SOLAR PROJECTS

In September 2015, Dominion Energy signed an agreement to sell a noncontrolling interest (consisting of 33% of the equity interests) in all of its then wholly-owned merchant solar projects, 24 solar projects totaling 425 MW, to SunEdison. In December 2015, the sale of interest in 15 of the solar projects closed for $184 million with the sale of interest in the remaining projects completed in January 2016 for $117 million. Upon closing, SunEdison sold its interest in these projects to Terra Nova Renewable Partners. See Note 3 to the Consolidated Financial Statements for additional information.

DOMINION ENERGY MIDSTREAM ACQUISITION OF INTEREST IN IROQUOIS

In September 2015, Dominion Energy Midstream acquired from NG and NJNR a 25.93% noncontrolling partnership interest in Iroquois. The investment was recorded at $216 million based on the value of Dominion Energy Midstream’s common units at closing. The common units issued to NG and NJNR are reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. See Note 3 to the Consolidated Financial Statements for additional information.

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. In April 2015, Dominion Energy contributed DECG to Dominion Energy Midstream. See Note 3 to the Consolidated Financial Statements for additional information.

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 natural gas storage fields. The agreements provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from that acreage. In March 2015, Dominion Energy Gas and a natural gas producer closed on an amendment to a December 2013 agreement, which included the immediate conveyance of approximately 9,000 acres of Marcellus Shale development rights and a two-year extension of the term of the original agreement. The conveyance of development rights resulted in the recognition of $43 million of previously deferred revenue. In April 2016, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the immediate conveyance of a 32% partial interest in the remaining approximately 70,000 acres. This conveyance resulted in the recognition of the remaining $35 million of previously deferred revenue. In August 2017, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the finalization of contractual matters on previous conveyances, the conveyance of Dominion Energy Gas’ remaining 68% interest in approximately 70,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. As a result of this amendment, Dominion Energy Gas will receive total consideration of $130 million, with $65 million received in November 2017 and $65 million to be received by the end of the third quarter of 2018 in connection with the final conveyance.

In March 2015, Dominion Energy Gas conveyed to a natural gas producer approximately 11,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields and received proceeds of $27 million and an overriding royalty interest in gas produced from the acreage.

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

In November 2014, Dominion Energy Gas closed on an agreement with a natural gas producer to convey over time approximately 24,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. The agreement provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $120 million over a period of four years, and an overriding royalty interest in gas produced from the acreage. In January 2018, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the conveyance of Dominion Energy Gas’ remaining 50% interest in approximately 18,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage for proceeds of $28 million.

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

 

 

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SALE OF ELECTRIC RETAIL ENERGY MARKETING BUSINESS

In March 2014, Dominion Energy completed the sale of its electric retail energy marketing business. The proceeds were $187 million, net of transaction costs. The sale of the electric retail energy marketing business did not qualify for discontinued operations classification.

SALE OF PIPELINES AND PIPELINE SYSTEMS

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

In September 2013, DETI sold Line TL-388 to Blue Racer for $75 million in cash proceeds.

SALE OF BRAYTON POINT, KINCAID AND EQUITY METHOD INVESTMENT IN ELWOOD

In August 2013, Dominion Energy completed the sale of Brayton Point, Kincaid and its equity method investment in Elwood to Energy Capital Partners and received proceeds of $465 million, net of transaction costs. The historical results of Brayton Point’s and Kincaid’s operations are presented in discontinued operations.

 

 

OPERATING SEGMENTS

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 other operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.

Virginia Power manages its daily operations through two primary operating segments: Power Delivery and Power Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.

Dominion Energy Gas manages its daily operations through its primary operating segment: Gas Infrastructure. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources and the effect of certain items recorded at Dominion Energy Gas as a result of Dominion Energy’s basis in the net assets contributed.

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

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

 

Primary Operating
Segment
  Description of Operations   Dominion
Energy
  Virginia
Power
  Dominion
Energy Gas

Power Delivery

 

Regulated electric distribution

      X         X      
   

Regulated electric transmission

      X         X            

Power Generation

 

Regulated electric 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.

For additional financial information on operating segments, including revenues from external customers, see Note 25 to the Consolidated Financial Statements. For additional information on operating revenue related to the Companies’ principal products and services, see Notes 2 and 4 to the Consolidated Financial Statements, which information is incorporated herein by reference.

Power Delivery

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

Power Delivery’s existing five-year investment plan includes spending approximately $8.5 billion from 2018 through 2022 to upgrade or add new transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability and regulatory compliance. The proposed electric delivery infrastructure projects are intended to address both continued customer growth and increases in electricity consumption. In addition, data centers continue to contribute to anticipated demand growth.

Revenue provided by electric distribution operations is based primarily on rates established by state regulatory authorities and state law. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures. Operationally, electric distribution continues to focus on improving service levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 117 minutes at the end of 2017, down from the three-year average of 123 minutes. Virginia Power’s overall customer satisfaction improved year over year when compared to 2016 J.D.

 

 

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Power and Associates’ scoring. In the future, safety, electric service reliability, outage durations and customer service will remain key focus areas for electric distribution. Modernizing the electric grid will become a key focus area to support the enhancement of the customer service experience, build upon improvements in resiliency and security and support enhanced innovation and renewable generation.

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

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

COMPETITION

Power Delivery Operating Segment— Dominion Energy and Virginia Power

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

REGULATION

Power Delivery Operating Segment—Dominion Energy and Virginia Power

Virginia Power’s electric distribution service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia and North Carolina Commissions. Virginia Power’s wholesale electric transmission rates, tariffs and terms of service are subject to regulation by FERC. Electric transmission siting authority remains the jurisdiction of the Virginia and North Carolina Commissions. However, EPACT provides FERC with certain backstop authority for transmission siting. See State Regulations and Federal Regulations in Regulation and Note 13 to the Consolidated Financial Statements for additional information.

PROPERTIES

Power Delivery Operating Segment—Dominion Energy and Virginia Power

Virginia Power has approximately 6,600 miles of electric transmission lines of 69 kV or more located in North Carolina, Virginia and West Virginia. Portions of Virginia Power’s electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.

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

    Surry-to-Skiffes Creek-to-Whealton ($325 million);
    Mt. Storm-to-Dooms ($240 million);
    Idylwood substation ($110 million);
    Dooms-to-Lexington ($130 million);
    Cunningham-to-Elmont ($110 million);
    Landstown voltage regulation ($70 million);
    Warrenton (including Remington CT-to-Warrenton, Vint Hill-to-Wheeler-to-Gainesville, and Vint Hill and Wheeler switching stations) ($110 million);
    Remington/Gordonsville/Pratts Area Improvement (including Remington-to-Gordonsville, and new Gordonsville substation transformer) ($110 million);
    Gainesville-to-Haymarket ($55 million);
    Kings Dominion-to-Fredericksburg ($50 million);
    Loudoun-Brambleton line-to-Poland Road Substation ($60 million);
    Cunningham-to-Dooms ($60 million);
    Carson-to-Rogers Road ($55 million);
    Dooms-Valley rebuild ($65 million);
    Mt. Storm-Valley rebuild ($225 million);
    Glebe-to-Station ($320 million);
    Idylwood-to-Tysons ($125 million);
    Chesterfield-to-Lakeside ($35 million); and
    Landstown-to-Thrasher ($25 million).

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

Virginia Power plans to increase transmission substation physical security and expects to invest $250 million—$300 million through 2022 to strengthen its electrical system to better protect critical equipment, enhance its spare equipment process and create multiple levels of security.

In addition, Virginia Power’s electric distribution network includes approximately 57,900 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked.

 

 

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Virginia legislation in 2014 provides for the recovery of costs, subject to approval by the Virginia Commission, for Virginia Power to move approximately 4,000 miles of electric distribution lines underground. The program is designed to reduce restoration outage time by moving Virginia Power’s most outage-prone overhead distribution lines underground, has an annual investment cap of approximately $175 million and is expected to be completed over the next decade. In August 2016, the Virginia Commission approved the first phase of the program encompassing approximately 400 miles of converted lines and $140 million in capital spending (with approximately $123 million recoverable through Rider U). In September 2017, the Virginia Commission approved recovery through Rider U of a total capital investment of $40 million for second phase conversions.

SOURCES OF ENERGY SUPPLY

Power Delivery Operating Segment—Dominion Energy and Virginia Power

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

SEASONALITY

Power Delivery Operating Segment—Dominion Energy and Virginia Power

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

Power Generation

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

Power Generation’s existing five-year investment plan includes spending approximately $8.3 billion from 2018 through 2022 to construct new generation capacity and extend the life of nuclear generation facilities to meet growing electricity demand within its service territory and maintain reliability. The most significant project currently under construction is Greensville County, which is estimated to cost approximately $1.3 billion, excluding financing costs. See Properties and Environmental Strategy for additional information on this and other utility projects.

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

Earnings for the Power Generation Operating Segment of Virginia Power primarily result from the sale of electricity generated by its utility fleet. Revenue is based primarily on rates established by state regulatory authorities and state law. Approximately 82% of revenue comes from serving Virginia jurisdictional customers. Base rates for the Virginia jurisdiction are set using a modified cost-of-service rate model, and are generally designed to allow an opportunity to recover the cost of providing utility service and earn a reasonable return on investments used to provide that service. Earnings variability may arise when revenues are impacted by factors not reflected in current rates, such as the impact of weather on customers’ demand for services. Likewise, earnings may reflect variations in the timing or nature of expenses as compared to those contemplated in current rates, such as labor and benefit costs, capacity expenses, and the timing, duration and costs of scheduled and unscheduled outages. The cost of fuel and purchased power is generally collected through fuel cost-recovery mechanisms established by regulators and does not materially impact net income. The cost of new generation facilities is generally recovered through rate adjustment clauses in Virginia. Variability in earnings from rate adjustment clauses reflects changes in the authorized ROE and the carrying amount of these facilities, which are largely driven by the timing and amount of capital investments, as well as depreciation. See Note 13 to the Consolidated Financial Statements for additional information.

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

COMPETITION

Power Generation Operating Segment—Dominion Energy and Virginia Power

 

 

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

Power Generation Operating Segment—Dominion Energy

Power Generation’s recently acquired and developed renewable generation projects are not currently subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. Competition for the nonrenewable merchant fleet is impacted by electricity and fuel prices, new market entrants, construction by others of generating assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors. These competitive factors may negatively impact the merchant fleet’s ability to profit from the sale of electricity and related products and services.

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

In November 2017, Connecticut adopted the Act Concerning Zero Carbon Solicitation and Procurement, which allows nuclear generating facilities to compete for power purchase agreements in a state sponsored procurement for electricity. In February 2018, Connecticut regulators recommended pursuing the procurement. They are expected to issue a request for proposals by May 1, 2018. Millstone will participate in the state sponsored procurement. If successful in the competitive bid process, Millstone would receive a long-term power purchase agreement for between three and ten years.

REGULATION

Power Generation Operating Segment—Dominion Energy and Virginia Power

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

PROPERTIES

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

Power Generation Operating Segment—Dominion Energy and Virginia Power

The generation capacity of Virginia Power’s electric utility fleet totals approximately 20,800 MW. The generation mix is diversified and includes gas, coal, nuclear, oil, renewables, biomass and power purchase agreements. Virginia Power’s generation facilities are located in Virginia, West Virginia and North Carolina and serve load in Virginia and northeastern North Carolina.

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

  Virginia Power plans to acquire or construct certain solar facilities in Virginia and North Carolina. See Notes 10 and 13 to the Consolidated Financial Statements for more information.
  Virginia Power continues to consider the construction of a third nuclear unit at a site located at North Anna. See Note 13 to the Consolidated Financial Statements for more information on this project.
  Virginia Power is considering the construction of a hydroelectric pumped storage facility in Southwest Virginia.
  In March 2016, the Virginia Commission authorized the construction of Greensville County and related transmission interconnection facilities. Commercial operations are expected to commence in late 2018, at an estimated cost of approximately $1.3 billion, excluding financing costs.
  In June 2017, Virginia Power signed an agreement to develop two 6 MW wind turbines off the coast of Virginia for the Coastal Virginia Offshore Wind project. The project is expected to cost approximately $300 million and to be installed by the end of 2020.
  In October 2017, Virginia Power received a permit by rule from the VDEQ to construct and operate the Hollyfield solar facility, a 17 MW solar facility in King William County, Virginia and related distribution interconnection facilities. The total estimated cost of the Hollyfield solar facility is approximately $33 million, excluding financing costs. The facility is the subject of a public-private partnership whereby the University of Virginia, an agency of the Commonwealth of Virginia and a non-jurisdictional customer, will compensate Virginia Power for the facility’s net electrical energy output.

Power Generation Operating Segment—Dominion Energy

The generation capacity of Dominion Energy’s merchant fleet totals approximately 5,100 MW. The generation mix is diversified and includes nuclear, natural gas and renewables. Merchant nonrenewable generation facilities are located in Connecticut, Pennsylvania and Rhode Island, with a majority of that capacity concentrated in New England. Dominion Energy’s merchant renewable generation facilities include a fuel cell generation facility in Connecticut, solar generation facilities in California, Connecticut, Georgia, Indiana, North Carolina, South Carolina, Tennessee, Utah and Virginia, and wind generation facilities in Indiana and West Virginia.

 

 

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SOURCES OF ENERGY SUPPLY

Power Generation Operating Segment—Dominion Energy and Virginia Power

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

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

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

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

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

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

Purchased Power—Power Generation purchases electricity from the PJM spot market and through power purchase agreements with other suppliers to provide for utility system load requirements.

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

Power Generation Operating Segment—Virginia Power

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

 

Source    2017     2016     2015  

Nuclear(1)

     32     31     30

Natural gas

     32       31       23  

Coal(2)

     17       24       26  

Purchased power, net

     14       8       15  

Other(3)

     5       6       6  

Total

     100     100     100

 

(1) Excludes ODEC’s 11.6% ownership interest in North Anna.
(2) Excludes ODEC’s 50.0% ownership interest in the Clover power station.
(3) Includes oil, hydro, biomass and solar.

SEASONALITY

Power Generation Operating Segment—Dominion Energy and Virginia Power

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

NUCLEAR DECOMMISSIONING

Power Generation Operating Segment—Dominion Energy and Virginia Power

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

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

Virginia Power believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects the long-term investment horizon, since the units will not be decommissioned for decades, and a positive long-term outlook for trust fund investment returns. Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC.

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

Under the current operating licenses, Virginia Power is scheduled to decommission the Surry and North Anna units during the period 2032 to 2078. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. Virginia Power has announced its intention to apply for operating life extensions for Surry and North Anna.

