Exhibit 99.2

Glossary of Terms

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

Abbreviation or Acronym	Definition
2014 Equity Units	Dominion Energy’s 2014 Series A Equity Units issued in July 2014
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
AMR	Automated meter reading program deployed by East Ohio
AOCI	Accumulated other comprehensive income (loss)
ARO	Asset retirement obligation
Atlantic Coast Pipeline	Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion Energy, Duke and Southern Company Gas
bcf	Billion cubic feet
Blue Racer	Blue Racer Midstream, LLC, a joint venture between Dominion Energy and Caiman
CAA	Clean Air 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
DETI	Dominion Energy Transmission, 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 operating segment, or the entirety of Dominion Energy Midstream Partners, LP and its consolidated subsidiaries
Dominion Energy Questar	The legal entity, Dominion Energy Questar Corporation, one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion Energy Questar Corporation and its consolidated subsidiaries
Dominion Energy Questar Combination	Dominion Energy’s acquisition of Dominion Energy Questar completed on September 16, 2016 pursuant to the terms of the agreement and plan of merger entered on January 31, 2016
Dominion Energy Questar Pipeline	Dominion Energy Questar Pipeline, LLC (formerly known as Questar Pipeline, LLC), one or more of its consolidated subsidiaries, or the entirety of Dominion Energy Questar Pipeline, LLC and its consolidated subsidiaries
East Ohio	The East Ohio Gas Company, doing business as Dominion Energy Ohio
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings Ltd.
FTRs	Financial transmission rights
Gas Infrastructure	Gas Infrastructure Group operating segment
GHG	Greenhouse gas
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.
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

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Abbreviation or Acronym	Definition
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
MWh	Megawatt hour
NGL	Natural gas liquid
NOX	Nitrogen oxide
Order 1000	Order issued by FERC adopting new requirements for electric transmission planning, cost allocation and development
PHMSA	Pipeline and Hazardous Materials Safety Administration
PIR	Pipeline Infrastructure Replacement program deployed by East Ohio
PJM	PJM Interconnection, L.L.C.
Power Delivery	Power Delivery Group operating segment
Power Generation	Power Generation Group operating segment
Questar Gas	Questar Gas Company
RCC	Replacement Capital Covenant
Regulation Act	Legislation effective July 1, 2007, that amended the Virginia Electric Utility Restructuring Act and fuel factor statute, which legislation is also known as the Virginia Electric Utility Regulation Act, as amended in 2015
RGGI	Regional Greenhouse Gas Initiative
RSN	Remarketable subordinated note
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
SCE&G	South Carolina Electric & Gas Company, a wholly-owned subsidiary of SCANA
SEC	Securities and Exchange Commission
September 2006 hybrids	Dominion Energy’s 2006 Series B Enhanced Junior Subordinated Notes due 2066
Standard & Poor’s	Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.
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
Wexpro	The legal entity, Wexpro Company, one or more of its consolidated subsidiaries, or the entirety of Wexpro 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’s and Dominion Energy Gas’ results of operations. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. Virginia Power and Dominion Energy Gas meet the conditions to file under the reduced disclosure format, and therefore have omitted certain sections of MD&A.

CONTENTS OF MD&A

MD&A consists of the following information:

• Forward-Looking Statements

• Accounting Matters—Dominion Energy

• Dominion Energy

• Results of Operations

• Segment Results of Operations

• Virginia Power

• Results of Operations

• Dominion Energy Gas

• Results of Operations

• Liquidity and Capital Resources—Dominion Energy

• Future Issues and Other Matters—Dominion Energy

FORWARD-LOOKING STATEMENTS

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

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

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

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

• Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations, including provisions of the 2017 Tax Reform Act that take effect beginning in 2018;

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

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

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

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

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

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

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

• Counterparty credit and performance risk;

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

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

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

• Fluctuations in interest rates or foreign currency exchange rates;

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

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

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

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

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

• The expected timing and likelihood of completion of the proposed acquisition of SCANA, including the ability to obtain the requisite approvals of SCANA’s shareholders and the terms and condition of any regulatory approvals;

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

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

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

• Political and economic conditions, including inflation and deflation;

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

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

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

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

• Competition in the development, construction and ownership of certain electric transmission facilities in Virginia Power’s service territory in connection with FERC Order 1000;

