DOMINION ENERGY, INC - Annual Report: 2017 (Form 10-K)

Item 1. Business

GENERAL

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

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

In March 2014, Dominion Energy formed Dominion Energy Midstream, an MLP designed to grow a portfolio of natural gas terminaling, processing, storage, transportation and related assets. In October 2014, Dominion Energy Midstream launched its initial public offering and issued 20,125,000 common units representing limited partner interests. Dominion Energy has and may continue to investigate opportunities to acquire assets that meet its strategic objective for Dominion Energy Midstream. At December 31, 2017, Dominion Energy owns the general partner, 50.6% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owns a preferred equity interest and the general partner interest in Cove Point, DECG, Dominion Energy Questar Pipeline and a 25.93% noncontrolling partnership interest in Iroquois. Dominion Energy Midstream is consolidated by Dominion Energy, and is an SEC registrant. However, its Form 10-K is filed separately and is not combined herein.

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

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

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

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

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

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

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

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

EMPLOYEES

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

WHERE YOU CAN FIND MORE INFORMATION ABOUT THE COMPANIES

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

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

ACQUISITIONS AND DISPOSITIONS

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

PROPOSED ACQUISITION OF SCANA

Under the terms of the SCANA Merger Agreement announced in January 2018, Dominion Energy has agreed to issue 0.6690 shares of Dominion Energy common stock for each share of SCANA common stock upon closing. In addition, Dominion Energy will provide the financial support for SCE&G to make a $1.3 billion up-front, one-time rate credit to all current electric service customers of SCE&G to be paid within 90 days of closing and a $575 million refund along with the benefit of the 2017 Tax Reform Act resulting in at least a 5% reduction to SCE&G

electric service customers’ bills over an estimated eight-year period as well as the exclusions from rate recovery of approximately $1.7 billion of costs related to the V.C. Summer Units 2 and 3 new nuclear development project and approximately $180 million to purchase the Columbia Energy Center power station. Subject to receipt of SCANA shareholder and any required regulatory approvals and meeting closing conditions, Dominion Energy targets closing by the end of 2018. See Note 3 to the Consolidated Financial Statements for additional information.

ACQUISITION OF DOMINION ENERGY QUESTAR

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

ACQUISITION OF WHOLLY-OWNED MERCHANT SOLAR PROJECTS

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

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

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

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

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

ACQUISITION OF VIRGINIA POWER SOLAR PROJECTS

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

SALE OF CERTAIN RETAIL ENERGY MARKETING ASSETS

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

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

ASSIGNMENT OF TOWER RENTAL PORTFOLIO

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

ACQUISITION OF NON-WHOLLY-OWNED MERCHANT SOLAR PROJECTS

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

SALE OF INTEREST IN MERCHANT SOLAR PROJECTS

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

DOMINION ENERGY MIDSTREAM ACQUISITION OF INTEREST IN IROQUOIS

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

ACQUISITION OF DECG

In January 2015, Dominion Energy completed the acquisition of 100% of the equity interests of DECG from SCANA for $497 million in cash, as adjusted for working capital. In April 2015, Dominion Energy contributed DECG to Dominion Energy Midstream. See Note 3 to the Consolidated Financial Statements for additional information.

ASSIGNMENTS OF SHALE DEVELOPMENT RIGHTS

In December 2013, Dominion Energy Gas closed on agreements with two natural gas producers to convey over time approximately

100,000 acres of Marcellus Shale development rights underneath several natural gas storage fields. The agreements provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from that acreage. In March 2015, Dominion Energy Gas and a natural gas producer closed on an amendment to a December 2013 agreement, which included the immediate conveyance of approximately 9,000 acres of Marcellus Shale development rights and a two-year extension of the term of the original agreement. The conveyance of development rights resulted in the recognition of $43 million of previously deferred revenue. In April 2016, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the immediate conveyance of a 32% partial interest in the remaining approximately 70,000 acres. This conveyance resulted in the recognition of the remaining $35 million of previously deferred revenue. In August 2017, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the finalization of contractual matters on previous conveyances, the conveyance of Dominion Energy Gas’ remaining 68% interest in approximately 70,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. As a result of this amendment, Dominion Energy Gas will receive total consideration of $130 million, with $65 million received in November 2017 and $65 million to be received by the end of the third quarter of 2018 in connection with the final conveyance.

