Item 1. Business

OVERVIEW

Dominion Energy Midstream is a growth-oriented Delaware limited partnership formed on March 11, 2014 by Dominion Energy to grow a portfolio of natural gas terminaling, processing, storage, transportation and related assets. Dominion Energy Midstream’s common units began trading on the NYSE on October 15, 2014, under the ticker symbol “DM.” At December 31, 2017, Dominion Energy owned the general partner, 50.6% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream. In connection with the Offering, Dominion Energy Midstream acquired the Preferred Equity Interest and the general partner interest in Cove Point from Dominion Energy.

Cove Point owns and operates the Cove Point LNG Facility and the Cove Point Pipeline. Cove Point has historically generated a significant portion of its revenue and earnings from annual reservation payments under certain regasification, storage and transportation contracts. Upon operational commencement of the Liquefaction Project, the majority of Cove Point’s revenue and earnings will be generated from annual reservation payments under certain terminaling, storage and transportation contracts.

On April 1, 2015, Dominion Energy Midstream acquired from Dominion Energy all of the issued and outstanding membership interests of DECG, an open access, transportation-only interstate pipeline company in South Carolina and southeastern Georgia, for total consideration of $500.8 million. See Note 4 to the Consolidated Financial Statements for additional information regarding this acquisition.

On September 29, 2015, Dominion Energy Midstream acquired NG’s 20.4% and NJNR’s 5.53% partnership interests in Iroquois and, in exchange, Dominion Energy Midstream issued common units representing limited partner interests in Dominion Energy Midstream to both NG and NJNR. The Iroquois investment, accounted for under the equity method, was recorded at $216.5 million. See Note 4 to the Consolidated Financial Statements for additional information regarding this equity method investment.

On December 1, 2016, Dominion Energy Midstream acquired from Dominion Energy all of the issued and outstanding membership interests of Dominion Energy Questar Pipeline, which owns and operates interstate natural gas pipelines and storage facilities in the western U.S., for total consideration of $1.29 billion. See Note 4 to the Consolidated Financial Statements for additional information regarding this acquisition.

Dominion Energy Midstream manages its daily operations through one operating segment, Gas Infrastructure, which consists of gas transportation, LNG terminalling services and storage. In addition to Gas Infrastructure, Dominion Energy Midstream also reports a Corporate and Other segment, which primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the operating segment’s performance or in allocating resources. See Note 25 to the Consolidated Financial Statements for further discussions of Dominion Energy Midstream’s operating segment, which information is incorporated herein by reference.

ASSETS AND OPERATIONS

Dominion Energy Midstream’s ongoing principal sources of cash flow include distributions received from Cove Point from our Preferred Equity Interest, cash generated from the operations of DECG and Dominion Energy Questar Pipeline and distributions received from our noncontrolling partnership interests in Iroquois and White River Hub.

Preferred Equity Interest

One of our primary cash flow generating assets is the Preferred Equity Interest which is entitled to Preferred Return Distributions so long as Cove Point has sufficient cash and undistributed Net Operating Income (determined on a cumulative basis from the closing of the Offering) from which to make Preferred Return Distributions. Preferred Return Distributions will be made on a quarterly basis and will not be cumulative. The Preferred Equity Interest is also entitled to the Additional Return Distributions and should benefit from the expected increased cash flows and income associated with the Liquefaction Project once it is commercially operational.

We believe that Cove Point has generated cash and cumulative Net Operating Income in excess of that required to make Preferred Return Distributions until the Liquefaction Project is commercially operational, expected in March 2018. We expect the cash flows and Net Operating Income from the Liquefaction Project, once commercially operational, to replace and substantially exceed Cove Point’s cash flows and Net Operating Income from its existing import contracts and associated transportation contracts. See description of the Liquefaction Project under Assets and Operations—Cove Point. Until the Liquefaction Project is completed, Cove Point was prohibited from making a distribution on its common equity interests unless it has a distribution reserve sufficient to pay two quarters of Preferred Return Distributions (and two quarters of similar distributions with respect to any other preferred equity interest in Cove Point). Cove Point fully funded this distribution reserve in October 2016, but there can be no assurance that funds will be sufficient for such purpose or that Cove Point will have sufficient cash and undistributed Net Operating Income to permit it to continue to make Preferred Return Distributions. The distribution reserve was fully utilized to fund the quarterly Preferred Return Distributions paid in November 2017 and February 2018. We do not expect to cause Cove Point to make distributions on its common equity, or the Additional Return Distributions, prior to the Liquefaction Project commencing commercial service. No distribution reserve will be established for the Additional Return Distributions.