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

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

• Changes in operating, maintenance and construction costs;

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

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

• Adverse outcomes in litigation matters or regulatory proceedings; and

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

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

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

ACCOUNTING MATTERS

Critical Accounting Policies and Estimates

Dominion Energy has identified the following accounting policies, including certain inherent estimates, that as a result of the

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

ACCOUNTING FOR REGULATED OPERATIONS

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

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

ASSET RETIREMENT OBLIGATIONS

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

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

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

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

INCOME TAXES

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

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

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

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

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

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

ACCOUNTING FOR DERIVATIVE CONTRACTS AND FINANCIAL INSTRUMENTS AT FAIR VALUE

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

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

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

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

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

USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING

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

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

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

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

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

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

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

EMPLOYEE BENEFIT PLANS

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

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

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

• Expected inflation and risk-free interest rate assumptions;

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

• Expected future risk premiums, asset volatilities and correlations;

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

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

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

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

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

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

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

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

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

				Increase in Net Periodic Cost
	Change in Actuarial Assumption			Pension Benefits		Other Postretirement Benefits
(millions, except percentages)
Discount rate		(0.25	)%		$20		$  3
Long-term rate of return on plan assets		(0.25	)%		19		4
Healthcare cost trend rate		1	%		N/A		24

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

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

New Accounting Standards

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

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

Dominion Energy

RESULTS OF OPERATIONS

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

Year Ended December 31,	2017		$ Change		2016		$ Change		2015
(millions, except EPS)
Net income attributable to Dominion Energy	$	2,999		$ 876	$	2,123		$ 224	$	1,899
Diluted EPS		4.72		1.28		3.44		0.24		3.20

Overview

2017 VS. 2016

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

2016 VS. 2015

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

Analysis of Consolidated Operations

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

Year Ended December 31,	2017			$ Change			2016		$ Change			2015
(millions)
Operating Revenue	$	12,586			$ 849		$	11,737		$   54		$	11,683
Electric fuel and other energy-related purchases		2,301			(32	)		2,333		(392	)		2,725
Purchased electric capacity		6			(93	)		99		(231	)		330
Purchased gas		701			242			459		(92	)		551
Net Revenue		9,578			732			8,846		769			8,077
Other operations and maintenance		3,068			(175)			3,243		532			2,711
Depreciation, depletion and amortization		1,905			346			1,559		164			1,395
Other taxes		668			72			596		45			551
Other income		358			(71	)		429		117			312
Interest and related charges		1,205			195			1,010		106			904
Income tax expense (benefit)		(30	)		(685	)		655		(250	)		905

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

2017 VS. 2016

Net revenue increased 8%, primarily reflecting:

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

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

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

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

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

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

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

These increases were partially offset by:

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

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

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

Other operations and maintenance decreased 5%, primarily reflecting:

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

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

• A $78 million benefit from the sale of certain assets associated with nonregulated retail energy marketing operations;

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

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

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

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

• A $36 million increase in outage costs; and

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

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

8

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

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

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

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

2016 VS. 2015

Net revenue increased 10%, primarily reflecting:

• A $544 million increase from electric utility operations, primarily reflecting:

• A $225 million electric capacity benefit, primarily due to the new PJM capacity performance market effective June 2016 ($155 million) and the expiration of non-utility generator contracts in 2015 ($58 million);

• An increase from rate adjustment clauses ($183 million); and

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

• A $305 million increase due to the Dominion Energy Questar Combination.

These increases were partially offset by:

• A $47 million decrease from merchant generation operations, primarily due to lower realized prices at certain merchant generation facilities ($64 million) and an increase in planned and unplanned outage days in 2016 ($26 million), partially offset by additional solar generating facilities placed into service ($37 million);

• A $19 million decrease from regulated natural gas transmission operations, primarily due to:

• A $14 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($28 million), increased fuel costs ($13 million), contract rate changes ($11 million) and decreased revenue from gathering and extraction services ($8 million), partially offset by expansion projects placed in service ($18 million) and increased regulated gas sales ($20 million); and

• A $17 million decrease in NGL activities, due to decreased prices ($15 million) and volumes ($2 million); partially offset by

• A $12 million increase in other revenues, primarily due to an increase in services performed for Atlantic Coast Pipeline ($21 million), partially offset by decreased amor-