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

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

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

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

SALE OF ELECTRIC RETAIL ENERGY MARKETING BUSINESS

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

SALE OF PIPELINES AND PIPELINE SYSTEMS

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

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

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

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

OPERATING SEGMENTS

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

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

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

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

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

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

Power Delivery

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

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

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

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

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

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

COMPETITION

Power Delivery Operating Segment— Dominion Energy and Virginia Power

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

REGULATION

Power Delivery Operating Segment—Dominion Energy and Virginia Power

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

PROPERTIES

Power Delivery Operating Segment—Dominion Energy and Virginia Power

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

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

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

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

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

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

SOURCES OF ENERGY SUPPLY

Power Delivery Operating Segment—Dominion Energy and Virginia Power

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

SEASONALITY

Power Delivery Operating Segment—Dominion Energy and Virginia Power

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

Power Generation

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

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

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

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

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

COMPETITION

Power Generation Operating Segment—Dominion Energy and Virginia Power

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

Power Generation Operating Segment—Dominion Energy

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

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

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

REGULATION

Power Generation Operating Segment—Dominion Energy and Virginia Power

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

PROPERTIES

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

Power Generation Operating Segment—Dominion Energy and Virginia Power

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

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

Power Generation Operating Segment—Dominion Energy

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

SOURCES OF ENERGY SUPPLY

Power Generation Operating Segment—Dominion Energy and Virginia Power

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

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

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

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

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

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

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

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

Power Generation Operating Segment—Virginia Power

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

SEASONALITY

Power Generation Operating Segment—Dominion Energy and Virginia Power

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

NUCLEAR DECOMMISSIONING

Power Generation Operating Segment—Dominion Energy and Virginia Power

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

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

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

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

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

Power Generation Operating Segment—Dominion Energy

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

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

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

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

Financial Statements for information about nuclear decommissioning trust investments.

Gas Infrastructure

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

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

In September 2016, Dominion Energy completed the Dominion Energy Questar Combination and Dominion Energy Questar, a Rockies-based integrated natural gas company, became a wholly-owned subsidiary of Dominion Energy. Dominion Energy Questar included Questar Gas, Wexpro and Dominion Energy Questar Pipeline at closing. Questar Gas’ regulated gas distribution operations in Utah, southwestern Wyoming and southeastern Idaho includes 29,600 miles of gas distribution pipeline. Wexpro develops and produces natural gas from reserves supplied to Questar Gas under a cost-of-service framework. Dominion Energy Questar Pipeline provides FERC-regulated interstate natural gas transportation and storage services in Utah, Wyoming and western Colorado through 2,200 miles of gas transmission pipeline and 56 bcf of working gas storage. See Acquisitions and Dispositions above and Note 3 to the Consolidated Financial Statements for a description of the Dominion Energy Questar Combination.

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

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

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

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

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

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

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

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

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

COMPETITION

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

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

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

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

Gas Infrastructure Operating Segment—Dominion Energy

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

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

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

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

REGULATION

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

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

Gas Infrastructure Operating Segment—Dominion Energy

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

PROPERTIES AND INVESTMENTS

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

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

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

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

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

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

Gas Infrastructure Operating Segment—Dominion Energy

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

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

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

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

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

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

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

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

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

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

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

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

In September 2014, Dominion Energy, along with Duke and Southern Company Gas, announced the formation of Atlantic Coast Pipeline. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion Energy an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. In October 2016, Dominion Energy purchased an additional 3% membership interest in Atlantic Coast Pipeline from Duke for $14 million. The members hold the following membership interests: Dominion Energy, 48%; Duke, 47%; and Southern Company Gas, 5%. Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, with development and construction costs estimated between $6.0 billion and $6.5 billion, excluding financing costs. In October 2014, Atlantic Coast Pipeline requested approval from FERC to utilize the pre-filing process under which environmental review for the natural gas pipeline project will commence. Atlantic Coast Pipeline filed its FERC application in September 2015 and expects to be in service in late 2019. In October 2017, Atlantic Coast Pipeline received the FERC order authorizing the construction and operation of the project. The FERC order has been appealed to the U.S. Court of Appeals for the Fourth Circuit and the project remains subject to other pending federal and state approvals. See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Atlantic Coast Pipeline.

