EX-99.2 4 d804746dex992.htm EX-99.2

Exhibit 99.2

Glossary of Terms

The following abbreviations or acronyms used in this Form 8-K are defined below:

Abbreviation or Acronym |  | Definition
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
AFUDC |  | Allowance for funds used during construction
AOCI |  | Accumulated other comprehensive income (loss)
ARO |  | Asset retirement obligation
Atlantic Coast Pipeline |  | Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion Energy, Duke and Southern Company Gas
Atlantic Coast Pipeline Project |  | The approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina which will be owned by Dominion Energy, Duke and Southern Company Gas and constructed and operated by DETI
bcf |  | Billion cubic feet
Blue Racer |  | Blue Racer Midstream, LLC, a joint venture between Caiman and FR BR Holdings, LLC effective December 2018
Caiman |  | Caiman Energy II, LLC
CCR |  | Coal combustion residual
CEA |  | Commodity Exchange Act
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
Companies |  | Dominion Energy, Virginia Power and Dominion Energy Gas, collectively
Cooling degree days |  | Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day
Corporate Unit |  | A stock purchase contract and 1/20 or 1/40 interest in a RSN issued by Dominion Energy
Cove Point |  | Dominion Energy Cove Point LNG, LP
Cove Point Holdings |  | Cove Point GP Holding Company, LLC
Cove Point LNG Facility |  | An LNG terminalling and storage facility located on the Chesapeake Bay in Lusby, Maryland owned by Cove Point

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Abbreviation or Acronym |  | Definition
DECG |  | Dominion Energy Carolina Gas Transmission, LLC
DETI |  | Dominion Energy Transmission, Inc.
DGI |  | Dominion Generation, Inc.
DGP |  | Dominion Gathering and Processing, Inc.
Dodd-Frank Act |  | The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
Dominion Energy |  | The legal entity, Dominion Energy, Inc., one or more of its consolidated subsidiaries (other than Virginia Power and Dominion Energy Gas) or operating segments, or the entirety of Dominion Energy, Inc. and its consolidated subsidiaries
Dominion Energy Direct® |  | A dividend reinvestment and open enrollment direct stock purchase plan
Dominion Energy Gas |  | The legal entity, Dominion Energy Gas Holdings, LLC, one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion Energy Gas Holdings, LLC and its consolidated subsidiaries
Dominion Energy Midstream |  | The legal entity, Dominion Energy Midstream Partners, LP, one or more of its consolidated subsidiaries, Cove Point Holdings, Iroquois GP Holding Company, LLC, DECG and Dominion Energy Questar Pipeline (beginning December 1, 2016), or the entirety of Dominion Energy Midstream Partners, LP and its consolidated subsidiaries
Dominion Energy Questar |  | The legal entity, Dominion Energy Questar Corporation, one or more of its consolidated subsidiaries, or the entirety of Dominion Energy Questar Corporation and its consolidated subsidiaries
Dominion Energy Questar Combination |  | Dominion Energy’s acquisition of Dominion Energy Questar completed on September 16, 2016 pursuant to the terms of the agreement and plan of merger entered on January 31, 2016
Dominion Energy Questar Pipeline |  | Dominion Energy Questar Pipeline, LLC, one or more of its consolidated subsidiaries, or the entirety of Dominion Energy Questar Pipeline, LLC and its consolidated subsidiaries
Dth |  | Dekatherm
Duke |  | The legal entity, Duke Energy Corporation, one or more of its consolidated subsidiaries or operating segments, or the entirety of Duke Energy Corporation and its consolidated subsidiaries
Eagle Solar |  | Eagle Solar, LLC, a wholly-owned subsidiary of DGI
East Ohio |  | The East Ohio Gas Company, doing business as Dominion Energy Ohio
Eastern Market Access Project |  | Project to provide 294,000 Dths/day of transportation service to help meet demand for natural gas for Washington Gas Light Company, a local gas utility serving customers in D.C., Virginia and Maryland, and Mattawoman Energy, LLC for its new electric power generation facility to be built in Maryland
EPA |  | U.S. Environmental Protection Agency
EPS |  | Earnings per share
Fairless |  | Fairless power station
FASB |  | Financial Accounting Standards Board