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

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

Other operations and maintenance increased 20%, primarily reflecting:

• A $148 million increase due to the Dominion Energy Questar Combination, including $58 million of transaction and transition costs;

• A $98 million increase in charges related to future ash pond and landfill closure costs at certain utility generation facilities;

• A $79 million increase in salaries, wages and benefits;

• A $78 million decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields;

• Organizational design initiative costs ($64 million);

• A $50 million increase in storm damage and service restoration costs, including $23 million for Hurricane Matthew;

• A $20 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income; and

• A $16 million increase due to labor contract renegotiations as well as costs resulting from a union workforce temporary work stoppage; partially offset by

• A $26 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income.

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

Other income increased 38%, primarily due to an increase in the non-service cost components of pension and other postretirement employee benefit credits ($63 million), an increase in earnings from equity method investments ($55 million) and an increase in AFUDC associated with rate-regulated projects ($12 million), partially offset by lower realized gains (net of investment income) on nuclear decommissioning trust funds ($19 million).

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

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

Outlook

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

9

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

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

• Absence of a benefit from remeasurement of deferred income taxes from the 2017 Tax Reform Act;

• Reduction of solar investment tax credits;

• Increases in interest and related charges;

• An increase in depreciation, depletion, and amortization; and

• Share dilution.

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

• Revenues from the Liquefaction Project;

• A return to normal weather in its electric utility operations;

• Growth in weather-normalized electric utility sales of approximately 1.5%;

• Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue;

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

• Absence of additional refueling outages at Millstone; and

• A lower effective tax rate, driven by the tax reform.

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

SEGMENT RESULTS OF OPERATIONS

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

Year Ended December 31,	2017				2016						2015
	Net Income attributable to Dominion Energy		Diluted EPS		Net Income attributable to Dominion Energy			Diluted EPS			Net Income attributable to Dominion Energy			Diluted EPS
(millions, except EPS)
Power Delivery		$   531		$0.83		$   484			$ 0.78			$   490			$ 0.82
Power Generation		1,181		1.86		1,397			2.26			1,120			1.89
Gas Infrastructure		898		1.41		726			1.18			680			1.15
Primary operating segments		2,610		4.10		2,607			4.22			2,290			3.86
Corporate and Other		389		0.62		(484	)		(0.78	)		(391	)		(0.66	)
Consolidated		$2,999		$4.72		$2,123			$ 3.44			$1,899			$ 3.20

Power Delivery

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

Year Ended December 31,	2017		% Change			2016		% Change			2015
Electricity delivered (million MWh)		83.4		—	%		83.7		—	%		83.9
Degree days:
Cooling		1,801		(2	)		1,830		(1	)		1,849
Heating		3,104		(10	)		3,446		1			3,416
Average electric distribution customer accounts (thousands)(1)		2,574		1			2,549		1			2,525

(1) Period average.

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

2017 VS. 2016

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

2016 VS. 2015

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather		$  (1	)		$    —
Other		1			—
FERC transmission equity return		41			0.07
Storm damage and service restoration		(16	)		(0.03	)
Depreciation and amortization		(10	)		(0.02	)
AFUDC return		(8	)		(0.01	)
Interest expense		(5	)		(0.01	)
Other		(8	)		(0.01	)
Share dilution		—			(0.03	)
Change in net income contribution		$  (6	)		$(0.04	)

Power Generation

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

Year Ended December 31,	2017		% Change			2016		% Change			2015
Electricity supplied (million MWh):
Utility		85.0		(3	)%		87.9		3	%		85.2
Merchant		28.9		—			28.9		7			26.9
Degree days (electric utility service area):
Cooling		1,801		(2	)		1,830		(1	)		1,849
Heating		3,104		(10	)		3,446		1			3,416

10

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

2017 VS. 2016

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

2016 VS. 2015

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather		$    2			$    —
Other		13			0.02
Renewable energy investment tax credits		186			0.31
Electric capacity		137			0.23
Merchant generation margin		(34	)		(0.06	)
Rate adjustment clause equity return		24			0.04
Noncontrolling interest(1)		(28	)		(0.05	)
Depreciation and amortization		(25	)		(0.04	)
Other		2			0.01
Share dilution		—			(0.09	)
Change in net income contribution		$277			$ 0.37