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

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

SOURCES OF ENERGY SUPPLY

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

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

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

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

SEASONALITY

Gas Infrastructure Operating Segment—Dominion Energy and Dominion Energy Gas

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

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

Corporate and Other

Corporate and Other Segment-Virginia Power and Dominion Energy Gas

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

Corporate and Other Segment-Dominion Energy

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

REGULATION

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

State Regulations

ELECTRIC

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

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

Electric Regulation in Virginia

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

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

In February 2015, the Virginia Governor signed legislation into law which will keep Virginia Power’s base rates unchanged until at least December 1, 2022. In addition, no biennial reviews will be conducted by the Virginia Commission for the five successive 12-month test periods beginning January 1, 2015, and ending December 31, 2019. The legislation states that Virginia Power’s 2015 biennial review, filed in March 2015, would proceed for the sole purpose of reviewing and determining whether any refunds are due to customers based on earnings performance for generation and distribution services during the 2013 and 2014 test periods. In addition the legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utility’s ROE for use in connection with rate adjustment clauses and requires utilities to file integrated resource plans annually rather than biennially. In November 2017, the Virginia Commission approved an ROE of 9.2% for rate adjustment clauses.

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

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

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

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

Electric Regulation in North Carolina

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

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

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

GAS

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

Gas Regulation in Utah, Wyoming and Idaho

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

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

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

Gas Regulation in Ohio

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

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

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

Gas Regulation in West Virginia

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

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

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

Status of Competitive Retail Gas Services

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

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

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

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

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

Federal Regulations

FEDERAL ENERGY REGULATORY COMMISSION

Electric

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

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

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

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

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

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

Gas

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

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

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

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

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

Safety Regulations

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

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

Environmental Regulations

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

AIR

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

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

GLOBAL CLIMATE CHANGE

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

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

WATER

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

WASTE AND CHEMICAL MANAGEMENT

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

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

PROTECTED SPECIES

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

OTHER REGULATIONS

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

Nuclear Regulatory Commission

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

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

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

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

ENVIRONMENTAL STRATEGY

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

Reduction of GHG Emissions

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

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

CLEANER GENERATION

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

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

GHG EMISSIONS

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

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

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

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

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

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

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

Energy Infrastructure Modernization

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

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

for additional information, including natural gas infrastructure projects.

Conservation and Energy Efficiency

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

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

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

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

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

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

CYBERSECURITY

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

Item 1A. Risk Factors

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The SCANA Merger Agreement further provides that Dominion Energy will have the right to refuse to close the merger if there shall have occurred any substantive change in the Base Load Review Act or other laws governing South Carolina public utilities which has or would reasonably be expected to have an adverse effect on SCANA or any of its subsidiaries. There is currently pending before the South Carolina Senate a bill that would make substantive changes to the Base Load Review Act. This bill has passed the South Carolina House of Representatives. If this bill becomes law, Dominion Energy would not be obligated to complete the merger if it is determined that the bill has or would reasonably be expected to have an adverse effect on SCANA or any of its subsidiaries.

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

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

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

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

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

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

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

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

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

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

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

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

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

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

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

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

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

GAS INFRASTRUCTURE

Dominion Energy and Dominion Energy Gas

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

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

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

Dominion Energy

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

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

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

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

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

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

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

POWER DELIVERY

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

POWER GENERATION

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

Item 3. Legal Proceedings

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

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

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

Item 4. Mine Safety Disclosures

Not applicable.