Power Generation Operating Segment—Dominion Energy

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

 

 

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As part of Dominion Energy’s acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Any funds remaining in Kewaunee’s trust after decommissioning is completed are required to be refunded to Wisconsin ratepayers. Dominion Energy believes that the amounts currently available in the decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Dominion Energy will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. The estimated cost to decommission Dominion Energy’s eight units is reflected in the table below and is primarily based upon site-specific studies completed for Surry, North Anna and Millstone in 2014 and for Kewaunee in 2013.

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

 

     

NRC

license

expiration

year

    

Most

recent

cost

estimate

(2017

dollars)(1)

    

Funds in

trusts at
December 31,
2017

    

2017

contributions

to trusts

 
(dollars in millions)                            

Surry

           

Unit 1

     2032      $ 612        $     680        $  —  

Unit 2

     2033        633        670         

North Anna

           

Unit 1(2)

     2038        524        541         

Unit 2(2)

     2040        536        508         

Total (Virginia Power)

        2,305        2,399         

Millstone

           

Unit 1(3)

     N/A        377        533         

Unit 2

     2035        575        700         

Unit 3(4)

     2045        698        688         

Kewaunee

           

Unit 1(5)

     N/A        452        773         

Total (Dominion Energy)

            $   4,407        $  5,093        $  —  

 

(1) The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on Dominion Energy’s and Virginia Power’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Dominion Energy’s and Virginia Power’s nuclear decommissioning AROs.
(2) North Anna is jointly owned by Virginia Power (88.4%) and ODEC (11.6%). However, Virginia Power is responsible for 89.26% of the decommissioning obligation. Amounts reflect 89.26% of the decommissioning cost for both of North Anna’s units.
(3) Unit 1 permanently ceased operations in 1998, before Dominion Energy’s acquisition of Millstone.
(4) Millstone Unit 3 is jointly owned by Dominion Energy Nuclear Connecticut, Inc., with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain. Decommissioning cost is shown at Dominion Energy’s ownership percentage. At December 31, 2017, the minority owners held $42 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.
(5) Permanently ceased operations in 2013.

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

Financial Statements for information about nuclear decommissioning trust investments.

Gas Infrastructure

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

The Gas Infrastructure Operating Segment of Dominion Energy includes LNG operations, Dominion Energy Questar operations, Hope’s gas distribution operations in West Virginia, and nonregulated retail natural gas marketing, as well as Dominion Energy’s investments in the Blue Racer joint venture, Atlantic Coast Pipeline and Dominion Energy Midstream. See Properties and Investments below for additional information regarding the Blue Racer and Atlantic Coast Pipeline investments. Dominion Energy’s LNG operations involve the import and storage of LNG at Cove Point and the transportation of regasified LNG to the interstate pipeline grid and mid-Atlantic and Northeast markets. Dominion Energy has received DOE and FERC approval to export LNG from Cove Point and, once the Liquefaction Project commences commercial operations, will be able to import LNG and regasify it as natural gas and liquefy natural gas and export it as LNG. See Note 22 to the Consolidated Financial Statements for more information.

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’ regulated gas distribution operations in Utah, southwestern Wyoming and southeastern Idaho includes 29,600 miles of gas distribution pipeline. 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 through 2,200 miles of gas transmission pipeline and 56 bcf of working gas storage. See Acquisitions and Dispositions above and Note 3 to the Consolidated Financial Statements for a description of the Dominion Energy Questar Combination.

In 2014, Dominion Energy formed Dominion Energy Midstream, an MLP initially consisting of a preferred equity interest in Cove Point. See General above for more information. Also see Acquisitions and Dispositions above and Note 3 to the Consolidated Financial Statements for a description of Dominion Energy’s contribution of Dominion Energy Questar Pipeline to

 

 

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Dominion Energy Midstream in December 2016 as well as Dominion Energy’s acquisition of DECG, which Dominion Energy contributed to Dominion Energy Midstream in April 2015, and Dominion Energy Midstream’s acquisition of a 25.93% noncontrolling partnership interest in Iroquois in September 2015. DECG provides FERC-regulated interstate natural gas transportation services in South Carolina and southeastern Georgia through 1,500 miles of gas transmission pipeline.

Gas Infrastructure’s existing five-year investment plan includes spending approximately $8.3 billion from 2018 through 2022 to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability. Demand for natural gas is expected to continue to grow as initiatives to transition to gas from more carbon-intensive fuels are implemented. This plan includes Dominion Energy’s portion of spending for the Atlantic Coast Pipeline Project.

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

Approximately 91% of DETI’s transmission capacity is subscribed including 86% under long-term contracts (two years or greater) and 5% on a year-to-year basis. DETI’s storage services are 100% subscribed with long-term contracts.

Revenue from processing and fractionation operations largely results from the sale of commodities at market prices. For DGP’s processing plants, Dominion Energy Gas receives the wet gas product from producers and may retain the extracted NGLs as compensation for its services. This exposes Dominion Energy Gas to commodity price risk for the value of the spread between the NGL products and natural gas. In addition, Dominion Energy Gas has volumetric risk as the majority of customers receiving these services are not required to deliver minimum quantities of gas.

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

Earnings for the Gas Infrastructure Operating Segment of Dominion Energy primarily include the results of rates established by FERC and the West Virginia, Utah, Wyoming and Idaho Commissions. Additionally, Dominion Energy receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain LNG storage and terminalling services. Dominion Energy Questar Pipeline’s and DECG’s revenues are primarily derived from reservation charges for firm transportation and storage services as provided for in their FERC-approved tariffs. Revenue provided by Questar Gas’ operations is based primarily on rates established by the Utah and Wyoming Commissions. The Idaho Commission has contracted with the

Utah Commission for rate oversight of Questar Gas operations in a small area of southeastern Idaho. Hope’s gas distribution operations in West Virginia serve residential, commercial, sale for resale and industrial gas sales, transportation and gathering service customers. Revenue provided by Hope’s operations is based primarily on rates established by the West Virginia Commission. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their capital investments. Variability in earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, which are dependent on weather, changes in commodity prices and the economy.

COMPETITION

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

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

DGP’s processing and fractionation operations face competition in obtaining natural gas supplies for its processing and related services. Numerous factors impact any given customer’s choice of processing services provider, including the location of the facilities, efficiency and reliability of operations, and the pricing arrangements offered.

In Ohio, there has been no legislation enacted to require supplier choice for natural gas distribution consumers. However, East Ohio has offered an Energy Choice program to residential and commercial customers since October 2000. East Ohio has since taken various steps approved by the Ohio Commission toward exiting the merchant function, including restructuring its commodity service and placing Energy Choice-eligible customers in a direct retail relationship with participating suppliers. Further, in April 2013, East Ohio fully exited the merchant function for its nonresidential customers, which are now required to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2017, approximately 1 million of East Ohio’s 1.2 million Ohio customers were participating in the Energy Choice program.

Gas Infrastructure Operating Segment—Dominion Energy

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

 

 

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Cove Point’s gas transportation, LNG import and storage operations, as well as the Liquefaction Project’s capacity are contracted primarily under long-term fixed reservation fee agreements. However, in the future Cove Point may compete with other independent terminal operators as well as major oil and gas companies on the basis of terminal location, services provided and price. Competition from terminal operators primarily comes from refiners and distribution companies with marketing and trading arms.

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

Dominion Energy’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy markets for natural gas. In March 2014, Dominion Energy completed the sale of its electric retail energy marketing business. In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy marketing operations. The sale is expected to be completed by the end of 2018. The remaining retail natural gas business consists of approximately 350,000 customer accounts in five states. The heaviest concentration of customers in these markets are located in states where utilities have the advantage of long-standing commitment to customer choice, primarily Ohio and Pennsylvania.

REGULATION

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

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

Gas Infrastructure Operating Segment—Dominion Energy

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

PROPERTIES AND INVESTMENTS

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

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

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

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

In September 2014, DETI announced its intent to construct and operate the Supply Header project which is estimated to cost between $550 million and $600 million to construct, excluding financing costs, and provide 1,500,000 Dths per day of firm transportation service to various customers. In December 2014, DETI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header project. In October 2017, DETI received FERC authorization to construct and operate the project facilities, with the facilities expected to be in service in late 2019.

In 2008, East Ohio began PIR, aimed at replacing approximately 4,100 miles of its pipeline system at a cost of $2.7 billion. In 2011, approval was obtained to include an additional 1,450 miles and to increase annual capital investment to meet the program goal. The program will replace approximately 25% of the pipeline system and is anticipated to take place over a total of 25 years. In March 2015, East Ohio filed an application with the Ohio Commission requesting approval to extend the PIR program for an additional five years and to increase the annual capital investment, with corresponding increases in the annual rate-increase caps. In September 2016, the Ohio Commission approved a stipulation filed jointly by East Ohio and the Staff of the Ohio Commission to settle East Ohio’s pending application. As requested, the PIR program and associated cost recovery will continue for another five-year term, calendar years 2017 through 2021, and East Ohio will be permitted to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio. Costs associated with calendar year 2016 investment will be recovered under the existing terms. 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 plan investment for 2016 of $188 million, cumulative gross plant investment of $1.2 billion and a revenue requirement of $157 million.

Gas Infrastructure Operating Segment—Dominion Energy

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

Cove Point—Dominion Energy expects the Liquefaction Project to commence commercial operations in March 2018, which will enable the Cove Point facility to liquefy domestically-produced natural gas and export it as LNG. The DOE previously authorized Dominion Energy to export LNG to countries with free trade agreements. In September 2013, the DOE authorized

 

 

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Dominion Energy to export LNG from Cove Point to non-free trade agreement countries.

In September 2014, Cove Point received the FERC order authorizing the Liquefaction Project with certain conditions. The conditions regarding the Liquefaction Project set forth in the FERC order largely incorporate the mitigation measures proposed in the environmental assessment. In October 2014, Cove Point commenced construction of the Liquefaction Project, with an in-service date anticipated in March 2018 at a total estimated cost of approximately $4.1 billion, excluding financing costs. The Cove Point facility is authorized to export at a rate of 770 million cubic feet of natural gas per day for a period of 20 years.

In April 2013, Dominion Energy announced it had fully subscribed the capacity of the project with 20-year terminal service agreements. ST Cove Point, LLC, a joint venture of Sumitomo Corporation, a Japanese corporation that is one of the world’s leading trading companies, and Tokyo Gas Co., Ltd., a Japanese corporation that is the largest natural gas utility in Japan, and GAIL Global (USA) LNG LLC, a wholly-owned indirect U.S. subsidiary of GAIL (India) Ltd., have each contracted for half of the capacity. Following completion of the front-end engineering and design work, Dominion Energy also announced it had awarded its engineering, procurement and construction contract for new liquefaction facilities to IHI/Kiewit Cove Point, a joint venture between IHI E&C International Corporation and Kiewit Energy Company.

Cove Point has historically operated as an LNG import facility under various long-term import contracts. Since 2010, Dominion Energy has renegotiated certain existing LNG import contracts in a manner that will result in a significant reduction in pipeline and storage capacity utilization and associated anticipated revenues during the period from 2017 through 2028. Such amendments created the opportunity for Dominion Energy to explore the Liquefaction Project, which, will extend the economic life of Cove Point and contribute to Dominion Energy’s overall growth plan. In total, these renegotiations reduced Cove Point’s expected annual revenues from the import-related contracts by approximately $150 million from 2017 through 2028, partially offset by approximately $50 million of additional revenues in the years 2013 through 2017.

In June 2015, Cove Point executed binding agreements with two customers for the approximately $150 million Eastern Market Access Project. In January 2018, Cove Point received FERC authorization to construct and operate the project facilities, which are expected to be placed into service in early 2019.

DECG—In 2014, DECG executed binding precedent agreements with three customers for the Charleston project. The project is expected to cost approximately $125 million, and provide 80,000 Dths per day of firm transportation service from an existing interconnect with Transcontinental Gas Pipe, LLC in Spartanburg County, South Carolina to customers in Dillon, Marlboro, Sumter, Charleston, Lexington and Remington counties, South Carolina. In February 2017, DECG received FERC approval to construct and operate the project facilities, which are expected to be placed into service in March 2018.

Questar Gas—In 2010, Questar Gas began replacing aging high pressure infrastructure under a cost-tracking mechanism that allows it to place into rate base and earn a return on capital expenditures associated with a multi-year natural gas

infrastructure-replacement program upon the completion of each project. At that time, the commission-allowed annual spending in the replacement program was approximately $55 million.

In its 2014 Utah general rate case, Questar Gas received approval to include intermediate high pressure infrastructure in the replacement program and increase the annual spending limit to approximately $65 million, adjusted annually using a gross domestic product inflation factor. At that time, 420 miles of high pressure pipe and 70 miles of intermediate high pressure pipe were identified to be replaced in the program over a 17-year period. Questar Gas has spent about $65 million each year through 2017 under this program. The program is evaluated in each Utah general rate case. The next Utah general rate case is anticipated to occur in 2019.

Gas Infrastructure Equity Method Investments—In September 2015, Dominion Energy, through Dominion Energy Midstream, acquired an additional 25.93% interest in Iroquois. Dominion Energy Gas holds a 24.07% interest with TransCanada holding a 50% interest. Iroquois owns and operates a 416-mile FERC regulated interstate natural gas pipeline providing service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end-users, through interconnecting pipelines and exchanges. Iroquois’ pipeline extends from the U.S.-Canadian border at Waddington, New York through the state of Connecticut to South Commack, Long Island, New York and continuing on from Northport, Long Island, New York through the Long Island Sound to Hunts Point, Bronx, New York. See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Iroquois.

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. 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, with development and construction costs estimated between $6.0 billion and $6.5 billion, excluding financing costs. In October 2014, Atlantic Coast Pipeline requested approval from FERC to utilize the pre-filing process under which environmental review for the natural gas pipeline project will commence. Atlantic Coast Pipeline filed its FERC application in September 2015 and expects to be in service in late 2019. In October 2017, Atlantic Coast Pipeline received the FERC order authorizing the construction and operation of the project. The FERC order has been appealed to the U.S. Court of Appeals for the Fourth Circuit and the project remains subject to other pending federal and state approvals. See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Atlantic Coast Pipeline.

In December 2012, Dominion Energy formed Blue Racer with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions

 

 

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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. Midstream services offered by Blue Racer include gathering, processing, fractionation, and natural gas liquids transportation and marketing. Blue Racer is expected to develop additional new capacity designed to meet producer needs as the development of the Utica Shale formation increases. See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Blue Racer.

SOURCES OF ENERGY SUPPLY

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

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

Dominion Energy’s and Dominion Energy Gas’ underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Northeast, mid-Atlantic, Midwest and Rocky Mountain regions. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transmission capacity.

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

SEASONALITY

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

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

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

Corporate and Other

Corporate and Other Segment-Virginia Power and Dominion Energy Gas

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

Corporate and Other Segment-Dominion Energy

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

REGULATION

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

State Regulations

ELECTRIC

Virginia Power’s electric utility retail service is subject to regulation by the Virginia Commission and the North Carolina Commission.