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

Gas Infrastructure

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

Year Ended December 31,	2017		% Change			2016			% Change			2015
Gas distribution throughput (bcf)(1):
Sales		130		113	%		61			126	%		27
Transportation		654		22			537			14			470
Heating degree days (gas distribution service area):
Eastern region		4,930		(6	)		5,235			(8	)		5,666
Western region(1)		4,892		161			1,876			100			—
Average gas distribution customer accounts (thousands)(1)(2):
Sales		1,240		—			1,234	(3)		414			240
Transportation		1,086		1			1,071			1			1,057
Average retail energy marketing customer accounts (thousands)(2)		1,405		2			1,376			6			1,296

(1) Includes Dominion Energy Questar effective September 2016.

(2) Period average.

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

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

2017 VS. 2016

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

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

2016 VS. 2015

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Gas distribution margin:
Weather		$  (4	)		$(0.01	)
Rate adjustment clauses		11			0.02
Other		6			0.01
Assignment of shale development rights		(48	)		(0.08	)
Dominion Energy Questar Combination		78			0.13
Other		3			0.01
Share dilution		—			(0.05	)
Change in net income contribution		$ 46			$ 0.03

Corporate and Other

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

Year Ended December 31,	2017			2016			2015
(millions, except EPS amounts)
Specific items attributable to operating segments		$ 861			$ (180	)		$ (136	)
Specific items attributable to Corporate and Other segment		(151	)		(44	)		(5	)
Total specific items		710			(224	)		(141	)
Other corporate operations		(321	)		(260	)		(250	)
Total net expense		$ 389			$ (484)			$ (391	)
EPS impact		$0.62			$(0.78)			$(0.66	)

TOTAL SPECIFIC ITEMS

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

11

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

VIRGINIA POWER

RESULTS OF OPERATIONS

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

Year Ended December 31,	2017		$ Change		2016		$ Change		2015
(millions)
Net Income		$1,540		$322		$1,218		$131	$	1,087

Overview

2017 VS. 2016

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

2016 VS. 2015

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

Analysis of Consolidated Operations

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

Year Ended December 31,	2017		$ Change			2016		$ Change			2015
(millions)
Operating Revenue	$	7,556		$ (32	)	$	7,588		$ (34	)	$	7,622
Electric fuel and other energy-related purchases		1,909		(64	)		1,973		(347	)		2,320
Purchased electric capacity		6		(93	)		99		(231	)		330
Net Revenue		5,641		125			5,516		544			4,972
Other operations and maintenance		1,478		(379	)		1,857		223			1,634
Depreciation and amortization		1,141		116			1,025		72			953
Other taxes		290		6			284		20			264
Other income		76		20			56		(12	)		68
Interest and related charges		494		33			461		18			443
Income tax expense		774		47			727		68			659

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

2017 VS. 2016

Net revenue increased 2%, primarily reflecting:

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

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

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

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

Other operations and maintenance decreased 20%, primarily reflecting:

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

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

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

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

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

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

Other income increased 36%, primarily reflecting:

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

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

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

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

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

2016 VS. 2015

Net revenue increased 11%, primarily reflecting:

• A $225 million electric capacity benefit, primarily due to the new PJM capacity performance market effective June 2016 ($155 million) and the expiration of non-utility generator contracts in 2015 ($58 million);

• An increase from rate adjustment clauses ($183 million); and

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

Other operations and maintenance increased 14%, primarily reflecting:

• A $98 million increase in charges related to future ash pond and landfill closure costs at certain utility generation facilities;

• A $50 million increase in storm damage and service restoration costs, including $23 million for Hurricane Matthew;

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

• Organizational design initiative costs ($32 million).