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Abbreviation or Acronym |  | Definition
FERC |  | Federal Energy Regulatory Commission
Fitch |  | Fitch Ratings Ltd.
FTRs |  | Financial transmission rights
Gas Infrastructure |  | Gas Infrastructure Group operating segment
GHG |  | Greenhouse gas
Greensville County |  | A 1,588 MW combined-cycle, natural gas-fired power station in Greensville County, Virginia
Heating degree days |  | Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day
Hope |  | Hope Gas, Inc., doing business as Dominion Energy West Virginia
Iroquois |  | Iroquois Gas Transmission System, L.P.
ISO |  | Independent system operator
June 2006 hybrids |  | Dominion Energy’s 2006 Series A Enhanced Junior Subordinated Notes due 2066
Liquefaction Project |  | A natural gas export/liquefaction facility at Cove Point
LNG |  | Liquefied natural gas
Manchester |  | Manchester power station
MD&A |  | Management’s Discussion and Analysis of Financial Condition and Results of Operations
Millstone |  | Millstone nuclear power station
Moody’s |  | Moody’s Investors Service
MW |  | Megawatt

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Abbreviation or Acronym |  | Definition
MWh |  | Megawatt hour
NERC |  | North American Electric Reliability Corporation
North Anna |  | North Anna nuclear power station
NOX |  | Nitrogen oxide
NRC |  | U.S. Nuclear Regulatory Commission
Order 1000 |  | Order issued by FERC adopting new requirements for electric transmission planning, cost allocation and development
PHMSA |  | Pipeline and Hazardous Materials Safety Administration
PJM |  | PJM Interconnection, L.L.C.
Power Delivery |  | Power Delivery Group operating segment
Power Generation |  | Power Generation Group operating segment
PSNC |  | Public Service Company of North Carolina, Incorporated
Questar Gas |  | Questar Gas Company, doing business as Dominion Energy Utah, Dominion Energy Wyoming and Dominion Energy Idaho
RCC |  | Replacement Capital Covenant
RGGI |  | Regional Greenhouse Gas Initiative

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Abbreviation or Acronym |  | Definition
RSN |  | Remarketable subordinated note
RTO |  | Regional transmission organization
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 Combination |  | Dominion Energy’s acquisition of SCANA completed on January 1, 2019 pursuant to the terms of the SCANA Merger Agreement
SCE&G |  | The legal entity, South Carolina Electric & Gas Company, its consolidated subsidiaries or operating segments, or the entirety of South Carolina Electric & Gas Company and its consolidated subsidiaries
September 2006 hybrids |  | Dominion Energy’s 2006 Series B Enhanced Junior Subordinated Notes due 2066
Southeast Energy |  | Southeast Energy Group operating segment
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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Abbreviation or Acronym |  | Definition
VDEQ |  | Virginia Department of Environmental Quality
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

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

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

CONTENTS OF MD&A

MD&A consists of the following information:

• |  | Forward-Looking Statements

• |  | Accounting Matters—Dominion Energy

• |  | Dominion Energy

| • |  | Results of Operations

| • |  | Segment Results of Operations

• |  | Virginia Power

| • |  | Results of Operations

• |  | Dominion Energy Gas

| • |  | Results of Operations

• |  | Liquidity and Capital Resources—Dominion Energy

• |  | Future Issues and Other Matters—Dominion Energy

FORWARD-LOOKING STATEMENTS

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

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

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

● |  | Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities;

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

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

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

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

● |  | Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals;

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

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

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

● |  | Counterparty credit and performance risk;

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

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

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

● |  | Fluctuations in interest rates or foreign currency exchange rates;

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

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

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

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

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

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

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

● |  | Political and economic conditions, including inflation and deflation;

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

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

● |  | Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers;

● |  | Competition in the development, construction and ownership of certain electric transmission facilities in Dominion Energy and Virginia Power’s service territories in connection with Order 1000;

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

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

● |  | Changes in operating, maintenance and construction costs;

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

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

● |  | Adverse outcomes in litigation matters or regulatory proceedings, including matters acquired in the SCANA Combination; and

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

● |  | Risks associated with entities in which Dominion Energy Gas shares ownership with third parties, including risks that result from lack of sole decision making authority, disputes that may arise between Dominion Energy Gas and third party participants and difficulties in exiting these arrangements;

● |  | Changes in future levels of domestic and international natural gas production, supply or consumption;

● |  | Fluctuations in future volumes of LNG imports or exports from the U.S. and other countries worldwide or demand for, purchases of, and prices related to natural gas or LNG;

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

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

ACCOUNTING MATTERS

Critical Accounting Policies and Estimates

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

ACCOUNTING FOR REGULATED OPERATIONS

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

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

ASSET RETIREMENT OBLIGATIONS

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

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

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

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

INCOME TAXES

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

Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2018, Dominion Energy had $44 million of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.