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

Electric Regulation in Virginia

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

The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, 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.

 

 

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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 2017, the Virginia Commission approved an ROE of 9.2% for rate adjustment clauses.

In February 2017, the Governor of Virginia signed legislation into law that allows utilities to file a rate adjustment clause to recover costs of pumped hydroelectricity generation and storage facilities that are located in the coalfield region of Virginia. In March 2017, the Governor of Virginia signed legislation into law that allows utilities to file a rate adjustment clause to recover, beginning in 2020, reasonably appropriate costs for extending the operating licenses, or the operating lives, of nuclear power generation facilities.

In March 2017, the Governor of Virginia signed legislation into law stating that it is in the public interest for utilities to replace existing overhead tap lines having nine or more total unplanned outage events-per-mile with new underground facilities, and that utilities can seek cost recovery for such new underground facilities through a rate adjustment clause.

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

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

Electric Regulation in North Carolina

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

Virginia Power’s transmission service rates in North Carolina are regulated by the North Carolina Commission as part of Virginia Power’s bundled retail service to North Carolina customers.

See Note 13 to the Consolidated Financial Statements for additional information, which is incorporated herein by reference.

GAS

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

Gas Regulation in Utah, Wyoming and Idaho

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

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

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

Gas Regulation in Ohio

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

 

 

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

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

Gas Regulation in West Virginia

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

In addition to general rate increases, Hope makes routine separate filings with the West Virginia Commission to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover a prospective twelve-month period. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

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

Status of Competitive Retail Gas Services

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

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

program and places Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which is designated on the customers’ bills.

In January 2013, the Ohio Commission granted East Ohio’s motion to fully exit the merchant function for its nonresidential customers, beginning in April 2013, which requires those customers to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2017, approximately 1.0 million of Dominion Energy Gas’ 1.2 million Ohio customers were participating in the Energy Choice program. Subject to the Ohio Commission’s approval, East Ohio may eventually exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. East Ohio continues to be the provider of last resort in the event of default by a supplier. Large industrial customers in Ohio also source their own natural gas supplies.

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

Federal Regulations

FEDERAL ENERGY REGULATORY COMMISSION

Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and 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. 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.

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

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

 

 

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

Dominion Energy and Virginia Power plan and operate their facilities in compliance with approved NERC reliability requirements. Dominion Energy and Virginia Power employees participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. Dominion Energy and Virginia Power anticipate incurring additional compliance expenditures over the next several years as a result of the implementation of new cybersecurity programs. In addition, NERC has redefined critical assets which expanded the number of assets subject to NERC reliability standards, including cybersecurity assets. NERC continues to develop additional requirements specifically regarding supply chain standards and control centers that impact the bulk electric system. While Dominion Energy and Virginia Power expect to incur additional compliance costs in connection with NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.

In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE 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.

Gas

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

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

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

Dominion Energy Gas also make certain informational postings available on Dominion Energy’s website.

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

Safety Regulations

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

The Companies are subject to a number of federal and state laws and regulations, including Occupational Safety and Health Administration, and comparable state statutes, whose purpose is to protect the health and safety of workers. The Companies have an internal safety, health and security program designed to monitor and enforce compliance with worker safety requirements, which is routinely reviewed and considered for improvement. The Companies believe that they are in material compliance with all applicable laws and regulations related to worker health and safety. Notwithstanding these preventive measures, incidents may occur that are outside of the Companies’ control.

Environmental Regulations

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

AIR

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

 

 

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hydrogen chloride, NOX, SO2, and particulate matter. At a minimum, delegated states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies’ facilities are subject to the CAA’s permitting and other requirements.

GLOBAL CLIMATE CHANGE

The national and international attention to GHG emissions and their relationship to climate change has resulted in federal, regional and state legislative and regulatory action in this area. See, for example, the discussion of the Clean Power Plan and the United Nation’s Paris Agreement in Environmental Matters in Future Issues and Other Matters in Item 7. MD&A.

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

WATER

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

WASTE AND CHEMICAL MANAGEMENT

Dominion Energy is subject to various federal and state laws and implementing regulations governing the management, storage, treatment, reuse and disposal of waste materials and hazardous substances, including the Resources Conservation and Recovery Act of 1976, CERCLA, the Emergency Planning and Community Right-to-Know Act of 1986 and the Toxic Substance Control Act of 1976. Dominion Energy’s operations and construction activities, including activities associated with oil and gas pro-

duction and gas storage wells, generate waste. Across Dominion Energy, completion water is disposed at commercial disposal facilities. Produced water is either hauled for disposal, evaporated or injected into company and third-party owned underground injection wells. Wells drilled in tight-gas-sand and shale reservoirs require hydraulic-fracture stimulation to achieve economic production rates and recoverable reserves. The majority of Wexpro’s current and future production and reserve potential is derived from reservoirs that require hydraulic-fracture stimulation to be commercially viable. Currently, all well construction activities, including hydraulic-fracture stimulation and management and disposal of hydraulic fracturing fluids, are regulated by federal and state agencies that review and approve all aspects of gas- and oil-well design and operation.

PROTECTED SPECIES

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

OTHER REGULATIONS

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

Nuclear Regulatory Commission

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

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

The NRC also requires Dominion Energy and Virginia Power to decontaminate their nuclear facilities once operations cease.

 

 

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This process is referred to as decommissioning, and Dominion Energy and Virginia Power are required by the NRC to be financially prepared. For information on decommissioning trusts, see Power Generation-Nuclear Decommissioning above and Note 9 to the Consolidated Financial Statements. See Note 22 to the Consolidated Financial Statements for information on spent nuclear fuel.

 

 

ENVIRONMENTAL STRATEGY

As part of the Companies’ overall long term strategic planning overseen by the Board of Directors, we have a well formed environmental strategy. The Companies are committed to continuing to be an industry leader, delivering safe, reliable, clean and affordable energy while fully complying with all applicable environmental laws and regulations. Additionally, we seek to build partnerships and engage with local communities, stakeholders and customers on environmental issues important to them. The Companies are dedicated to meeting their customers’ growing energy needs with innovative, sustainable solutions. It is the Companies’ belief that sustainable solutions should strive to balance the interdependent goals of environmental stewardship and economic effects. The integrated strategy to meet these objectives consists of three major elements:

  Reduction of GHG emissions;
  Energy infrastructure modernization, including natural gas and electric operations; and
  Conservation and energy efficiency.

Reduction of GHG Emissions

The Companies integrated strategy has resulted in a reduction in GHG emission intensity. Over the past two decades, the Companies have made changes to the generation mix and to natural gas operations which have significantly improved environmental performance. For example, Power Generation has significantly reduced both its carbon emissions and its carbon intensity while generating electricity with an increasingly clean portfolio. From 2000 through 2016, our carbon intensity decreased by 43%. This strategy has also resulted in significant reductions of other air pollutants such as NOX, SO2 and mercury and also reduced the amount of coal ash generated and the amount of water withdrawn. The principal components of the strategy, which include initiatives that address electric energy production and delivery, natural gas storage, transmission and delivery and energy management, are as follows:

  Expand Dominion Energy’s and Virginia Power’s renewable energy portfolio, including solar, wind power, and biomass, to further diversify Dominion Energy’s and Virginia Power’s fleet, meet state renewable energy targets and lower the carbon footprint;
  Pursue the extension of operating licenses of existing nuclear units which provide carbon-free generation;
  Evaluate effective battery solutions, such as hydroelectric pumped storage, which help support a grid with increased renewables;
  Enhance conservation and energy efficiency programs on both the electric and gas side of our businesses to help customers use energy wisely and reduce environmental impacts;
  Sell, close, place in cold reserve or convert to cleaner fuels a number of coal-fired generation units owned by Dominion Energy and Virginia Power;
  Evaluate behind-the-meter and rate design solutions and other business opportunities;
  Construct new electric and gas transmission infrastructure to modernize the grid, to expand availability of cleaner fuel, to reduce emissions, to promote energy and economic security and help deliver more green energy to population centers where it is needed most;
  Replace older distribution pipeline mains and services; and
  Implement and enhance voluntary methane mitigation measures through participation in the EPA’s Natural Gas Star and Methane Challenge programs; and continue to evaluate business opportunities presented by a lower carbon economy and innovative technologies.

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

CLEANER GENERATION

Renewable energy is an important component of a diverse and reliable energy mix that helps to mitigate the environmental aspects of energy production. Nationally, Dominion Energy has nearly 2,400 MW of renewable generating capacity in operation or under development in nine states, including offtake agreements for Virginia Power’s utility customers. Both Virginia and North Carolina have passed legislation setting targets for renewable power. Dominion Energy is committed to meeting Virginia’s goals of 12% of base year electric energy sales from renewable power sources by 2022, and 15% by 2025, and North Carolina’s Renewable Portfolio Standard of 12.5% by 2021 and continues to add utility-scale solar capacity. Backed by a $1 billion investment, Dominion Energy has grown its solar fleet in Virginia and North Carolina over the past two years from near zero to about 1,350 megawatts in service, in construction or under development.

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

GHG EMISSIONS

Since 2000, Dominion Energy and Virginia Power have tracked the emissions of their electric generation fleet, which employs a mix of fuel and renewable energy sources. Comparing annual year 2016 to annual year 2000, the entire electric generating fleet (based on ownership percentage) reduced its average CO2 emissions rate per MWh of energy produced from electric generation by approximately 43%. Comparing annual year 2016 to annual year 2000, the regulated electric generating fleet (based on ownership percentage) reduced its average CO 2 emissions rate per MWh of energy produced from electric generation by approximately 26%.

Dominion Energy also develops a comprehensive GHG inventory annually. For Power Generation, Dominion Energy and Virginia Power’s direct CO 2 equivalent emissions, based on ownership percentage, were 37.2 million metric tons and 33.1 million metric tons, respectively, in 2016, compared to 34.3 million metric tons and 30.9 million metric tons, respectively, in 2015. The corresponding carbon intensity rates for Dominion Energy were 0.339 metric tons CO2 equivalent

 

 

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emissions per net MWh in 2016 and 0.348 metric tons CO2 equivalent emissions per net MWh in 2015.

For Power Delivery’s regulated electric transmission and distribution operations, direct CO 2 equivalent emissions for 2016 were 42,856 metric tons, compared to 53,819 metric tons in 2015.

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

Hope and East Ohio direct CO2 equivalent emissions together decreased from 0.90 million metric tons in 2015 to 0.86 million metric tons in 2016. DETI’s and Cove Point’s direct CO2 equivalent emissions together were 1.3 million metric tons in 2016, increasing from 1.1 million metric tons in 2015 attributable to new EPA reporting of transmission pipeline blowdowns.

The Companies’ GHG inventory follows all methodologies specified in the EPA Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98 for calculating emissions. Total CO2 equivalent emissions reported for our natural gas assets, as estimated in Dominion Energy’s corporate inventory, were 2.3 million metric tons in 2016. This estimate includes emissions reported under the GHG Reporting Program, as well as other emissions not required to be reported under the federal program. The 2016 corporate GHG inventory emission estimate includes Dominion Energy Questar Pipeline, Questar Gas and Wexpro for the entire calendar year.

Energy Infrastructure Modernization

Dominion Energy’s existing five-year investment plan includes significant capital expenditures to upgrade or add new electric transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory, maintain reliability, implement a strategic underground program to minimize outage duration and address environmental requirements. These enhancements are primarily aimed at meeting Dominion Energy’s continued goal of providing reliable service, and are intended to address both continued population growth and increases in electricity consumption. An additional benefit will be added capacity to efficiently deliver electricity from the renewable projects now being developed, or to be developed in the future, to meet our customers’ preference for cleaner energy. See Operating Segments for additional information.

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

for additional information, including natural gas infrastructure projects.

Conservation and Energy Efficiency

Conservation and load management play a significant role in meeting the growing demand for electricity and natural gas, while also helping to reduce the environmental footprint of our customers.

The Regulation Act provides incentives for energy conservation through the implementation of conservation programs. Additional legislation in 2009 added definitions of peak-shaving and energy efficiency programs, and allowed for a margin on operating expenses and recovery of revenue reductions related to energy efficiency programs.

Virginia Power’s DSM programs, implemented with Virginia Commission and North Carolina Commission approval, provide important incremental steps in assisting customers to reduce energy consumption through programs that include energy audits and incentives for customers to upgrade or install certain energy efficient measures and/or systems. The DSM programs began in Virginia in 2010 and in North Carolina in 2011. Currently, there are residential and non-residential DSM programs active in the two states. Virginia Power continues to evaluate opportunities to redesign current DSM programs and develop new DSM initiatives in Virginia and North Carolina.

Virginia Power continues to upgrade meters throughout Virginia to AMI, also referred to as smart meters. The AMI meter upgrades are part of an ongoing demonstration effort to help Virginia Power further evaluate the effectiveness of AMI meters to monitor voltage stability, remotely turn off and on electric service, increase detection and reporting capabilities with respect to power outages and restorations, obtain remote daily meter readings and offer dynamic rates.

East Ohio offers two DSM programs, approved by the Ohio Commission, designed to help customers reduce their energy consumption. One program provides weatherization assistance to help income-eligible customers reduce their energy usage. Another program has been designed to help East Ohio’s residential customers improve their homes’ energy efficiency, starting with a home energy assessment. Following the assessment, customers receive a report with recommendations on how to save energy and improve their home’s comfort. This program includes rebates and free installation of several energy-efficient products such as, high-efficiency showerheads, kitchen and bathroom faucet aerators, programmable thermostat or carbon monoxide detector and water heater pipe wrap.

Questar Gas offers an energy-efficiency program, approved by the Utah and Wyoming Commissions, designed to help customers reduce their energy consumption. This program promotes the use of energy-efficient appliances and practices to reduce natural gas usage. The program provides home energy planning, which provides homeowners with a step-by-step roadmap to efficiency improvements to reduce gas usage. In addition to the recommendations, the program provides home owners with energy-saving devices such as pipe insulation and low-flow shower heads as well as rebates on appliances and weatherization items. The program also offers new construction builders with rebates for installing high-efficiency equipment and offers commercial businesses with rebates on energy efficient equipment and retrofits.

 

 

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CYBERSECURITY

In an effort to reduce the likelihood and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In addition, the Companies are subject to mandatory cybersecurity regulatory requirements, interface regularly with a wide range of external organizations, and participate in classified briefings to maintain an awareness of current cybersecurity threats and vulnerabilities. The Companies’ current security posture and regulatory compliance efforts are intended to address the evolving and changing cyber threats. See Item 1A. Risk Factors for additional information.

 

 

Item 1A. Risk Factors

The Companies’ businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond their control. A number of these factors have been identified below. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in Item 7. MD&A.