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

12

DOMINION ENERGY GAS

RESULTS OF OPERATIONS

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

Year Ended December 31,	2017		$ Change		2016		$ Change			2015
(millions)
Net Income	$	615		$223	$	392		$(65	)	$	457

Overview

2017 VS. 2016

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

2016 VS. 2015

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

Analysis of Consolidated Operations

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

Year Ended December 31,	2017		$ Change			2016		$ Change			2015
(millions)
Operating Revenue	$	1,814		$ 176		$	1,638		$(78	)	$	1,716
Purchased gas		132		23			109		(24	)		133
Other energy-related purchases		21		9			12		(9	)		21
Net Revenue		1,661		144			1,517		(45	)		1,562
Other operations and maintenance		611		61			550		98			452
Depreciation and amortization		227		23			204		(13	)		217
Other taxes		185		15			170		4			166
Earnings from equity method investee		21		—			21		(2	)		23
Other income		104		17			87		24			63
Interest and related charges		97		3			94		21			73
Income tax expense		51		(164	)		215		(68	)		283

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

2017 VS. 2016

Net revenue increased 9%, primarily reflecting:

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

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

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

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

Other operations and maintenance increased 11%, primarily reflecting:

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

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

• A $15 million increase due to a charge to write-off the balance of a regulatory asset no longer considered probable of recovery; and

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

• A $25 million increase in gains from agreements to convey shale development rights underneath several natural gas storage fields.

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

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

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

2016 VS. 2015

Net revenue decreased 3%, primarily reflecting:

• A $34 million decrease from regulated natural gas transmission operations, primarily reflecting:

• A $36 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($28 million), increased fuel costs ($13 million), contract rate changes ($11 million) and decreased revenue from gathering and extraction services ($8 million), partially offset by increased regulated gas sales ($16 million) and expansion projects placed in service ($9 million); and

• An $18 million decrease from NGL activities, due to decreased prices ($16 million) and volumes ($2 million); partially offset by

• A $21 million increase in services performed for Atlantic Coast Pipeline; and

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

• A decrease in rate adjustment clause revenue related to low income assistance programs ($26 million); and

• A $9 million decrease in other revenue primarily due to a decrease in pooling and metering activities ($3 million), a decrease in Blue Racer management fees ($3 million) and a decrease in gathering activities ($2 million); partially offset by

• An $18 million increase in AMR and PIR program revenues; and

• An $8 million increase in off-system sales.

13

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

Other operations and maintenance increased 22%, primarily reflecting:

• A $78 million decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields;

• A $20 million increase in salaries, wages and benefits; and

• A $20 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income; partially offset by;

• A $26 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income.

Other income increased 38%, primarily due to an increase in the non-service cost components of pension and other postretirement employee benefit credits ($14 million), a gain on the sale of 0.65% of the noncontrolling partnership interest in Iroquois ($5 million) and an increase in AFUDC associated with rate-regulated projects ($5 million).

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

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

LIQUIDITY AND CAPITAL RESOURCES

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

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

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

Year Ended December 31,	2017			2016			2015
(millions)
Cash, restricted cash and equivalents at beginning of year	$	322		$	632		$	337
Cash flows provided by (used in):
Operating activities		4,502			4,151			4,491
Investing activities		(5,942	)		(10,691	)		(6,513	)
Financing activities		1,303			6,230			2,317
Net increase (decrease) in cash, restricted cash and equivalents		(137	)		(310	)		295
Cash, restricted cash and equivalents at end of year	$	185		$	322		$	632

Operating Cash Flows

Net cash provided by Dominion Energy’s operating activities increased $351 million, primarily due to the operations acquired in the Dominion Energy Questar combination being included for all of 2017, derivative activities, and lower income tax payments,

partially offset by lower deferred fuel cost recoveries in the Virginia jurisdiction, higher interest expense, lower revenue from Cove Point’s import contracts and higher pension and postretirement benefit payments and funding.

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

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

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

CREDIT RISK

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

	Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade(1)		$19		$—		$19
Non-investment grade(2)		8		—		8
No external ratings:
Internally rated-investment grade(3)		5		—		5
Internally rated-non-investment grade(4)		63		—		63
Total		$95		$—		$95

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

(2) The five largest counterparty exposures, combined, for this category represented approximately 7% of the total net credit exposure.

(3) The five largest counterparty exposures, combined, for this category represented approximately 5% of the total net credit exposure.

(4) The five largest counterparty exposures, combined, for this category represented approximately 38% of the total net credit exposure.

Investing Cash Flows

Net cash used in Dominion Energy’s investing activities decreased $4.7 billion, primarily due to the absence of the acquisition of

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Dominion Energy Questar and decreases in plant construction and other property additions, partially offset by an increase in acquisitions of solar development projects and increased contributions to Atlantic Coast Pipeline.