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

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

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

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ACCOUNTING FOR DERIVATIVE CONTRACTS AND FINANCIAL INSTRUMENTS AT FAIR VALUE

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

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

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

USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING

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

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

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

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from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset or underlying assets of equity method investees, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. See Notes 6 and 9 to the Consolidated Financial Statements for a discussion of impairments related to certain long-lived assets and equity method investments.

As discussed in Future Issues and Other Matters, delays in obtaining permits necessary for construction and construction delays due to judicial actions have impacted the estimated cost and schedule for the Atlantic Coast Pipeline Project. As a result, Dominion Energy evaluated the carrying amount of its equity method investment in Atlantic Coast Pipeline for an other-than-temporary impairment and determined that it was not impaired. Any significant changes affecting the discounted cash flow estimates associated with the Atlantic Coast Pipeline Project, such as future unfavorable judicial actions resulting in further construction and in-service delays along with an increase in construction costs, could result in an impairment charge.

EMPLOYEE BENEFIT PLANS

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

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

• |  | Expected inflation and risk-free interest rate assumptions;

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

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

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

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

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

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

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

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

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

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

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

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

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

New Accounting Standards

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

Dominion Energy

RESULTS OF OPERATIONS

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

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

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Overview

2018 VS. 2017

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

2017 VS. 2016

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

Analysis of Consolidated Operations

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

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

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

2018 VS. 2017

Net revenue increased 2%, primarily reflecting:

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

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

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

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

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

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

14

These increases were partially offset by:

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

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

• |  | A $94 million increase in net electric capacity expense related to the annual PJM capacity performance market effective June 2017 ($112 million) and the annual PJM capacity performance market effective June 2018 ($39 million), partially offset by a benefit related to non-utility generators ($57 million);

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

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

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

Other operations and maintenance increased 8%, primarily reflecting:

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

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

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

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

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

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

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

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

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

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

Interest and related charges increased 24%, primarily due to the absence of capitalization of interest expense associated with the Liquefaction Project upon completion of construction ($111 million), higher long-term debt interest expense resulting from net debt issuances in 2018 and 2017 ($92 million) and charges associated with the early redemption of certain debt securities ($69 million).

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

15

2017 VS. 2016

Net revenue increased 8%, primarily reflecting:

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

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

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

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

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

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

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

These increases were partially offset by:

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

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

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

Other operations and maintenance decreased 2%, primarily reflecting:

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

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

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

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

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

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

• |  | A $36 million increase in outage costs; and

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

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

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

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

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

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

16

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

Outlook

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

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

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

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

• |  | Return to normal weather;

• |  | An increase in pension-related expenses; and

• |  | Share dilution.

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

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

• |  | The inclusion of operations acquired in the SCANA Combination;

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

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

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

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

SEGMENT RESULTS OF OPERATIONS

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

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

17

Power Delivery

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

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

(1) | Period average.

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

2018 VS. 2017

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

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 |

18

Power Generation

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

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

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

2018 VS. 2017

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

2017 VS. 2016

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

19

Gas Infrastructure

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

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

(1) | Includes Dominion Energy Questar effective September 2016.

(2) | Period average.

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

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

2018 VS. 2017

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

2017 VS. 2016

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

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

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Corporate and Other

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

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

TOTAL SPECIFIC ITEMS

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

VIRGINIA POWER

RESULTS OF OPERATIONS

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

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

Overview

2018 VS. 2017

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

2017 VS. 2016

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

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Analysis of Consolidated Operations

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

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

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

2018 VS. 2017

Net revenue decreased 8%, primarily reflecting:

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

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

• |  | A $94 million increase in net electric capacity expense related to the annual PJM capacity performance market effective June 2017 ($112 million) and the annual PJM capacity performance market effective June 2018 ($39 million), partially offset by a benefit related to non-utility generators ($57 million); and

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

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

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

Other operations and maintenance increased 13%, primarily reflecting:

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

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

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

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

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

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

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2017 VS. 2016

Net revenue increased 2%, primarily reflecting:

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

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

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

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

Other operations and maintenance decreased 20%, primarily reflecting:

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

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

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

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

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

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

Other income increased 36%, primarily reflecting:

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

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

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

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

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

DOMINION ENERGY GAS

RESULTS OF OPERATIONS

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

Year Ended December 31, |  | 2018 |  |  | $ Change |  |  | 2017 |  |  | $ Change |  |  | 2016 |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income attributable to Dominion Energy Gas |  | $ | 481 |  |  | $ | (222 | ) |  | $ | 703 |  |  | $ | 226 |  |  | $ | 477 |

Overview

2018 VS. 2017

Net income attributable to Dominion Energy Gas decreased 32%, primarily due to an impairment charge on certain gathering and processing assets included in discontinued operations, a charge for disallowance of FERC-regulated plant and the absence of benefits from the 2017 Tax Reform Act partially offset by the commencement of commercial operations of the Liquefaction Project, regulated natural gas transmission activities from growth projects placed into service and an increase in gains from agreements to convey shale development rights underneath several natural gas storage fields.

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2017 VS. 2016

Net income attributable to Dominion Energy Gas increased 47%, primarily due to the operations of Dominion Energy Quarter Pipeline being included for all of 2017, a benefit from the remeasurement of deferred income taxes to the new corporate income tax rate and gas transportation and storage activities from growth projects placed into service.

Analysis of Consolidated Operations

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

Year Ended December 31, |  | 2018 |  |  | $ Change |  |  | 2017 |  |  | $ Change |  |  | 2016 |
(millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  | $ | 1,996 |  |  | $ | 473 |  |  | $ | 1,523 |  |  | $ | 149 |  |  | $ | 1,374 |
Purchased (excess) gas |  |  | (10 | ) |  |  | (119 | ) |  |  | 109 |  |  |  | 17 |  |  |  | 92 |
Other energy-related purchases |  |  | 4 |  |  |  | — |  |  |  | 4 |  |  |  | (1 | ) |  |  | 5 |
Net revenue |  |  | 2,002 |  |  |  | 592 |  |  |  | 1,410 |  |  |  | 133 |  |  |  | 1,277 |
Other operations and maintenance |  |  | 716 |  |  |  | 144 |  |  |  | 572 |  |  |  | 125 |  |  |  | 447 |
Depreciation and amortization |  |  | 333 |  |  |  | 91 |  |  |  | 242 |  |  |  | 51 |  |  |  | 191 |
Other taxes |  |  | 120 |  |  |  | 21 |  |  |  | 99 |  |  |  | 17 |  |  |  | 82 |
Impairment of assets and related charges |  |  | 163 |  |  |  | 148 |  |  |  | 15 |  |  |  | 15 |  |  |  | — |
Gains on sales of assets |  |  | (117 | ) |  |  | (47 | ) |  |  | (70 | ) |  |  | (26 | ) |  |  | (44 | )
Earnings from equity method investees |  |  | 54 |  |  |  | 7 |  |  |  | 47 |  |  |  | 3 |  |  |  | 44 |
Other income |  |  | 89 |  |  |  | 27 |  |  |  | 62 |  |  |  | 19 |  |  |  | 43 |
Interest and related charges |  |  | 174 |  |  |  | 114 |  |  |  | 60 |  |  |  | (5 | ) |  |  | 65 |
Income tax expense (benefit) |  |  | 124 |  |  |  | 189 |  |  |  | (65 | ) |  |  | (262 | ) |  |  | 197 |
Net income from discontinued operations |  |  | 24 |  |  |  | (139 | ) |  |  | 163 |  |  |  | 11 |  |  |  | 152 |
Noncontrolling interests |  |  | 175 |  |  |  | 49 |  |  |  | 126 |  |  |  | 25 |  |  |  | 101 |

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

2018 VS. 2017

Net revenue increased 42%, primarily reflecting:

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

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

• |  | A $57 million increase due to regulated natural gas transmission growth projects placed in service, other than the Liquefaction Project; partially offset by

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

Other operations and maintenance increased 25%, primarily reflecting:

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

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

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

Depreciation and amortization increased 38%, primarily due to an increase from various growth projects being placed into service, including the Liquefaction Project.

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Other taxes increased 21%, primarily due to property taxes associated with the Liquefaction Project commencing commercial operations.

Impairment of assets and related charges increased $148 million, primarily due to a charge for disallowance of FERC-regulated plant ($127 million) and a write-off associated with the Eastern Market Access Project ($37 million), partially offset by the absence of a charge to write-off the balance of a regulatory asset no longer considered probable of recovery ($15 million).

Gains on sales of assets increased 67%, primarily due to increased gains related to agreements to convey shale development rights under natural gas storage fields.

Earnings from equity method investees increased 15%, primarily due to higher earnings from unsubscribed capacity as a result of an increase in heating degree days at Iroquois.