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

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

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

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

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

Legislation signed by the Virginia Governor in February 2015 suspends biennial reviews for the five successive 12-month test periods beginning January 1, 2015 and ending December 31, 2019, and no changes will be made to Virginia Power’s existing base rates until at least December 1, 2022. During this period, Virginia Power bears the risk of any severe weather events and natural disasters, the risk of asset impairments related to the early retirement of any generation facilities due to the implementation of environmental regulations, as well as an increase in general operating and financing costs, and Virginia Power may not recover its associated costs through increases to base rates. If Virginia Power incurs any such significant additional expenses during this period, Virginia Power may not be able to recover its costs and/or earn a reasonable return on capital investment, which could negatively affect Virginia Power’s future earnings.

Virginia Power’s retail electric base rates for bundled generation, transmission, and distribution services to customers in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes, and the rules and procedures of the North Carolina Commission. If retail electric earnings exceed the returns established by the North Carolina Commission, retail electric rates may be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery through

 

 

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base rates, on a timely basis, of costs incurred in providing service, Virginia Power’s future earnings could be negatively impacted.

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

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

The 2017 Tax Reform Act could have a material impact on our operations, cash flows, and financial results. Reductions in the estimated annual cost-of-service effect (commonly referred to as the gross-up factor) due to the reduction in the corporate income tax rates to 21% under the provisions of the 2017 Tax Reform Act could result in amounts currently collected from utility customers to be refundable to such customers, generally through reductions in rates. In addition, the Companies’ regulators may require the reduction in accumulated deferred income tax balances under the provisions of the 2017 Tax Reform Act to be shared with customers, generally through reductions in future rates. 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 our federal and state regulators.

The 2017 Tax Reform Act could have a material impact on Dominion Energy and Dominion Energy Gas’ FERC-regulated gas operations including rates charged to customers. In light of the reduction in the income tax rate in the 2017 Tax Reform Act, our FERC-regulated gas subsidiaries are subject to an increased risk of FERC initiating industry-wide proceedings under Section 5 of the Natural Gas Act to have interstate pipelines substantiate rates charged for transportation and storage of natural gas in interstate commerce, when viewed holistically, are “just and reasonable” taking into account the effects of tax reform and all other drivers. It is unclear if FERC will mandate a one-time rate reset or Section 5 rate case for Dominion Energy and Dominion

Energy Gas’ regulated subsidiaries; however, states as well as customers have petitioned FERC to request changes in rates as a result of tax reform.

The interpretation of provisions of the 2017 Tax Reform Act that take effect in 2018 may significantly impact our operations. The 2017 Tax Reform Act contains provisions that limit the deductibility of interest expense. The new provision generally limits the interest deduction on business interest to (1) business interest income, plus (2) 30 percent of the taxpayer’s adjusted taxable income. Business interest and business interest income is defined as that allocable to a trade or business and not investment interest and income. Regulated public utilities are not subject to this interest limitation; however Dominion Energy is a consolidated group with both regulated and merchant lines of businesses. The U.S. Department of Treasury has been tasked with providing guidance on applying the interest limitation to consolidated groups, such as Dominion Energy, but it is unclear when that guidance may be issued, or whether that guidance could result in a disallowance of a portion of our interest deductions in the future.

Dominion Energy and Virginia Power’s generation business may be negatively affected by possible FERC actions that could change market design in the wholesale markets or affect pricing rules or revenue calculations in the RTO markets. Dominion Energy and Virginia Power’s generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize RTOs to make changes in market design. FERC also periodically reviews Dominion Energy’s authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets or its interpretation of market rules, Dominion Energy or Virginia Power’s authority to sell power at market-based rates, or changes to pricing rules or rules involving revenue calculations, could adversely impact the future results of Dominion Energy or Virginia Power’s generation business. For example, in July 2015, FERC approved changes to PJM’s Reliability Pricing Model capacity market establishing a new Capacity Performance Resource product. This product offers the potential for higher capacity prices but can also impose significant economic penalties on generator owners such as Virginia Power for failure to perform during periods when electricity is in high demand. In addition, there have been changes to the interpretation and application of FERC’s market manipulation rules. A failure to comply with these rules could lead to civil and criminal penalties.

The Companies’ infrastructure build and expansion plans often require regulatory approval before construction can commence. The Companies may not complete facility construction, pipeline, conversion or other infrastructure projects that they commence, or they may complete projects on materially different terms or timing than initially anticipated, and they may not be able to achieve the intended benefits of any such project, if completed. Several facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects have been announced and additional projects

 

 

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may be considered in the future. The Companies compete for projects with companies of varying size and financial capabilities, including some that may have competitive advantages. Commencing construction on announced and future projects may require approvals from applicable state and federal agencies, and such approvals could include mitigation costs which may be material to the Companies. Projects may not be able to be completed on time as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a decline in the credit strength of counterparties or vendors, or other factors beyond the Companies’ control. Even if facility construction, pipeline, expansion, electric transmission line, conversion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of the Companies following completion of the projects may not meet expectations. Start-up and operational issues can arise in connection with the commencement of commercial operations at our facilities, including but not limited to commencement of commercial operations at our power generation facilities following expansions and the Liquefaction Project. Such issues may include failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, the Companies may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies’ ability to realize the anticipated benefits from the facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects.

The development, construction and commissioning of several large-scale infrastructure projects simultaneously involves significant execution risk. The Companies are currently simultaneously developing, constructing or commissioning several major projects, including the Liquefaction Project, the Atlantic Coast Pipeline Project, the Supply Header project, Greensville County and multiple DETI projects, which together help contribute to the over $25 billion in capital expenditures planned by the Companies through 2022. Several of the Companies’ key projects are increasingly large-scale, complex and being constructed in constrained geographic areas or in difficult terrain, for example, the Atlantic Coast Pipeline Project. The advancement of the Companies’ ventures is also affected by the interventions, litigation or other activities of stakeholder and advocacy groups, some of which oppose natural gas-related and energy infrastructure projects. For example, certain landowners and stakeholder groups oppose the Atlantic Coast Pipeline Project, which could impede construction activities or the acquisition of rights-of-way and other land rights on a timely basis or on acceptable terms. Given that these projects provide the foundation for the Companies’ strategic growth plan, if the Companies are unable to obtain or maintain the required approvals, develop the necessary technical expertise, allocate and coordinate sufficient resources, adhere to budgets and timelines, effectively handle public outreach efforts, or otherwise fail to successfully execute the projects, there could be an adverse impact to the Companies’

financial position, results of operations and cash flows. For example, while Dominion Energy has received the required approvals to commence construction of the Liquefaction Project from the DOE, all DOE export licenses are subject to review and possible withdrawal should the DOE conclude that such export authorization is no longer in the public interest. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect the Companies’ ability to execute their business plan.

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

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

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

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

 

 

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

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

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

Virginia Power is subject to risks associated with the disposal and storage of coal ash. Virginia Power historically produced and continues to produce coal ash, or CCRs, as a by-product of its coal-fired generation operations. The ash is stored and managed in impoundments (ash ponds) and landfills located at eight different facilities.

Virginia Power is facing litigation regarding alleged CWA violations at Chesapeake power station, and may face litigation concerning its coal ash facilities at other stations. Depending on the final outcome of any such litigation, Virginia Power could incur expenses and other costs, including costs associated with

closing, corrective action and ongoing monitoring of certain ash ponds. In addition, the EPA has issued regulations concerning the management and storage of CCRs, which Virginia has adopted. These CCR regulations require Virginia Power to make additional capital expenditures and increase its operating and maintenance expenses.

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

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

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

In addition, there are many risks associated with the Companies’ operations and the transportation, storage and processing of natural gas and NGLs, including nuclear accidents, fires, explosions, uncontrolled release of natural gas and other environmental hazards, pole strikes, electric contact cases, the collision of third party equipment with pipelines and avian and other wildlife impacts. Such incidents could result in loss of human life or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or business interruptions and associated public or

 

 

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employee safety impacts, loss of revenues, increased liabilities, heightened regulatory scrutiny and reputational risk. Further, the location of pipelines and storage facilities, or generation, transmission, substations and distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.

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

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

Sustained declines in natural gas and NGL prices have resulted in, and could result in further, curtailments of third-party producers’ drilling programs, delaying the production of volumes of natural gas and NGLs that Dominion Energy and Dominion Energy Gas gather, process, and transport and reducing the value of NGLs retained by Dominion Energy Gas, which may adversely affect Dominion Energy and Dominion Energy Gas’ revenues and earnings. Dominion Energy and Dominion Energy Gas obtain their supply of natural gas and NGLs from numerous third-party producers. Most producers are under no obligation to deliver a specific quantity of natural gas or

NGLs to Dominion Energy’s and Dominion Energy Gas’ facilities. A number of other factors could reduce the volumes of natural gas and NGLs available to Dominion Energy’s and Dominion Energy Gas’ pipelines and other assets. Increased regulation of energy extraction activities could result in reductions in drilling for new natural gas wells, which could decrease the volumes of natural gas supplied to Dominion Energy and Dominion Energy Gas. Producers with direct commodity price exposure face liquidity constraints, which could present a credit risk to Dominion Energy and Dominion Energy Gas. Producers could shift their production activities to regions outside Dominion Energy’s and Dominion Energy Gas’ footprint. In addition, the extent of natural gas reserves and the rate of production from such reserves may be less than anticipated. If producers were to decrease the supply of natural gas or NGLs to Dominion Energy’s and Dominion Energy Gas’ systems and facilities for any reason, Dominion Energy and Dominion Energy Gas could experience lower revenues to the extent they are unable to replace the lost volumes on similar terms. In addition, Dominion Energy Gas’ revenue from processing and fractionation operations largely results from the sale of commodities at market prices. Dominion Energy Gas receives the wet gas product from producers and may retain the extracted NGLs as compensation for its services. This exposes Dominion Energy Gas to commodity price risk for the value of the spread between the NGL products and natural gas, and relative changes in these prices could adversely impact Dominion Energy Gas’ results.

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

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

Dominion Energy purchases fuel under a variety of terms, including long-term and short-term contracts and spot market purchases. Dominion Energy is exposed to fuel cost volatility for the portion of its fuel obtained through short-term contracts or on the spot market, including as a result of market supply shortages. Fuel prices can be volatile and the price that can be obtained for power produced from such fuel may not change at the same rate as fuel costs, thus adversely impacting Dominion Energy’s financial results.

 

 

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In addition, in the event that any of the merchant generation facilities experience a forced outage, Dominion Energy may not receive the level of revenue it anticipated.

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

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

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

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

Certain of Dominion Energy and Dominion Energy Gas’ gas pipeline services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if the cost to perform such services exceeds the revenues received from such contracts. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated, cost-based recourse rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being

used to perform the services. Any shortfall of revenue as a result of these “negotiated rate” contracts could decrease Dominion Energy and Dominion Energy Gas’ earnings and cash flows.

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

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

Market performance and other changes may decrease the value of Dominion Energys and Virginia Powers decommissioning trust funds and Dominion Energys and Dominion Energy Gas benefit plan assets or increase Dominion Energys and Dominion Energy Gas liabilities, which could then require significant additional funding. The performance of the capital markets affects the value of the assets that are held in trusts to satisfy future obligations to decommission Dominion Energy’s and Virginia Power’s nuclear plants and under Dominion Energy’s and Dominion Energy Gas’ pension and other postretirement benefit plans. The Companies have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates.

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

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

 

 

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

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

The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The Dodd-Frank Act includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, can choose to exempt their hedging transactions from these clearing and exchange trading requirements. Final rules for the over-the-counter derivative-related provisions of the Dodd-Frank Act will continue to be established through the ongoing rulemaking process of the applicable regulators, including rules regarding margin requirements for non-cleared swaps. If, as a result of changes to the rulemaking process, the Companies’ derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs, including from higher margin requirements, for their derivative activities. In addition, changes to or the elimination of rulemaking that implements Title VII of the Dodd-Frank Act by the Companies’ counterparties could result in increased costs related to the Companies’ derivative activities.

Changing rating agency requirements could negatively affect the Companies’ growth and business strategy. In order to maintain appropriate credit ratings to obtain needed credit at a reasonable cost in light of existing or future rating agency requirements, the Companies may find it necessary to take steps or change their business plans in ways that may adversely affect their growth and earnings. A reduction in the Companies’ credit ratings could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require the Companies to post additional collateral in connection with some of its price risk management activities.

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

the failure of financial institutions on which the Companies rely. Increased costs and restrictions on the Companies’ ability to access financial markets may be severe enough to affect their ability to execute their business plans as scheduled.

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

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

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

A successful cyber attack on the systems that control the Companies’ electric generation, electric or gas transmission or distribution assets could severely disrupt business operations, preventing the Companies from serving customers or collecting revenues. The breach of certain business systems could affect the Companies’ ability to correctly record, process and report finan-

 

 

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cial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to the Companies’ reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. The Companies maintain property and casualty insurance that may cover certain damage caused by potential cyber incidents; however, other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could materially and adversely affect the Companies’ business, financial condition and results of operations.

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

The completion of the merger with SCANA is subject to the receipt of consents, approvals and/or findings from governmental entities, which may impose conditions that could have an adverse effect on Dominion Energy or SCANA or could cause either Dominion Energy or SCANA to abandon the merger. The completion of the merger is also subject to there not having been substantive changes in certain South Carolina laws that have or would reasonably be expected to have an adverse effect on SCANA or its subsidiaries or orders of governmental entities or changes in law that impose any condition that would reasonably be expected to result in specified changes to the South Carolina Commission petition. Dominion Energy and SCANA are not required to complete the merger until after the applicable waiting period under the Hart-Scott-Rodino Act expires or terminates and the requisite authorizations, approvals, consents and/or permits are received from the FERC, NRC, South Carolina Commission, North Carolina Commission and Georgia Public Service Commission. Any of the relevant governmental entities may oppose the merger, fail to approve the

merger, fail to make required findings in favor of the merger, or impose certain requirements or obligations as conditions for their consent, approval or findings or in connection with their review. Regulatory approvals of the merger or findings with respect to the merger may not be obtained on a timely basis or at all, and such approvals or findings may include conditions that could have an adverse effect on Dominion Energy and/or SCANA, or result in the abandonment of the merger. Dominion Energy cannot provide any assurance that Dominion Energy and SCANA will obtain the necessary approvals or findings or that any required conditions will not have an adverse effect on Dominion Energy following the merger.

Subject to the terms and conditions set forth in the merger agreement, the merger agreement may require Dominion Energy to accept conditions from regulators that could adversely impact Dominion Energy after the merger without either of Dominion Energy or SCANA having the right to refuse to close the merger on the basis of those regulatory conditions, except that Dominion Energy is generally not required, and SCANA is generally not permitted without Dominion Energy’s prior approval, to take any action or accept any condition that results in a burdensome condition for Dominion Energy or SCANA as more fully described in the SCANA Merger Agreement.