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 provided by Dominion Energy’s financing activities decreased $4.9 billion, primarily due to the absence of issuances of debt, common stock, and Dominion Energy Midstream common and convertible preferred units utilized to finance the Dominion Energy Questar Combination in 2016.

CREDIT FACILITIES AND SHORT-TERM DEBT

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

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

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

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

(1) These credit facilities mature in April 2020 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

(2) The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s credit facilities was 1.61% at December 31, 2017.

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

In February 2018, Dominion Energy borrowed $950 million under a 364-Day Term Loan Agreement that bears interest at a variable rate. In addition, the agreement contains a maximum allowed total debt to total capital ratio of 67.5%. The proceeds were used for general corporate purposes and to repay debt.

In July 2017, Dominion Energy Questar repaid a $250 million variable rate term loan due in August 2017 at the amount of principal then outstanding plus accrued interest.

In November 2017, Dominion Energy filed an SEC shelf registration for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability Investment^SM. The registration limits the principal amount that may be outstanding at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. The balance as of December 31, 2017 was less than $0.1 million. The notes are short-term debt obligations of Dominion Energy and are reflected as short-term debt on Dominion Energy’s Consolidated Balance Sheets. The proceeds will be used for general corporate purposes and to repay debt.

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

LONG-TERM DEBT

During 2017, Dominion Energy issued the following long-term public debt:

Type	Principal		Rate			Maturity
	(millions)
Senior notes	$	400		1.875	%		2019
Senior notes		400		2.750	%		2022
Senior notes		100		3.900	%		2025
Senior notes		750		3.500	%		2027
Senior notes		550		3.800	%		2047
Senior notes		200		2.750	%		2023
Total notes issued	$	2,400

During 2017, Dominion Energy also issued the following long-term private debt:

• In March 2017, Dominion Energy issued through private placement $300 million of 3.496% senior notes that mature in 2024. The proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper.

• In June 2017, Dominion Energy issued through private placement $500 million of variable rate senior notes that mature in 2019. The proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper.

• In November 2017, Questar Gas issued through private placement $100 million of 3.38% senior notes that mature in 2032. The proceeds were used for general corporate purposes and to repay short-term debt.

• In December 2017, Dominion Energy issued through private placement $300 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.

During 2017, Dominion Energy also remarketed the following long-term debt:

• In May 2017, Dominion Energy successfully remarketed the $1.0 billion 2014 Series A 1.50% RSNs due in 2020 pursuant to the terms of the 2014 Equity Units. In connection with the remarketing, the interest rate on the junior subordinated notes was reset to 2.579%. Dominion Energy did not receive any proceeds from the remarketing. See Note 17 to the Consolidated Financial Statements for more information.

During 2017, Dominion Energy also borrowed the following under a term loan agreement:

• In May 2017, Dominion Solar Projects III, Inc. borrowed $280 million under a term loan agreement that bears interest at a variable rate. The term loan amortizes over an 18-year period and matures in May 2024. The debt is nonrecourse to Dominion Energy and is secured by Dominion Solar Projects III, Inc.’s interest in certain solar facilities. The proceeds were used for general corporate purposes.

During 2017, Dominion Energy repaid the following long-term debt:

• In August 2017, Dominion Energy retired its $75 million variable rate Massachusetts Development Finance Agency

Solid Waste Disposal Revenue Bonds, Series 2010B, due in 2041 at the amount of principal then outstanding plus accrued interest.

During 2017, Dominion Energy repaid and repurchased $1.6 billion of long-term debt.

In October 2017, Questar Gas entered into an agreement with certain investors to issue through private placements in April 2018, $50 million of 3.30% 12-year senior notes and $100 million of 3.97% 30-year senior notes. The proceeds will be used for general corporate purposes and to repay short-term 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 for general corporate purposes and to pay maturing long-term debt.

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

During 2017, Dominion Energy issued 4.3 million shares of common stock totaling $335 million through employee savings plans, direct stock purchase and dividend reinvestment plans and other employee and director benefit plans. Dominion Energy received cash proceeds of $302 million from the issuance of 3.8 million of such shares through Dominion Energy Direct^® and employee savings plans. In July 2017, Dominion Energy issued 12.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2014 Equity Units and received proceeds of $1.0 billion.

In January 2018, Dominion Energy issued 6.6 million shares and received cash proceeds of $495 million, net of fees and commissions paid of $5 million through its at-the-market program. See Note 19 to the Consolidated Financial Statements for a description of the at-the-market program.