Other income increased 44%, primarily due to interest income from Cove Point’s promissory notes receivable from Dominion Energy issued in September 2018 ($20 million) and a decrease in non-service components of pension and other postretirement employee benefit credits capitalized to property, plant and equipment in 2018 ($13 million), partially offset by AFUDC on rate-regulated projects ($7 million).

Interest and related charges increased $114 million, primarily due to the absence of capitalization of interest expense associated with the Liquefaction Project upon completion of construction ($72 million) and Cove Point’s term loan borrowings ($36 million).

Income tax expense increased $189 million, primarily due to the absence of benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($246 million), higher pre-tax income ($37 million), the absence of a settlement with state tax authorities ($5 million), partially offset by the reduced corporate income tax rate ($90 million) and a state legislative change ($10 million).

2017 VS. 2016

Net revenue increased 10%, primarily reflecting:

• |  | A $165 million increase due to Dominion Energy Questar Pipeline operations being included for all of 2017;

• |  | 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; partially offset by

• |  | A $144 million decrease from Cove Point import contracts.

Other operations and maintenance increased 28%, 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 $33 million increase due to Dominion Energy Questar Pipeline operations being included for all of 2017;

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

• |  | A $13 million increase in labor and outside service costs associated with Cove Point’s operations affected by the Liquefaction Project.

Depreciation and amortization increased 27%, primarily due to Dominion Energy Questar Pipeline operations being included for all of 2017 ($40 million) and various growth projects being placed into service ($9 million).

Other taxes increased 21%, primarily due to Dominion Energy Questar Pipeline operations being included for all of 2017.

Impairment of assets and related charges increased $15 million, primarily due to a charge to write-off the balance of a regulatory asset no longer considered probable of recovery.

Gains on sales of assets increased 59%, primarily due to increased gains from agreements to convey shale development rights underneath several natural gas storage fields.

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Other income increased 44%, primarily due to an increase in AFUDC associated with rate-regulated projects ($14 million) and an increase in the non-service cost components of pension and other postretirement employee benefit credits ($8 million), 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 $262 million, primarily due to the benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate ($246 million) and lower pre-tax income ($11 million).

LIQUIDITY AND CAPITAL RESOURCES

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

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

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

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

Operating Cash Flows

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

Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In December 2018, Dominion Energy’s Board of Directors established an annual dividend rate for 2019 of $3.67 per share of common stock, a 10.0% increase over the 2018 rate. Dividends are subject to declaration by the Board of Directors. In January 2019, Dominion Energy’s Board of Directors declared dividends payable in March 2019 of 91.75 cents per share of common stock.

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

Credit Risk

Dominion Energy’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion Energy’s credit exposure as of December 31, 2018 for these

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activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.

|  | Gross Credit Exposure |  |  | Credit Collateral |  |  | Net Credit Exposure |
(millions) |  |  |  |  |  |  |  |  |
Investment grade(1) |  | $ | 101 |  |  | $ | 4 |  |  | $ | 97 |
Non-investment grade(2) |  |  | 1 |  |  |  | — |  |  |  | 1 |
No external ratings: |  |  |  |  |  |  |  |  |  |  |  |
Internally rated—investment grade(3) |  |  | 3 |  |  |  | — |  |  |  | 3 |
Internally rated—non-investment grade(4) |  |  | 44 |  |  |  | — |  |  |  | 44 |
Total |  | $ | 149 |  |  | $ | 4 |  |  | $ | 145 |

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

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

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

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

Investing Cash Flows

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

Financing Cash Flows and Liquidity

Dominion Energy relies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by its operations. As discussed in Credit Ratings, Dominion Energy’s ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.

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

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

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

Credit Facilities and Short-Term Debt

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

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

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

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

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

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

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

In November 2017, Dominion Energy filed an SEC shelf registration statement for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability InvestmentSM. The registration limits the principal amount that may be outstanding at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. The balance as of December 31, 2018 was $10 million. The notes are short-term debt obligations on Dominion Energy’s Consolidated Balance Sheets. The proceeds will be used for general corporate purposes and to repay debt.

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

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

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

Long-Term Debt

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any and all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of $1.0 billion. SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer.

Noncontrolling Interest in Dominion Energy Midstream

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

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

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prior to the closing, each Series A Preferred Unit representing limited partner interests in Dominion Energy Midstream was converted into common units representing limited partner interests in Dominion Energy Midstream in accordance with the terms of Dominion Energy Midstream’s partnership agreement.