In addition, the SCANA Merger Agreement provides that Dominion Energy (but not SCANA) will have the right to refuse to complete the merger if, since the date of the SCANA Merger Agreement, any governmental entity shall have enacted any order, or there shall have been any change in law (including the Base Load Review Act and the other laws governing South Carolina public utilities), which imposes any material change to the terms, conditions or undertakings set forth in the South Carolina Commission petition, or any significant changes to the economic value of the proposed terms set forth in the South Carolina Commission petition, in each case as determined by Dominion Energy in good faith.

The SCANA Merger Agreement further 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 SCANA or any of its subsidiaries. There is currently pending before the South Carolina Senate a bill that would make substantive changes to the Base Load Review Act. This bill has passed the South Carolina House of Representatives. If this bill becomes law, Dominion Energy would not be obligated to complete the merger if it is determined that the bill has or would reasonably be expected to have an adverse effect on SCANA or any of its subsidiaries.

Certain lawsuits and regulatory actions have been filed against SCANA and SCE&G in connection with the abandonment of the V.C. Summer Units 2 and 3 new nuclear development project. If the relief requested in these matters (including a request for declaratory judgment that the Base Load Review Act is unconstitutional) is granted, Dominion Energy might not be obligated to complete the merger.

Dominion Energy and SCANA can provide no assurance that these risks will not materialize and either adversely impact Dominion Energy after the completion of the merger or, if such conditions rise to the thresholds discussed above, some of which,

 

 

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as described above, are in the subjective determination of Dominion Energy acting in good faith, or if the required authorizations, approvals, consents and/or permits are not obtained or received, result in the abandonment of the merger.

Dominion Energy expects to incur substantial expenses related to the merger with SCANA. Dominion Energy expects to incur relatively significant expenses in connection with completing the merger. While Dominion Energy has assumed that a certain level of transaction and integration expenses would be incurred, there are a number of factors beyond its control that could affect the total amount or the timing of its integration expenses. Many of the expenses that will be incurred, by their nature, are difficult to estimate accurately at the present time.

Following the merger with SCANA, Dominion Energy may be unable to successfully integrate SCANA’s businesses. Dominion Energy and SCANA currently operate as independent public companies. After the merger, Dominion Energy will be required to devote significant management attention and resources to integrating SCANA’s business. Potential difficulties Dominion Energy may encounter in the integration process include the following:

  The complexities associated with integrating SCANA and its utility businesses, while at the same time continuing to provide consistent, high quality services;
  The complexities of integrating a company with different core services, markets and customers;
  The inability to attract and retain key employees;
  Potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the merger;
  Difficulties in managing political and regulatory conditions related to SCANA’s utility businesses after the merger;
  The cost recovery plan includes a moratorium on filing requests for adjustments in SCE&G’s base electric rates until 2021 if the merger is approved by the South Carolina Commission, which would limit Dominion Energy’s ability to recover increases in non-fuel related costs of electric operations for SCE&G’s customers; and
  Performance shortfalls as a result of the diversion of Dominion Energy management’s attention caused by completing the merger and integrating SCANA’s utility businesses.

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

Dominion Energy and SCANA may be materially adversely affected by negative publicity related to the merger and in connection with other related matters, including the abandonment of the V.C. Summer Units 2 and 3 new nuclear development project. From time to time, political and public sentiment in connection with the merger and in connection with other matters, including the abandonment of the V.C. Summer Units 2 and 3 new nuclear development project may result in a significant

amount of adverse press coverage and other adverse public statements affecting Dominion Energy and SCANA. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims. Responding to these investigations and lawsuits, regardless of the ultimate outcome of the proceedings, as well as responding to and addressing adverse press coverage and other adverse public statements, can divert the time and effort of senior management from the management of Dominion Energy’s and SCANA’s respective businesses.

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

The market value of Dominion Energy common stock could decline if large amounts of its common stock are sold following the merger with SCANA. Following the merger, shareholders of Dominion Energy and former SCANA shareholders will own interests in a combined company operating an expanded business with more assets and a different mix of liabilities. Current shareholders of Dominion Energy and SCANA may not wish to continue to invest in the combined company, or may wish to reduce their investment in the combined company, in order to comply with institutional investing guidelines, to increase diversification or to track any rebalancing of stock indices in which Dominion Energy common stock or SCANA common stock is or was included. If, following the merger, large amounts of Dominion Energy common stock are sold, the price of its common stock could decline.

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

 

 

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Litigation against SCANA and Dominion Energy could result in an injunction preventing the completion of the merger with SCANA or may adversely affect the combined company’s business, financial condition or results of operations following the merger with SCANA. Following the announcement of the SCANA Merger Agreement, lawsuits have been filed asserting claims relating to the merger. Among other things, the lawsuits allege breaches of various fiduciary duties by the members of the SCANA board in connection with the merger and allegations that Dominion Energy and/or SCANA aided and abetted such alleged breaches. Among other remedies, the plaintiffs seek to enjoin the merger, rescind the merger agreement or be awarded monetary damages should the merger be completed. While Dominion Energy believes that dismissal of these lawsuits is warranted, the outcome of any such litigation is inherently uncertain. The defense or settlement of any lawsuit or any claim that remains unresolved at the time the merger closes may adversely affect the combined company’s business, financial condition or results of operation. Additionally, other lawsuits may be filed in the future making similar or new claims and seeking similar or new remedies.

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

 

 

Item 1B. Unresolved Staff Comments

None.

    

 

 

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Item 2. Properties

As of December 31, 2017, Dominion Energy owned its principal executive office and three other corporate offices, all located in Richmond, Virginia. Dominion Energy also leases corporate offices in other cities in which its subsidiaries operate. Virginia Power and Dominion Energy Gas share Dominion Energy’s principal office in Richmond, Virginia, which is owned by Dominion Energy. In addition, Virginia Power’s Power Delivery and Power Generation segments share certain leased buildings and equipment. See Item 1. Business for additional information about each segment’s principal properties, which information is incorporated herein by reference.

Dominion Energy’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described here and in Item 1. Business.

Certain of Virginia Power’s property is subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding as of December 31, 2017; however, by leaving the indenture open, Virginia Power expects to retain the flexibility to issue mortgage bonds in the future. Certain of Dominion Energy’s merchant generation facilities are also subject to liens.

GAS INFRASTRUCTURE

Dominion Energy and Dominion Energy Gas

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

Dominion Energy Gas has approximately 10,400 miles, excluding interests held by others, of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy Gas also owns NGL processing plants capable of processing over 270,000 mcf per day of natural gas. Hastings is the largest plant and is capable of processing over 180,000 mcf per day of natural gas. Hastings can also fractionate over 580,000 Gals per day of NGLs into marketable products, including propane, isobutane, butane and natural gasoline. NGL operations have storage capacity of 1,226,500 Gals of propane, 109,000 Gals of isobutane, 442,000 Gals of butane, 2,000,000 Gals of natural gasoline and 1,012,500 Gals of mixed NGLs. Dominion Energy Gas also operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with approximately 2,000 storage wells and approximately 399,000 acres of operated leaseholds.

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

Dominion Energy

Cove Point’s LNG facility has an operational peak regasification daily send-out capacity of approximately 1.8 million Dths and an aggregate LNG storage capacity of approximately 14.6 bcfe. In addition, Cove Point has a liquefier that has the potential to create approximately 15,000 Dths/day.

The Cove Point pipeline is a 36-inch diameter underground, interstate natural gas pipeline that extends approximately 88 miles from Cove Point to interconnections with Transcontinental Gas Pipe Line Company, LLC in Fairfax County, Virginia, and with Columbia Gas Transmission, LLC and DETI in Loudoun County, Virginia. In 2009, the original pipeline was expanded to include a 36-inch diameter expansion that extends approximately 48 miles, roughly 75% of which is parallel to the original pipeline.

Questar Gas distributes gas to customers in Utah, Wyoming and Idaho. Questar Gas owns and operates distribution systems and has a total of 29,600 miles of street mains, service lines and interconnecting pipelines. Questar Gas has a major operations center in Salt Lake City, and has operations centers, field offices and service-center facilities in other parts of its service area.

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

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

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

In total, Dominion Energy has 171 compressor stations with approximately 1,190,000 installed compressor horsepower.

POWER DELIVERY

See Item 1. Business, General for details regarding Power Delivery’s principal properties, which primarily include transmission and distribution lines.

POWER GENERATION

Dominion Energy and Virginia Power generate electricity for sale on a wholesale and a retail level. Dominion Energy and Virginia Power supply electricity demand either from their generation facilities or through purchased power contracts. As of December 31, 2017, Power Generation’s total utility and merchant generating capacity was approximately 26,000 MW. The following tables list Power Generation’s utility and merchant generating units and capability, as of December 31, 2017.

 

 

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VIRGINIA POWER UTILITY GENERATION(1)

 

Plant    Location     

Net Summer

Capability (MW)

   

Percentage

Net Summer

Capability

 

Gas

       

Brunswick County (CC)

     Brunswick County, VA        1,376    

Warren County (CC)

     Warren County, VA        1,350    

Ladysmith (CT)

     Ladysmith, VA        784    

Bear Garden (CC)

     Buckingham County, VA        622    

Remington (CT)

     Remington, VA        608    

Possum Point (CC)

     Dumfries, VA        573    

Chesterfield (CC)

     Chester, VA        397    

Elizabeth River (CT)

     Chesapeake, VA        348    

Possum Point(6)

     Dumfries, VA        316    

Bellemeade (CC)(6)

     Richmond, VA        267    

Bremo(6)

     Bremo Bluff, VA        227    

Gordonsville Energy (CC)

     Gordonsville, VA        218    

Gravel Neck (CT)

     Surry, VA        170    

Darbytown (CT)

     Richmond, VA        168    

Rosemary (CC)

     Roanoke Rapids, NC        165          

Total Gas

        7,589       37

Coal

       

Mt. Storm

     Mt. Storm, WV        1,624    

Chesterfield(6)

     Chester, VA        1,268    

Virginia City Hybrid Energy Center

     Wise County, VA        610    

Clover

     Clover, VA        439 (2)   

Yorktown(3)

     Yorktown, VA        323    

Mecklenburg(6)

     Clarksville, VA        138          

Total Coal

        4,402       21  

Nuclear

       

Surry

     Surry, VA        1,676    

North Anna

     Mineral, VA        1,672 (4)         

Total Nuclear

        3,348       16  

Oil

       

Yorktown

     Yorktown, VA        790    

Possum Point

     Dumfries, VA        783    

Gravel Neck (CT)

     Surry, VA        198    

Darbytown (CT)

     Richmond, VA        168    

Possum Point (CT)

     Dumfries, VA        72    

Chesapeake (CT)

     Chesapeake, VA        51    

Low Moor (CT)

     Covington, VA        48    

Northern Neck (CT)

     Lively, VA        47          

Total Oil

        2,157       11  

Hydro

       

Bath County

     Warm Springs, VA        1,808 (5)   

Gaston

     Roanoke Rapids, NC        220    

Roanoke Rapids

     Roanoke Rapids, NC        95    

Other

     Various        3          

Total Hydro

        2,126       10  

Biomass

       

Pittsylvania

     Hurt, VA        83    

Altavista

     Altavista, VA        51    

Polyester

     Hopewell, VA        51    

Southampton

     Southampton, VA        51          

Total Biomass

        236       1  

Solar

       

Whitehouse Solar

     Louisa County, VA        20    

Woodland Solar

     Isle of Wight County, VA        19    

Scott Solar

     Powhatan County, VA        17          

Total Solar

        56        

Various

       

Mt. Storm (CT)

     Mt. Storm, WV        11        
                19,925          

Power Purchase Agreements

              854       4  

Total Utility Generation

              20,779       100

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

(1) The table excludes Virginia Power’s Morgans Corner solar facility located in Pasquotank County, NC, Remington solar facility located in Remington, VA and Oceana solar facility located in Virginia Beach, VA which have a net summer capacity of 20 MW, 20 MW and 18 MW, respectively as these facilities are dedicated to serving non-jurisdictional customers.
(2) Excludes 50% undivided interest owned by ODEC.
(3) Coal-fired units are expected to be retired at Yorktown power station as early as 2018 as a result of the issuance of MATS.
(4) Excludes 11.6% undivided interest owned by ODEC.
(5) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of FirstEnergy Corp.
(6) In January 2018, Virginia Power announced it would place certain units at this facility in cold storage.

 

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DOMINION MERCHANT GENERATION

 

Plant    Location     

Net Summer

Capability (MW)

   

Percentage

Net Summer

Capability

 

Nuclear

       

Millstone

     Waterford, CT        2,001 (1)         

Total Nuclear

        2,001       39

Gas

       

Fairless (CC)

     Fairless Hills, PA        1,240    

Manchester (CC)

     Providence, RI        468          

Total Gas

        1,708       33  

Solar(2)

       

Escalante I, II and III

     Beaver County, UT        120 (3)   

Amazon Solar Farm Virginia—Southampton

     Newsoms, VA        100    

Amazon Solar Farm Virginia—Accomack

     Oak Hall, VA        80    

Innovative Solar 37

     Morven, NC        79    

Moffett Solar 1

     Ridgeland, SC        71    

Granite Mountain East and West

     Iron County, UT        65 (3)   

Summit Farms Solar

     Moyock, NC        60    

Enterprise

     Iron County, UT        40 (3)   

Iron Springs

     Iron County, UT        40 (3)   

Pavant Solar

     Holden, UT        34 (4)   

Camelot Solar

     Mojave, CA        30 (4)   

Midway II

     Calipatria, CA        30    

Indy I, II and III

     Indianapolis, IN        20 (4)   

Amazon Solar Farm Virginia—Buckingham

     Cumberland, VA        20    

Amazon Solar Farm Virginia—Correctional

     Barhamsville, VA        20    

Hecate Cherrydale

     Cape Charles, VA        20    

Amazon Solar Farm Virginia—Sappony

     Soney Creek, VA        20    

Amazon Solar Farm Virginia—Scott II

     Powhatan, VA        20    

Cottonwood Solar

     Kings and Kern counties, CA        16 (4)   

Alamo Solar

     San Bernardino, CA        13 (4)   

Maricopa West Solar

     Kern County, CA        13 (4)   

Imperial Valley Solar

     Imperial, CA        13 (4)   

Richland Solar

     Jeffersonville, GA        13 (4)   

CID Solar

     Corcoran, CA        13 (4)   

Kansas Solar

     Lenmore, CA        13 (4)   

Kent South Solar

     Lenmore, CA        13 (4)   

Old River One Solar

     Bakersfield, CA        13 (4)   

West Antelope Solar

     Lancaster, CA        13 (4)   

Adams East Solar

     Tranquility, CA        13 (4)   

Catalina 2 Solar

     Kern County, CA        12 (4)   

Mulberry Solar

     Selmer, TN        11 (4)   

Selmer Solar

     Selmer, TN        11 (4)   

Columbia 2 Solar

     Mojave, CA        10 (4)   

Hecate Energy Clarke County

     White Post, VA        10    

Ridgeland Solar Farm I

     Ridgeland, SC        10    

Azalea Solar

     Davisboro, GA        5 (4)   

Clipperton

     Clinton, NC        5    

Fremont Solar

     Fremont, NC        5    

Moorings 2

     Lagrange, NC        5    

Pikeville Solar

     Pikeville, NC        5    

Wakefield

     Zebulon, NC        5    

Somers Solar

     Somers, CT        3 (4)         

Total Solar

        1,112       22  

Wind

       

Fowler Ridge(5)

     Benton County, IN        150 (6)   

NedPower(5)

     Grant County, WV        132 (7)         

Total Wind

        282       6  

Fuel Cell

       

Bridgeport Fuel Cell

     Bridgeport, CT        15          

Total Fuel Cell

              15        

Total Merchant Generation

              5,118       100

Note: (CC) denotes combined cycle.