During 2018, Dominion Energy plans to issue shares for employee savings plans and direct stock purchase and dividend reinvestment plans. In addition, if the merger with SCANA is realized, Dominion Energy would issue 0.6690 shares of Dominion Energy common stock for each share of SCANA common stock outstanding at closing.

REPURCHASE OF COMMON STOCK

Dominion Energy did not repurchase any shares in 2017 and does not plan to repurchase shares during 2018, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which 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

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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 January 2018, Moody’s affirmed Dominion Energy’s senior unsecured debt and commercial paper ratings of Baa2 and P-2, respectively, and Standard & Poor’s affirmed Dominion Energy’s senior unsecured debt and commercial paper ratings of BBB and A-2, respectively. Moody’s and Standard & Poor’s each changed Dominion Energy’s rating outlook to negative from stable. Dominion Energy cannot predict the potential impact the negative outlook at Moody’s and Standard & Poor’s could have on its cost of borrowing.

In January 2018, Fitch affirmed Dominion Energy’s senior unsecured debt and commercial paper ratings of BBB+ and F2, respectively, and maintained its stable outlook for both ratings.

Credit ratings as of February 23, 2018 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

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

(2) Securities have an interest deferral feature.

As of February 23, 2018, Fitch maintained a stable outlook for its respective ratings of Dominion Energy and Moody’s and Standard & Poor’s maintained a negative outlook for their respective ratings of Dominion Energy.

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 filed with the SEC 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 facilities. In addition, Dominion Energy’s credit agreements contain various terms and conditions that could affect its ability to borrow under these facilities. They include maximum debt to total capital ratios and cross-default provisions.

As of December 31, 2017, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:

Company	Maximum Allowed Ratio(1)			Actual  Ratio(2)
Dominion Energy		65	%		62%

(1) The $950 million 364-Day Term Loan Credit Agreement, borrowed in February 2018, has a maximum allowed total debt to total capital ratio of 67.5%. In addition, the $6.0 billion replacement joint revolving credit facility, expected to be executed in the first quarter of 2018, is expected to increase the maximum allowed total debt to total capital ratio from 65% to 67.5%.

(2) 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.

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 facilities, 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 facilities. In addition, if the defaulting company is Virginia Power, Dominion Energy’s obligations to repay any outstanding borrowing under the credit facilities could also be accelerated and the lenders’ commitments to Dominion Energy could terminate.

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

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, 2017, 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, 2017, there have been no events of default under Dominion Energy’s debt covenants.

Dividend Restrictions

Certain agreements associated with Dominion Energy’s credit facilities 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, 2017.

See Note 17 to the Consolidated Financial Statements for a description of potential restrictions on dividend payments by Dominion Energy 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, 2017. 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 2018.

	2018		2019- 2020		2021- 2022		2023 and thereafter		Total
(millions)
Long-term debt(1)	$	3,311	$	6,321	$	3,719	$	20,942	$	34,293
Interest payments(2)		1,349		2,341		1,969		14,556		20,215
Leases(3)		68		119		87		361		635
Purchase obligations(4):
Purchased electric capacity for utility operations		93		113		46		—		252
Fuel commitments for utility operations		1,019		820		364		1,362		3,565
Fuel commitments for nonregulated operations		115		97		110		165		487
Pipeline transportation and storage		389		712		549		2,190		3,840
Other(5)		330		107		28		45		510
Other long-term liabilities(6):
Other contractual obligations(7)		151		107		31		153		442
Total cash payments	$	6,825	$	10,737	$	6,903	$	39,774	$	64,239

(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders. In February 2018, $250 million of Dominion Energy Questar Pipeline’s senior notes were repaid using proceeds from the January 2018 issuance, through private placements, of $100 million and $150 million of senior notes that mature in 2028 and 2038, respectively. As a result, at December 31, 2017, $250 million of senior notes with a 2018 maturity were included in long-term debt in the Consolidated Balance Sheets.

(2) 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, 2017 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 17 to the Consolidated Financial Statements. Does not reflect Dominion Energy’s ability to defer interest and stock purchase contract payments on certain junior subordinated notes or RSNs and equity units, initially in the form of Corporate Units.