Issuance of Common Stock and Other Equity Securities

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

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

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

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

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

Repurchase of Common Stock

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

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Dominion Energy believes that its current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to Dominion Energy may affect its ability to access these funding sources or cause an increase in the return required by investors. Dominion Energy’s credit ratings affect its liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which it is able to offer its debt securities.

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

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

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

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

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

(2) | Securities have an interest deferral feature.

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

Debt Covenants

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

Some of the typical covenants include:

| • |  | The timely payment of principal and interest;

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

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

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

| • |  | Limitations on liens.

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

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

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

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

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

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

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

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

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

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

Dividend Restrictions

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

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

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

Contractual Obligations

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

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

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

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

(3) | Includes interest payments over the terms of the debt and payments on related stock purchase contracts. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2018 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 17 to the Consolidated Financial Statements. Does not reflect Dominion Energy’s

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| ability to defer interest and stock purchase contract payments on certain junior subordinated notes or RSNs and equity units, initially in the form of Corporate Units.

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

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

(6) | Excludes regulatory liabilities, AROs and employee benefit plan obligations, which are not contractually fixed as to timing and amount. See Notes 12, 14 and 21 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $29 million of income taxes payable associated with unrecognized tax benefits are excluded. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 5 to the Consolidated Financial Statements.

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

Planned Capital Expenditures

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

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

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

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

Use of Off-Balance Sheet Arrangements

Leasing Arrangement

In July 2016, Dominion Energy signed an agreement with a lessor to construct and lease a new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $365 million, to fund the estimated project costs. The project is expected to be completed by mid-2019. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $281 million as of December 31, 2018. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 89.9% of the then funded amount. For specific full recourse events, Dominion Energy could be required to pay up to 100% of the then funded amount.

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

The respective transactions have been structured so that Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. In accordance with revised accounting guidance pertaining to the recognition, measurement, presentation and disclosure of leasing arrangements, which is effective in January 2019, Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.

Guarantees

Dominion Energy primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the provisions of FASB guidance that dictate a guarantor’s accounting and disclosure requirements for guarantees, including indirect guarantees of indebtedness of others. In addition, Dominion Energy has provided a guarantee to support a portion of Atlantic

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Coast Pipeline’s obligation under a $3.4 billion revolving credit facility. See Note 22 to the Consolidated Financial Statements for additional information, which information is incorporated herein by reference.

FUTURE ISSUES AND OTHER MATTERS

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

Environmental Matters

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

Environmental Protection and Monitoring Expenditures

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

Future Environmental Regulations

Air

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

Climate Change

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

State Actions Related to Air and GHG Emissions

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

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

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PHMSA Regulation

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

Dodd-Frank Act

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

Virginia Legislation

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

Atlantic Coast Pipeline

In September 2014, Dominion Energy, along with Duke and Southern Company Gas, announced the formation of Atlantic Coast Pipeline. Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. During the third and fourth quarters of 2018, a FERC stop work order together with delays in obtaining permits necessary for construction and delays in construction due to judicial actions impacted the cost and schedule for the project. As a result project cost estimates have increased from between $6.0 billion to $6.5 billion to between $7.0 billion to $7.5 billion, excluding financing costs. Atlantic Coast Pipeline expects to achieve a late 2020 in-service date for at least key segments of the project, while the remainder may extend into early 2021. Alternatively, if it takes longer to resolve the judicial issues, such as through appeal to the Supreme Court of the U.S., full in-service could extend to the end of 2021 with total project cost estimated to increase an additional $250 million, resulting in total project cost estimates of $7.25 billion to $7.75 billion excluding financing costs. Abnormal weather, work delays (including due to judicial or regulatory action) and other conditions may result in further cost or schedule modifications in the future, which could result in a material impact to Dominion Energy’s cash flows, financial position and/or results of operations.

North Anna

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

Other Matters

While management currently has no plans which may affect the carrying value of Millstone, based on potential future economic and other factors, including, but not limited to, market power prices, results of capacity auctions, legislative and regulatory solutions to ensure nuclear plants are fairly compensated for their carbon-free generation, and the impact of potential EPA carbon rules; there is risk that Millstone may be evaluated for an early retirement date. Should management make any decision on a potential early retirement date, the precise date and the resulting financial statement impacts, which could be material to Dominion Energy, may be

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affected by a number of factors, including any potential regulatory or legislative solutions, results of any transmission system reliability study assessments and decommissioning requirements, among other factors.

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