(1) Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain.
(2) All solar facilities are alternating current.
(3) Excludes 50% noncontrolling interest owned by NRG. Dominion Energy’s interest is subject to a lien securing Dominion Solar Projects III, Inc.’s debt.
(4) Excludes 33% noncontrolling interest owned by Terra Nova Renewable Partners. Dominion Energy’s interest is subject to a lien securing SBL Holdco’s debt.
(5) Subject to a lien securing the facility’s debt.
(6) Excludes 50% membership interest owned by BP.
(7) Excludes 50% membership interest owned by Shell.

 

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Item 3. Legal Proceedings

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

In January 2016, Virginia Power self-reported a release of mineral oil from the Crystal City substation and began extensive cleanup. Virginia Power assumed the role of responsible party and has continued to cooperate with ongoing requirements for investigative and corrective action. In December 2016, the Virginia State Water Control Board approved a consent order between the VDEQ and Virginia Power related to this matter, which included a penalty in excess of $100,000. In May 2017, the VDEQ formally terminated the consent order, finding that all requirements had been completed. Also in May 2017, the U.S. Department of the Interior, on behalf of several federal and state agencies, proposed a settlement to resolve the agencies’ claims for natural resource damages related to the mineral oil release. In January 2018, Virginia Power and the natural resource trustee agencies executed a settlement agreement that would require Virginia Power to pay approximately $400,000 to fund wetland restoration and related projects in the location of the release. Final approval of the settlement is pending completion of a 30-day public comment period which is expected during the first quarter of 2018.

See Notes 13 and 22 to the Consolidated Financial Statements and Future Issues and Other Matters in Item 7. MD&A, which information is incorporated herein by reference, for discussion of various environmental and other regulatory proceedings to which the Companies are a party.

 

 

Item 4. Mine Safety Disclosures

Not applicable.

 

 

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

 

Name and Age    Business Experience Past Five Years(1)

Thomas F. Farrell, II (63)

   Chairman of the Board of Directors, President and CEO of Dominion Energy from April 2007 to date; Chairman and CEO of Dominion Energy Midstream GP, LLC (the general partner of Dominion Energy Midstream) from March 2014 to date and President from February 2015 to date; CEO of Dominion Energy Gas from September 2013 to date and Chairman from March 2014 to date; Chairman and CEO of Virginia Power from February 2006 to date and Questar Gas from September 2016 to date.

Mark F. McGettrick (60)

   Executive Vice President and CFO of Dominion Energy from June 2009 to date, Dominion Energy Midstream GP, LLC from March 2014 to date, Virginia Power from June 2009 to date, Dominion Energy Gas from September 2013 to date, and Questar Gas from September 2016 to date.

Robert M. Blue (50)

   Executive Vice President and President & CEO—Power Delivery Group of Dominion Energy from May 2017 to date; President and COO—Power Delivery Group of Virginia Power from May 2017 to date; Senior Vice President and President & CEO—Dominion Virginia Power of Dominion Energy from January 2017 to May 2017; President and COO of Virginia Power from January 2017 to May 2017; Senior Vice President—Law, Regulation & Policy of Dominion Energy, Dominion Energy Gas and Dominion Energy Midstream GP, LLC from February 2016 to December 2016 and Questar Gas from September 2016 to December 2016; President of Virginia Power from January 2016 to December 2016; Senior Vice President—Regulation, Law, Energy Solutions and Policy of Dominion Energy and Dominion Energy Gas from May 2015 to January 2016 and Dominion Energy Midstream GP, LLC from July 2015 to January 2016; Senior Vice President—Regulation, Law, Energy Solutions and Policy of Virginia Power from May 2015 to December 2015; President of Virginia Power from January 2014 to May 2015; Senior Vice President—Law, Public Policy and Environment of Dominion Energy from January 2011 to December 2013.

Paul D. Koonce (58)

   Executive Vice President and President & CEO—Power Generation Group of Dominion Energy from January 2017 to date; President and COO—Power Generation Group of Virginia Power from May 2017 to date; Executive Vice President and CEO—Dominion Generation Group of Dominion Energy from January 2016 to December 2016; Executive Vice President and CEO—Energy Infrastructure Group of Dominion Energy from February 2013 to December 2015; Executive Vice President of Dominion Energy from April 2006 to February 2013; Executive Vice President of Dominion Energy Midstream GP, LLC from March 2014 to December 2015; President and COO of Virginia Power from June 2009 to May 2017; President of Dominion Energy Gas from September 2013 to December 2015.

Diane Leopold (51)

   Executive Vice President and President & CEO—Gas Infrastructure Group of Dominion Energy and Dominion Energy Midstream GP, LLC from May 2017 to date; President of Dominion Energy Gas from January 2017 to date and Questar Gas from August 2017 to date; Senior Vice President and President & CEO—Dominion Energy of Dominion Energy and Dominion Energy Midstream GP, LLC from January 2017 to May 2017; President of DETI, East Ohio and Dominion Cove Point, Inc. from January 2014 to date; Senior Vice President of DETI from April 2012 to December 2013.

Mark O. Webb (53)

   Senior Vice President—Corporate Affairs and Chief Legal Officer of Dominion Energy, Virginia Power, Dominion Energy Gas, Dominion Energy Midstream GP, LLC, and Questar Gas from January 2017 to date; Senior Vice President, General Counsel and Chief Risk Officer of Dominion Energy, Virginia Power and Dominion Energy Gas from May 2016 to December 2016; Senior Vice President and General Counsel of Dominion Energy Midstream GP, LLC from May 2016 to December 2016 and Questar Gas from September 2016 to December 2016; Vice President, General Counsel and Chief Risk Officer of Dominion Energy, Virginia Power and Dominion Energy Gas from January 2014 to May 2016; Vice President and General Counsel of Dominion Energy Midstream GP, LLC from March 2014 to May 2016; Vice President and General Counsel of Dominion Energy and Virginia Power from January 2013 to December 2013 and Dominion Energy Gas from September 2013 to December 2013.

Michele L. Cardiff (50)

   Vice President, Controller and CAO of Dominion Energy and Virginia Power from April 2014 to date, Dominion Energy Gas and Dominion Energy Midstream GP, LLC from March 2014 to date and Questar Gas from September 2016 to date; Vice President—Accounting of DES from January 2014 to March 2014; Vice President and General Auditor of DES from September 2012 to December 2013.

 

(1) Any service listed for Virginia Power, Dominion Energy Midstream GP, LLC, Dominion Energy Gas, DETI, East Ohio, Dominion Cove Point, Inc., Questar Gas and DES reflects service at a subsidiary of Dominion Energy.

 

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

Dominion Energy

Dominion Energy’s common stock is listed on the NYSE. At February 15, 2018, there were approximately 123,000 record holders of Dominion Energy’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion Energy’s transfer agent records and includes accounts with shares held in (1) certificate form, (2) book-entry in the Direct Registration System and (3) book-entry under Dominion Energy Direct®. Discussions of expected dividend payments and restrictions on Dominion Energy’s payment of dividends required by this Item are contained in Liquidity and Capital Resources in Item 7. MD&A and Notes 17 and 20 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 2017 and 2016. Quarterly information concerning stock prices and dividends is disclosed in Note 26 to the Consolidated Financial Statements, which information is incorporated herein by reference.

The following table presents certain information with respect to Dominion Energy’s common stock repurchases during the fourth quarter of 2017:

 

DOMINION ENERGY PURCHASES OF EQUITY SECURITIES
Period   

Total

Number

of Shares

Purchased(1)

    

Average

Price

Paid per

Share(2)

    

Total Number

of Shares

Purchased as Part

of Publicly Announced

Plans or Programs

    

Maximum Number (or

Approximate Dollar Value)

of Shares that May

Yet Be Purchased under the

Plans or Programs(3)

 

10/1/2017-10/31/17

     29,305      $ 76.93        N/A      19,629,059 shares/$1.18 billion

11/1/2017-11/30/17

     8        80.49        N/A      19,629,059 shares/$1.18 billion

12/1/2017-12/31/17

     4        83.57        N/A      19,629,059 shares/$1.18 billion

Total

     29,317      $ 76.93        N/A      19,629,059 shares/$1.18 billion

 

(1) 29,305, 8 and 4 shares were tendered by employees to satisfy tax withholding obligations on vested restricted stock in October, November and December 2017, respectively.
(2) Represents the weighted-average price paid per share.
(3) The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Energy Board of Directors in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion Energy Board of Directors was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion.

Virginia Power

There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion Energy. Potential restrictions on Virginia Power’s payment of dividends are discussed in Note 20 to the Consolidated Financial Statements. In 2016, no dividends were declared or paid given the sufficiency of operating and other cash flows at Dominion Energy. In 2017, Virginia Power declared and paid quarterly cash dividends of $445 million, $409 million and $345 million during the first three quarters of 2017, respectively. Virginia Power intends to pay quarterly cash dividends in 2018 but is neither required to nor restricted, except as described above, from making such payments.

Dominion Energy Gas

All of Dominion Energy Gas’ membership interests are owned by Dominion Energy. Potential restrictions on Dominion Energy Gas’ payment of distributions are discussed in Note 20 to the Consolidated Financial Statements. Dominion Energy Gas declared and paid cash distributions of $150 million in the second quarter of 2016. Dominion Energy Gas declared and paid cash distributions of $7 million and $8 million in the first and second quarters of 2017, respectively. Dominion Energy Gas intends to pay quarterly cash dividends in 2018 but is neither required to nor restricted, except as described above, from making such payments.

 

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Item 6. Selected Financial Data

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

DOMINION ENERGY

 

Year Ended December 31,    2017(1)      2016(2)      2015      2014(3)      2013(4)  
(millions, except per share amounts)                                   

Operating revenue

   $ 12,586      $ 11,737      $ 11,683      $ 12,436      $ 13,120  

Income from continuing operations, net of tax(5)

     2,999        2,123        1,899        1,310        1,789  

Loss from discontinued operations, net of tax(5)

                                 (92

Net income attributable to Dominion Energy

     2,999        2,123        1,899        1,310        1,697  

Income from continuing operations before loss from discontinued operations per common share-basic

     4.72        3.44        3.21        2.25        3.09  

Net income attributable to Dominion Energy per common share-basic

     4.72        3.44        3.21        2.25        2.93  

Income from continuing operations before loss from discontinued operations per common share-diluted

     4.72        3.44        3.20        2.24        3.09  

Net income attributable to Dominion Energy per common share-diluted

     4.72        3.44        3.20        2.24        2.93  

Dividends declared per common share

     3.035        2.80        2.59        2.40        2.25  

Total assets

     76,585        71,610        58,648        54,186        49,963  

Long-term debt

     30,948        30,231        23,468        21,665        19,199  

 

(1) Includes $851 million of tax benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate, partially offset by $96 million of after-tax charges associated with equity method investments in wind-powered generation facilities.
(2) Includes a $122 million after-tax charge related to future ash pond and landfill closure costs at certain utility generation facilities.
(3) Includes $248 million of after-tax charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, a $193 million after-tax charge related to Dominion Energy’s restructuring of its producer services business and a $174 million after-tax charge associated with the Liability Management Exercise.
(4) Includes a $109 million after-tax charge related to Dominion Energy’s restructuring of its producer services business ($76 million) and an impairment of certain natural gas infrastructure assets ($33 million). Also in 2013, Dominion Energy recorded a $92 million after-tax net loss from the discontinued operations of Brayton Point and Kincaid.
(5) Amounts attributable to Dominion Energy’s common shareholders.

 

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

 

 

MD&A discusses Dominion Energy’s results of operations and general financial condition and Virginia Power’s and Dominion Energy Gas’ results of operations. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. Virginia Power and Dominion Energy Gas meet the conditions to file under the reduced disclosure format, and therefore have omitted certain sections of MD&A.

 

 

CONTENTS OF MD&A

MD&A consists of the following information:

  Forward-Looking Statements
  Accounting Matters—Dominion Energy
  Dominion Energy
    Results of Operations
    Segment Results of Operations
  Virginia Power
    Results of Operations
  Dominion Energy Gas
    Results of Operations
  Liquidity and Capital Resources—Dominion Energy
  Future Issues and Other Matters—Dominion Energy

 

 

FORWARD-LOOKING STATEMENTS

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

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

  Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;
  Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities;
  Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations, including provisions of the 2017 Tax Reform Act that take effect beginning in 2018;
  Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances;
  Cost of environmental compliance, including those costs related to climate change;
  Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;
  Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals;
  Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;
  Unplanned outages at facilities in which the Companies have an ownership interest;
  Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s and Dominion Energy Gas’ earnings and the Companies’ liquidity position and the underlying value of their assets;
  Counterparty credit and performance risk;
  Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;
  Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants;
  Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion Energy and Virginia Power and in benefit plan trusts by Dominion Energy and Dominion Energy Gas;
  Fluctuations in interest rates or foreign currency exchange rates;
  Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;
  Changes in financial or regulatory accounting principles or policies imposed by governing bodies;
  Employee workforce factors including collective bargaining agreements and labor negotiations with union employees;
  Risks of operating businesses in regulated industries that are subject to changing regulatory structures;
  Impacts of acquisitions, divestitures, transfers of assets to joint ventures or Dominion Energy Midstream, and retirements of assets based on asset portfolio reviews;
  The expected timing and likelihood of completion of the proposed acquisition of SCANA, including the ability to obtain the requisite approvals of SCANA’s shareholders and the terms and condition of any regulatory approvals;
  Receipt of approvals for, and timing of, closing dates for other acquisitions and divestitures;
  The timing and execution of Dominion Energy Midstream’s growth strategy;
  Changes in rules for regional transmission organizations and independent system operators in which Dominion Energy and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models;
  Political and economic conditions, including inflation and deflation;
  Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity;
 

 

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

 

 

 

  Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy and Dominion Energy Gas’ pipeline and processing systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;
  Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers;
  Competition in the development, construction and ownership of certain electric transmission facilities in Virginia Power’s service territory in connection with FERC Order 1000;
  Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;
  Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion Energy and Dominion Energy Gas;
  Changes in operating, maintenance and construction costs;
  Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals;
  The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement or intervention in such projects;
  Adverse outcomes in litigation matters or regulatory proceedings; and
  The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events.