(3) Primarily consists of operating leases.

(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, $27 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 $5.5 billion, $5.2 billion and $4.8 billion in 2018, 2019 and 2020, 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 Dominion Energy’s portion of the 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.

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See Power Delivery, Power Generation and Gas Infrastructure -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 2017 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 $139 million as of December 31, 2017. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 89.9% of the then funded amount. For specific full recourse events, Dominion Energy could be required to pay up to 100% of the then funded amount.

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

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. The financial accounting treatment of the lease agreement will be impacted by the new accounting standard issued in February 2016. See Note 2 to the Consolidated Financial Statements for additional information. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.

GUARANTEES

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

addition, Dominion Energy has provided a guarantee to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility. See Note 22 to the Consolidated Financial Statements for additional information, which information is incorporated herein by reference.

FUTURE ISSUES AND OTHER MATTERS

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

Environmental Matters

Dominion Energy is subject to costs resulting from a number of federal, state, tribal 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 $200 million, $394 million and $298 million of expenses (including accretion and depreciation) during, 2017, 2016 and 2015 respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $190 million and $185 million in 2018 and 2019, respectively. In addition, capital expenditures related to environmental controls were $201 million, $191 million, and $94 million for 2017, 2016 and 2015, respectively. These expenditures are expected to be approximately $205 million and $135 million for 2018 and 2019, respectively.

FUTURE ENVIRONMENTAL REGULATIONS

Air

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

In August 2015, the EPA issued final carbon standards for existing fossil fuel power plants. Known as the Clean Power Plan, the rule uses a set of measures for reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units and expanding renewable resources. The final rule has been challenged in the U.S. Court of Appeals for the D.C. Circuit. In February 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan until the disposition of the petitions challenging the rule now before the Court of Appeals, and, if such petitions are filed in the future, before the U.S. Supreme Court. Pursuant to an Executive Order directing the EPA to undertake a review of the Clean Power Plan, the EPA issued a proposed rule in October 2017 to repeal the Clean Power Plan on the basis that the rule promulgated in 2015 exceeds the

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

EPA’s authority under the CAA. In December 2017, the EPA issued an Advanced Notice of Proposed Rulemaking to solicit input on whether it should proceed with a rule to replace the Clean Power Plan, and if so, what the scope of such a rule should be. Given these developments and 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.

In March 2016, the EPA began development of regulations for reducing methane emissions from existing sources in the oil and natural gas sectors. In November 2016, the EPA issued an Information Collection Request to collect information on existing sources upstream of local distribution companies in this sector. In March 2017, the EPA withdrew the information collection request and it remains unclear whether the EPA may propose new regulations on existing sources. Dominion Energy cannot currently estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.

State Actions Related to Air and GHG Emissions

In August 2017, the Ozone Transport Commission released a draft model rule for control of NO_x emissions from natural gas pipeline compressor fuel-fire prime movers. States within the ozone transport region, including states in which Dominion Energy has natural gas operations, are expected to develop reasonably achievable control technology rules for existing sources based on the Ozone Transport Commission model rule. States outside of the Ozone Transport Commission may also consider the model rules in setting new reasonably achievable control technology standards. Several states in which Dominion Energy operates, including Pennsylvania, New York and Maryland, are developing state-specific regulations to control GHG emissions, including methane. In January 2018, the VDEQ published for comment a proposed state carbon regulation program linked to RGGI. Dominion Energy cannot currently estimate the potential financial statements impacts on results of operations, financial condition and/or cash flows related to these matters.

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

PROPOSED GRID TRANSFORMATION AND SECURITY ACT OF 2018

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

In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized return on equity that might have been refunded to customers may be reduced by any prior investment amounts for new solar or wind generation facilities or up to 5,000 MW of new solar or wind generation facilities and electric distribution grid transformation projects that Virginia Power elects to include in a customer credit reinvestment offset. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a customer credit reinvestment offset. Any costs that are the subject of a customer credit reinvestment offset may not be recovered in base rates for the service life of the projects and may not be included in base rates in future triennial review proceedings.

The legislation also includes provisions requiring Virginia Power to provide current customers a one-time bill credit of $200 million and to reduce base rates to reflect reductions in federal tax liability resulting from the enactment of the 2017 Tax Reform Act. The legislation is pending.

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Other Matters

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

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