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors.

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

 

 

ACCOUNTING MATTERS

Critical Accounting Policies and Estimates

Dominion Energy has identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the

underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or using different assumptions. Dominion Energy has discussed the development, selection and disclosure of each of these policies with the Audit Committee of its Board of Directors.

ACCOUNTING FOR REGULATED OPERATIONS

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

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

ASSET RETIREMENT OBLIGATIONS

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

 

 

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In 2017, 2016 and 2015, Dominion Energy recognized $117 million, $104 million and $93 million, respectively, of accretion, and expects to recognize $117 million in 2018. Dominion Energy records accretion and depreciation associated with utility nuclear decommissioning AROs and regulated pipeline replacement AROs as an adjustment to the regulatory liabilities related to these items.

A significant portion of Dominion Energy’s AROs relates to the future decommissioning of its merchant and utility nuclear facilities. These nuclear decommissioning AROs are reported in the Power Generation segment. At December 31, 2017, Dominion Energy’s nuclear decommissioning AROs totaled $1.5 billion, representing approximately 62% of its total AROs. Based on their significance, the following discussion of critical assumptions inherent in determining the fair value of AROs relates to those associated with Dominion Energy’s nuclear decommissioning obligations.

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

INCOME TAXES

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

Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2017, Dominion Energy had $38 million of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.

Deferred income tax assets and liabilities are recorded representing future effects on income taxes for temporary differences

between the bases of assets and liabilities for financial reporting and tax purposes. Dominion Energy evaluates quarterly the probability of realizing deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. Dominion Energy establishes a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2017, Dominion Energy had established $146 million of valuation allowances.

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

At the date of enactment, the Companies’ deferred taxes were remeasured based upon the new tax rate expected to apply when temporary differences are realized or settled. For regulated operations, many of the changes in deferred taxes 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 our state and federal regulators. For nonregulated operations, the changes in deferred taxes are recorded as an adjustment to deferred tax expense.

ACCOUNTING FOR DERIVATIVE CONTRACTS AND FINANCIAL INSTRUMENTS AT FAIR VALUE

Dominion Energy uses derivative contracts such as physical and financial forwards, futures, swaps, options and FTRs to manage commodity, interest rate and foreign currency exchange rate risks of its business operations. Derivative contracts, with certain exceptions, are reported in the Consolidated Balance Sheets at fair

 

 

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

 

 

 

value. The majority of investments held in Dominion Energy’s nuclear decommissioning and rabbi trusts and pension and other postretirement funds are also subject to fair value accounting. See Notes 6 and 21 to the Consolidated Financial Statements for further information on these fair value measurements.

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

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

USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING

As of December 31, 2017, Dominion Energy reported $6.4 billion of goodwill in its Consolidated Balance Sheet. A significant portion resulted from the acquisition of the former CNG in 2000 and the Dominion Energy Questar Combination in 2016.

In April of each year, Dominion Energy tests its goodwill for potential impairment, and performs additional tests more frequently if an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 2017, 2016 and 2015 annual tests and any interim tests did not result in the recognition of any goodwill impairment.

In general, Dominion Energy estimates the fair value of its reporting units by using a combination of discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. Fair value estimates are dependent on subjective factors such as Dominion Energy’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion Energy’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion Energy has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in

the most recent tests had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present.

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

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

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

EMPLOYEE BENEFIT PLANS

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

 

 

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assumptions and actual experience, is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants, rather than immediately.

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

  Expected inflation and risk-free interest rate assumptions;

 

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

 

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

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

Dominion Energy develops non-investment related assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions. Dominion Energy calculated its pension cost using an expected long-term rate of return on plan assets assumption of 8.75% for 2017, 2016 and 2015. For 2018, the expected long-term rate of return for pension cost assumption is 8.75%. Dominion Energy calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.50% for 2017, 2016 and 2015. For 2018, the expected long-term rate of return for other postretirement benefit cost assumption is 8.50%. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets.

Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost ranged from 3.31% to 4.50% for pension plans and 3.92% to

4.47% for other postretirement benefit plans in 2017, ranged from 2.87% to 4.99% for pension plans and 3.56% to 4.94% for other postretirement benefit plans in 2016 and were 4.40% in 2015. Dominion Energy selected a discount rate ranging from 3.80% to 3.81% for pension plans and 3.76% for other postretirement benefit plans for determining its December 31, 2017 projected benefit obligations.

Dominion Energy establishes the healthcare cost trend rate assumption based on analyses of various factors including the specific provisions of its medical plans, actual cost trends experienced and projected, and demographics of plan participants. Dominion Energy’s healthcare cost trend rate assumption as of December 31, 2017 was 7.00% and is expected to gradually decrease to 5.00% by 2022 and continue at that rate for years thereafter.

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

The following table illustrates the effect on cost of changing the critical actuarial assumptions previously discussed, while holding all other assumptions constant:

 

             Increase in Net Periodic Cost  
     

Change in

Actuarial

Assumption

   

Pension

Benefits

    

Other

Postretirement

Benefits

 
(millions, except percentages)                    

Discount rate

     (0.25 )%      $20        $  3  

Long-term rate of return on plan assets

     (0.25 )%      19        4  

Healthcare cost trend rate

     1  %      N/A        24  

In addition to the effects on cost, at December 31, 2017, a 0.25% decrease in the discount rate would increase Dominion Energy’s projected pension benefit obligation by $338 million and its accumulated postretirement benefit obligation by $44 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $158 million.

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

New Accounting Standards

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

 

 

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

 

 

 

Dominion Energy

 

 

RESULTS OF OPERATIONS

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

 

Year Ended
December 31,
   2017      $ Change      2016      $ Change      2015  
(millions, except EPS)                                   

Net income attributable to Dominion Energy

   $ 2,999        $ 876      $ 2,123        $ 224      $ 1,899  

Diluted EPS

     4.72        1.28        3.44        0.24        3.20  

Overview

2017 VS. 2016

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

2016 VS. 2015

Net income attributable to Dominion Energy increased 12%, primarily due to higher renewable energy investment tax credits and the new PJM capacity performance market effective June 2016. These increases were partially offset by a decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields and charges related to future ash pond and landfill closure costs at certain utility generation facilities.

Analysis of Consolidated Operations

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

 

Year Ended December 31,   2017     $ Change     2016     $ Change     2015  
(millions)                              

Operating Revenue

  $ 12,586       $ 849     $ 11,737       $   54     $ 11,683  

Electric fuel and other energy-related purchases

    2,301       (32     2,333       (392     2,725  

Purchased electric capacity

    6       (93     99       (231     330  

Purchased gas

    701       242       459       (92     551  

Net Revenue

    9,578       732       8,846       769       8,077  

Other operations and maintenance

    2,875       (189     3,064       469       2,595  

Depreciation, depletion and amortization

    1,905       346       1,559       164       1,395  

Other taxes

    668       72       596       45       551  

Other income

    165       (85     250       54       196  

Interest and related charges

    1,205       195       1,010       106       904  

Income tax expense (benefit)

    (30     (685     655       (250     905  

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

2017 VS. 2016

Net revenue increased 8%, primarily reflecting:

  A $663 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017;
  A $97 million electric capacity benefit related to non-utility generators ($133 million) and a benefit due to the annual PJM capacity performance market effective June 2016 ($123 million), partially offset by the annual PJM capacity performance market effective June 2017 ($159 million);
  An $86 million increase due to additional generation output from merchant solar generating projects;
  A $71 million increase in sales to electric utility retail customers due to the effect of changes in customer usage and other factors, including $25 million related to customer growth;
  A $63 million increase from regulated natural gas transmission growth projects placed in service;
  A $46 million increase from rate adjustment clauses associated with electric utility operations; and
  A $34 million increase in services performed for Atlantic Coast Pipeline.

These increases were partially offset by:

  A $144 million decrease from Cove Point import contracts;
  A $114 million decrease due to unfavorable pricing at merchant generation facilities; and
  A decrease in sales to electric utility retail customers from a decrease in cooling degree days during the cooling season of 2017 ($53 million) and a reduction in heating degree days during the heating season of 2017 ($28 million).

Other operations and maintenance decreased 6%, primarily reflecting:

  A $197 million absence of charges related to future ash pond and landfill closure costs at certain utility generation facilities;
  A $115 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;
  A $78 million benefit from the sale of certain assets associated with nonregulated retail energy marketing operations;
  The absence of organizational design initiative costs ($64 million); and
  A $46 million decrease in storm damage and service restoration costs associated with electric utility operations, partially offset by
  A $162 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017;
  A $92 million increase in salaries, wages and benefits;
  A $36 million increase in outage costs; and
  A $33 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income.

Depreciation, depletion and amortization increased 22%, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017 ($162 million)

 

 

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and various growth projects being placed into service ($151 million).

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

Other income decreased 34%, primarily due to charges associated with equity method investments in wind-powered generation facilities ($158 million), partially offset by an increase in earnings, excluding charges, from equity method investments ($29 million) and an increase in AFUDC associated with rate-regulated projects ($23 million).

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

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

2016 VS. 2015

Net revenue increased 10%, primarily reflecting:

  A $544 million increase from electric utility operations, primarily reflecting:
    A $225 million electric capacity benefit, primarily due to the new PJM capacity performance market effective June 2016 ($155 million) and the expiration of non-utility generator contracts in 2015 ($58 million);
    An increase from rate adjustment clauses ($183 million); and
    The absence of an $85 million write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015; and
  A $305 million increase due to the Dominion Energy Questar Combination.

These increases were partially offset by:

  A $47 million decrease from merchant generation operations, primarily due to lower realized prices at certain merchant generation facilities ($64 million) and an increase in planned and unplanned outage days in 2016 ($26 million), partially offset by additional solar generating facilities placed into service ($37 million);
  A $19 million decrease from regulated natural gas transmission operations, primarily due to:
    A $14 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($28 million), increased fuel costs ($13 million), contract rate changes ($11 million) and decreased revenue from gathering and extraction services ($8 million), partially offset by expansion projects placed in service ($18 million) and increased regulated gas sales ($20 million); and
    A $17 million decrease in NGL activities, due to decreased prices ($15 million) and volumes ($2 million); partially offset by
    A $12 million increase in other revenues, primarily due to an increase in services performed for Atlantic Coast Pipeline ($21 million), partially offset by decreased amor-
   

tization of deferred revenue associated with conveyed shale development rights ($4 million); and

  A $12 million decrease from regulated natural gas distribution operations, primarily due to a decrease in rate adjustment clause revenue related to low income assistance programs ($26 million) and a decrease in sales to customers due to a reduction in heating degree days ($6 million), partially offset by an increase in AMR and PIR program revenues ($18 million).

Other operations and maintenance increased 18%, primarily reflecting:

  A $148 million increase due to the Dominion Energy Questar Combination, including $58 million of transaction and transition costs;
  A $98 million increase in charges related to future ash pond and landfill closure costs at certain utility generation facilities;
  A $78 million decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields;
  Organizational design initiative costs ($64 million);
  A $50 million increase in storm damage and service restoration costs, including $23 million for Hurricane Matthew;
  A $20 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income; and
  A $16 million increase due to labor contract renegotiations as well as costs resulting from a union workforce temporary work stoppage; partially offset by
  A $26 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income.

Depreciation, depletion and amortization increased 12%, primarily due to various expansion projects being placed into service.

Other income increased 28%, primarily due to an increase in earnings from equity method investments ($55 million) and an increase in AFUDC associated with rate-regulated projects ($12 million), partially offset by lower realized gains (net of investment income) on nuclear decommissioning trust funds ($19 million).

Interest and related charges increased 12%, primarily due to higher long-term debt interest expense resulting from debt issuances in 2016 ($134 million), partially offset by an increase in capitalized interest associated with the Cove Point Liquefaction Project ($45 million).

Income tax expense decreased 28%, primarily due to higher renewable energy investment tax credits ($189 million) and the impact of a state legislative change ($14 million), partially offset by higher pre-tax income ($15 million).

Outlook

Dominion Energy’s strategy is to continue focusing on its regulated and long-term contracted businesses while maintaining upside potential in well-positioned nonregulated businesses. The goals of this strategy are to provide EPS growth, a growing dividend and to maintain a stable credit profile. Dominion Energy expects approximately 90% of earnings from its primary operating segments to come from regulated and long-term contracted businesses.

 

 

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

 

 

 

Dominion Energy’s 2018 net income is expected to decrease on a per share basis as compared to 2017 primarily from the following:

  Absence of a benefit from remeasurement of deferred income taxes from the 2017 Tax Reform Act;
  Reduction of solar investment tax credits;
  Increases in interest and related charges;
  An increase in depreciation, depletion, and amortization; and
  Share dilution.

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

  Revenues from the Liquefaction Project;
  A return to normal weather in its electric utility operations;
  Growth in weather-normalized electric utility sales of approximately 1.5%;
  Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue;
  Construction and operation of growth projects in gas transmission and distribution;
  Absence of additional refueling outages at Millstone; and
  A lower effective tax rate, driven by the tax reform.

In addition, if the merger with SCANA is completed in 2018, it would result in a decrease to net income as the result of charges to be incurred for refunds to SCE&G electric customers, write-offs of regulatory assets and transaction costs.

 

 

SEGMENT RESULTS OF OPERATIONS

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

 

Year Ended December 31,   2017     2016     2015  
    

Net

Income

attributable
to Dominion
Energy

   

Diluted

EPS

   

Net

Income

attributable
to Dominion
Energy

   

Diluted

EPS

   

Net

Income

attributable
to Dominion
Energy

   

Diluted

EPS

 
(millions, except EPS)                                    

Power Delivery

    $   531       $0.83       $   484       $ 0.78       $   490       $ 0.82  

Power Generation

    1,181       1.86       1,397       2.26       1,120       1.89  

Gas Infrastructure

    898       1.41       726       1.18       680       1.15  

Primary operating segments

    2,610       4.10       2,607       4.22       2,290       3.86  

Corporate and Other

    389       0.62       (484     (0.78     (391     (0.66

Consolidated

    $2,999       $4.72       $2,123       $ 3.44       $1,899       $ 3.20  

Power Delivery

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

 

Year Ended December 31,   2017     % Change     2016     % Change     2015  

Electricity delivered (million MWh)

    83.4           83.7           83.9  

Degree days:

         

Cooling

    1,801       (2     1,830       (1     1,849  

Heating

    3,104       (10     3,446       1       3,416  

Average electric distribution customer accounts (thousands)(1)

    2,574       1       2,549       1       2,525  

 

(1) Period average.

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

2017 VS. 2016

 

      Increase (Decrease)  
      Amount     EPS  
(millions, except EPS)             

Regulated electric sales:

    

Weather

     $(14     $(0.02

Other

     15       0.02  

FERC transmission equity return

     14       0.02  

Storm damage and service restoration

     14       0.02  

Other

     18       0.03  

Share dilution

           (0.02

Change in net income contribution

     $47       $0.05  

2016 VS. 2015

 

      Increase (Decrease)  
      Amount     EPS  
(millions, except EPS)             

Regulated electric sales:

    

Weather

     $  (1     $    —  

Other

     1        

FERC transmission equity return

     41       0.07  

Storm damage and service restoration

     (16     (0.03

Depreciation and amortization

     (10     (0.02

AFUDC return

     (8     (0.01

Interest expense

     (5     (0.01

Other

     (8     (0.01

Share dilution

           (0.03

Change in net income contribution

     $  (6     $(0.04

Power Generation

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

 

Year Ended December 31,   2017     % Change     2016     % Change     2015  

Electricity supplied
(million MWh):

         

Utility

    85.0       (3 )%      87.9       3     85.2  

Merchant

    28.9             28.9       7       26.9  

Degree days (electric
utility service area):

         

Cooling

    1,801       (2     1,830       (1     1,849  

Heating

    3,104       (10     3,446       1       3,416  
 

 

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

2017 VS. 2016

 

      Increase (Decrease)  
      Amount     EPS  
(millions, except EPS)             

Regulated electric sales:

    

Weather

     $  (36     $(0.06

Other

     32       0.05  

Electric capacity

     58       0.09  

Depreciation and amortization

     (46     (0.07

Renewable energy investment tax credits

     (133     (0.21

Merchant generation margin

     (28     (0.04

Interest expense

     (25     (0.04

Outage costs

     (22     (0.03

Other

     (16     (0.03

Share dilution

           (0.06

Change in net income contribution

     $(216     $(0.40

2016 VS. 2015

 

      Increase (Decrease)  
      Amount     EPS  
(millions, except EPS)             

Regulated electric sales:

    

Weather

     $    2       $    —  

Other

     13       0.02  

Renewable energy investment tax credits

     186       0.31  

Electric capacity

     137       0.23  

Merchant generation margin

     (34     (0.06

Rate adjustment clause equity return

     24       0.04  

Noncontrolling interest(1)

     (28     (0.05

Depreciation and amortization

     (25     (0.04

Other

     2       0.01  

Share dilution

           (0.09

Change in net income contribution

     $277       $ 0.37  

 

(1) Represents noncontrolling interest related to merchant solar partnerships.

Gas Infrastructure

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

 

Year Ended December 31,   2017     % Change     2016     % Change     2015  

Gas distribution throughput (bcf)(1):

         

Sales

    130       113     61       126     27  

Transportation

    654       22       537       14       470  

Heating degree days (gas distribution service area):

         

Eastern region

    4,930       (6     5,235       (8     5,666  

Western region(1)

    4,892       161       1,876       100        

Average gas distribution customer accounts (thousands)(1)(2):

         

Sales

    1,240             1,234 (3)      414       240  

Transportation

    1,086       1       1,071       1       1,057  

Average retail energy marketing customer accounts (thousands)(2)

    1,405       2       1,376       6       1,296  

 

(1) Includes Dominion Energy Questar effective September 2016.
(2) Period average.
(3) Includes Dominion Energy Questar customer accounts for the entire year.

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

2017 VS. 2016

 

      Increase (Decrease)  
      Amount     EPS  
(millions, except EPS)             

Dominion Energy Questar Combination

     $184       $ 0.30  

Sale of certain retail energy marketing assets

     48       0.08  

Assignment of shale development rights

     13       0.02  

Noncontrolling interest(1)

     (30     (0.05

Cove Point import contracts

     (86     (0.14

Transportation and storage growth projects

     29       0.04  

Other

     14       0.02  

Share dilution

           (0.04
       $172       $ 0.23  

 

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

2016 VS. 2015

 

      Increase (Decrease)  
      Amount     EPS  
(millions, except EPS)             

Gas distribution margin:

    

Weather

     $  (4     $(0.01

Rate adjustment clauses

     11       0.02  

Other

     6       0.01  

Assignment of shale development rights

     (48     (0.08

Dominion Energy Questar Combination

     78       0.13  

Other

     3       0.01  

Share dilution

           (0.05

Change in net income contribution

     $ 46       $ 0.03  

Corporate and Other

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

 

Year Ended December 31,    2017     2016     2015  
(millions, except EPS amounts)                   

Specific items attributable to operating segments

     $ 861       $ (180     $ (136

Specific items attributable to Corporate and Other segment

     (151     (44     (5

Total specific items

     710       (224     (141

Other corporate operations

     (321     (260     (250

Total net expense

     $ 389       $ (484)       $ (391

EPS impact

     $0.62       $(0.78)       $(0.66

TOTAL SPECIFIC ITEMS

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

 

 

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

 

 

 

VIRGINIA POWER

 

 

RESULTS OF OPERATIONS

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

 

Year Ended
December 31,
   2017      $ Change      2016      $ Change      2015  
(millions)                                   

Net Income

     $1,540        $322        $1,218        $131      $ 1,087  

Overview

2017 VS. 2016

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

2016 VS. 2015

Net income increased 12%, primarily due to the new PJM capacity performance market effective June 2016, an increase in rate adjustment clause revenue and the absence of a write-off of deferred fuel costs associated with the Virginia legislation enacted in February 2015. These increases were partially offset by charges related to future ash pond and landfill closure costs at certain utility generation facilities.

Analysis of Consolidated Operations

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

 

Year Ended December 31,   2017     $ Change     2016     $ Change     2015  
(millions)                              

Operating Revenue

  $ 7,556       $ (32   $ 7,588       $ (34   $ 7,622  

Electric fuel and other energy-related purchases

    1,909       (64     1,973       (347     2,320  

Purchased electric capacity

    6       (93     99       (231     330  

Net Revenue

    5,641       125       5,516       544       4,972  

Other operations and maintenance

    1,478       (379     1,857       223       1,634  

Depreciation and amortization

    1,141       116       1,025       72       953  

Other taxes

    290       6       284       20       264  

Other income

    76       20       56       (12     68  

Interest and related charges

    494       33       461       18       443  

Income tax expense

    774       47       727       68       659  

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

2017 VS. 2016

Net revenue increased 2%, primarily reflecting:

  A $97 million electric capacity benefit related to non-utility generators ($133 million) and a benefit due to the annual PJM capacity performance market effective June 2016 ($123 million), partially offset by the annual PJM capacity performance market effective June 2017 ($159 million);
  A $71 million increase in sales to retail customers due to the effect of changes in customer usage and other factors, including $25 million related to customer growth; and
  A $46 million increase from rate adjustment clauses; partially offset by
  A decrease in sales to retail customers from a decrease in cooling degree days during the cooling season of 2017 ($53 million) and a reduction in heating degree days during the heating season of 2017 ($28 million).

Other operations and maintenance decreased 20%, primarily reflecting:

  A $197 million decrease due to the absence of charges related to future ash pond and landfill closure costs at certain utility generation facilities;
  A $115 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;
  A $46 million decrease in storm damage and service restoration costs; and
  The absence of organizational design initiative costs ($32 million); partially offset by
  A $37 million increase in salaries, wages and benefits and general administrative expenses.

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

Other income increased 36%, primarily reflecting:

  An $11 million increase in interest income associated with the settlement of state income tax refund claims;
  An $11 million increase from the assignment of Virginia Power’s electric transmission tower rental portfolio; and
  An $8 million increase in AFUDC associated with rate-regulated projects; partially offset by
  A $16 million charge associated with a customer settlement.

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

2016 VS. 2015

Net revenue increased 11%, primarily reflecting:

  A $225 million electric capacity benefit, primarily due to the new PJM capacity performance market effective June 2016 ($155 million) and the expiration of non-utility generator contracts in 2015 ($58 million);
  An increase from rate adjustment clauses ($183 million); and
  The absence of an $85 million write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015.

Other operations and maintenance increased 14%, primarily reflecting:

  A $98 million increase in charges related to future ash pond and landfill closure costs at certain utility generation facilities;
  A $50 million increase in storm damage and service restoration costs, including $23 million for Hurricane Matthew;
  A $37 million increase in salaries, wages and benefits and general administrative expenses; and
  Organizational design initiative costs ($32 million).

Income tax expense increased 10%, primarily reflecting higher pre-tax income.

 

 

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DOMINION ENERGY GAS

 

 

RESULTS OF OPERATIONS

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

 

Year Ended December 31,    2017      $ Change      2016      $ Change     2015  
(millions)                                  

Net Income

   $ 615        $223      $ 392        $(65   $ 457  

Overview

2017 VS. 2016

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

2016 VS. 2015

Net income decreased 14%, primarily due a decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields.

Analysis of Consolidated Operations

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

 

Year Ended December 31,   2017     $ Change     2016     $ Change     2015  
(millions)                              

Operating Revenue

  $ 1,814       $ 176     $ 1,638       $(78   $ 1,716  

Purchased gas

    132       23       109       (24     133  

Other energy-related purchases

    21       9       12       (9     21  

Net Revenue

    1,661       144       1,517       (45     1,562  

Other operations and maintenance

    527       53       474       84       390  

Depreciation and amortization

    227       23       204       (13     217  

Other taxes

    185       15       170       4       166  

Earnings from equity method investee

    21             21       (2     23  

Other income

    20       9       11       10       1  

Interest and related charges

    97       3       94       21       73  

Income tax expense

    51       (164     215       (68     283  

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

2017 VS. 2016

Net revenue increased 9%, primarily reflecting:

  A $55 million increase due to regulated natural gas transmission growth projects placed in service;
  A $34 million increase in services performed for Atlantic Coast Pipeline;
  A $24 million increase in PIR program revenues; and
  A $16 million increase in rate recovery for low income assistance programs associated with regulated natural gas distribution operations.

Other operations and maintenance increased 11%, primarily reflecting:

  A $33 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income;
  A $16 million increase in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income;
  A $15 million increase due to a charge to write-off the balance of a regulatory asset no longer considered probable of recovery; and
  A $13 million increase in salaries, wages and benefits and general administrative expenses; partially offset by
  A $25 million increase in gains from agreements to convey shale development rights underneath several natural gas storage fields.

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

Other income increased 82%, primarily due to a $12 million increase in AFUDC associated with rate-regulated projects, partially offset by the absence of the 2016 sale of a portion of Dominion Energy Gas’ interest in Iroquois ($5 million).

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

2016 VS. 2015

Net revenue decreased 3%, primarily reflecting:

  A $34 million decrease from regulated natural gas transmission operations, primarily reflecting:
    A $36 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($28 million), increased fuel costs ($13 million), contract rate changes ($11 million) and decreased revenue from gathering and extraction services ($8 million), partially offset by increased regulated gas sales ($16 million) and expansion projects placed in service ($9 million); and
    An $18 million decrease from NGL activities, due to decreased prices ($16 million) and volumes ($2 million); partially offset by
    A $21 million increase in services performed for Atlantic Coast Pipeline; and
  A $12 million decrease from regulated natural gas distribution operations, primarily reflecting:
    A decrease in rate adjustment clause revenue related to low income assistance programs ($26 million); and
    A $9 million decrease in other revenue primarily due to a decrease in pooling and metering activities ($3 million), a decrease in Blue Racer management fees ($3 million) and a decrease in gathering activities ($2 million); partially offset by
    An $18 million increase in AMR and PIR program revenues; and
    An $8 million increase in off-system sales.
 

 

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Other operations and maintenance increased 22%, primarily reflecting:

  A $78 million decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields; and
  A $20 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income; partially offset by
  A $26 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income.

Other income increased $10 million, primarily due to a gain on the sale of 0.65% of the noncontrolling partnership interest in Iroquois ($5 million) and an increase in AFUDC associated with rate-regulated projects ($5 million).

Interest and related charges increased 29%, primarily due to higher interest expense resulting from the issuances of senior notes in November 2015 and the second quarter of 2016 ($28 million), partially offset by an increase in deferred rate adjustment clause interest expense ($7 million).

Income tax expense decreased 24% primarily reflecting lower pre-tax income.

LIQUIDITY AND CAPITAL RESOURCES

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

At December 31, 2017, Dominion Energy had $2.1 billion of unused capacity under its credit facilities. See additional discussion below under Credit Facilities and Short-Term Debt.

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

 

Year Ended December 31,    2017     2016     2015  
(millions)                   

Cash and cash equivalents at beginning of year

   $ 261     $ 607     $ 318  

Cash flows provided by (used in):

      

Operating activities

     4,549       4,127       4,475  

Investing activities

     (5,993     (10,703     (6,503

Financing activities

     1,303       6,230       2,317  

Net increase (decrease) in cash and cash equivalents

     (141     (346     289  

Cash and cash equivalents at end of year

   $ 120     $ 261     $ 607  

Operating Cash Flows

Net cash provided by Dominion Energy’s operating activities increased $422 million, primarily due to the operations acquired in the Dominion Energy Questar combination being included for all of 2017, derivative activities, and lower income tax payments, partially offset by lower deferred fuel cost recoveries in the Virginia jurisdiction, higher interest expense, lower revenue from Cove Point’s import contracts and higher pension and postretirement benefit payments and funding.

Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In December 2017, Dominion Energy’s Board of Directors established an annual dividend rate for 2018 of $3.34 per share of common stock, a 10.0% increase over the 2017 rate. Dividends are subject to declaration by the Board of Directors. In January 2018, Dominion Energy’s Board of Directors declared dividends payable in March 2018 of 83.5 cents per share of common stock.

Beginning in 2018, the 2017 Tax Reform Act is expected to reduce customer rates due to lower income tax expense recoveries and the settlement of income taxes refundable through future rates. The Companies’ regulated utilities continue to work with their respective regulatory commissions to determine the amount and timing of the 2017 Tax Reform Act benefits to customers. FERC has not yet issued guidance on the 2017 Tax Reform Act. The ultimate resolution of the amount and timing of these rate reductions with the Companies’ regulators could be material to the Companies’ operating cash flows.

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

CREDIT RISK

Dominion Energy’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion Energy’s credit exposure as of December 31, 2017 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.

 

     

Gross

Credit

Exposure

    

Credit

Collateral

    

Net

Credit

Exposure

 
(millions)                     

Investment grade(1)

     $19        $—        $19  

Non-investment grade(2)

     8               8  

No external ratings:

        

Internally rated-investment grade(3)

     5               5  

Internally rated-non-investment grade(4)

     63               63  

Total

     $95        $—        $95  

 

(1) Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 14% of the total net credit exposure.
(2) The five largest counterparty exposures, combined, for this category represented approximately 7% of the total net credit exposure.