Cove Point

Cove Point is a Delaware limited partnership, of which Dominion Energy Midstream owns the preferred equity interests and the general partner interest and Dominion Energy owns the common equity interests. Cove Point’s operations currently consist of LNG import and storage services at the Cove Point LNG Facility and the transportation of domestic natural gas and regasified LNG to Mid-Atlantic markets via the Cove Point Pipeline. Following binding commitments from counterparties, Cove Point requested and received regulatory approval to operate the Cove Point LNG

Facility as a bi-directional facility, able to import LNG and regasify it as natural gas or to liquefy domestic natural gas and export it as LNG.

COVE POINT’S IMPORT/STORAGE/REGASIFICATION FACILITIES

The Cove Point LNG Facility includes an offshore pier, LNG storage tanks, regasification facilities and associated equipment required to (i) receive imported LNG from tankers, (ii) store LNG in storage tanks, (iii) regasify LNG and (iv) deliver regasified LNG to the Cove Point Pipeline. The Cove Point LNG Facility has a contractual peak regasification capacity of approximately 1.8 million Dths/day and an aggregate LNG storage capacity of 695,000 cubic meters of LNG, or approximately 14.6 Bcfe, of which approximately 53% was contracted at December 31, 2017. The available capacity reflects the expiration of an agreement with Statoil in 2017. In addition, the Cove Point LNG Facility has an existing liquefier (unrelated to the Liquefaction Project) capable of liquefying approximately 15,000 Dths/day of natural gas. This liquefaction capacity is primarily used to liquefy natural gas received from domestic customers that store LNG in our tanks for use during peak periods of natural gas demand. Cove Point offers both Open Access Services and Non-Open Access Services. Cove Point’s two-berth pier is located approximately 1.1 miles offshore in the Chesapeake Bay. Cove Point operates the Cove Point LNG Facility on an integrated basis with no equipment exclusively used for the benefit of Open Access Services or Non-Open Access Services.

Cove Point currently provides services under (i) long-term agreements with the Import Shippers for an aggregate of 1.0 million Dths/day of firm and off-peak regasification capacity, and (ii) long-term agreements for an aggregate 204,000 Dths/day of firm capacity with the Storage Customers who receive firm peaking services, whereby the Storage Customers deliver domestic natural gas to the Cove Point LNG Facility to be liquefied and stored during the summer for withdrawal on a limited number of days at peak times during the winter. Through December 31, 2016, Cove Point had 800,000 Dths/day of regasification and firm transportation capacity under contract with Statoil, one of the Import Shippers, which decreased to a maximum of 277,650 Dths/day of such capacity through its expiration in the second quarter of 2017. In 2017, the Import Shippers comprised approximately 25% of total consolidated operating revenues for Dominion Energy Midstream. Cove Point’s customers are required to pay fixed monthly charges, regardless of whether they use the amount of capacity they have paid to reserve at the Cove Point LNG Facility. The available storage and most of the transportation capacity of the Cove Point LNG Facility will be utilized in connection with the Liquefaction Project.

COVE POINT’S PIPELINE FACILITIES

The Cove Point Pipeline is a 36-inch diameter bi-directional underground, interstate natural gas pipeline that extends approximately 88 miles from the Cove Point LNG Facility to interconnections with pipelines owned by Transco in Fairfax County, Virginia, and with Columbia Gas Transmission LLC and DETI, both in Loudoun County, Virginia. In 2009, the original pipeline was expanded to include a 36-inch diameter loop that extends approximately 48 miles, roughly 75% of which is parallel to the

original pipeline. Cove Point has two compressor stations, with approximately 30,840 installed compressor horsepower, at its interconnections with the three upstream interstate pipelines. The Loudoun Compressor Station is located at the western end of the Cove Point Pipeline where it interconnects with the pipeline systems of DETI and Columbia Gas Transmission LLC. The Pleasant Valley Compressor Station is located roughly 13 miles to the southeast of the Loudoun Compressor Station, where the Cove Point Pipeline interconnects with Transco’s pipeline system.

Cove Point offers open-access transportation services, including firm transportation, off-peak firm transportation and interruptible transportation, with cost-based rates and terms and conditions that are subject to the jurisdiction of FERC. Firm transportation services are generally provided based on a reservation-based fee that is designed to recover Cove Point’s fixed costs and earn a reasonable return. The firm transportation customers are required to pay fixed monthly fees, regardless of whether they use their reserved capacity for the Cove Point Pipeline. Cove Point also provides certain incrementally priced, firm transportation services that are associated with expansion projects. The Export Customers will be responsible for procuring their own natural gas supplies and transporting such supplies to the Cove Point Pipeline, which serves as the primary method of transportation of natural gas supplies to or from the Cove Point LNG Facilities.

In June 2015, Cove Point executed two binding precedent agreements 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.

COVE POINT’S EXPORT/LIQUEFACTION FACILITIES

The Liquefaction Project, which will consist of one LNG train with a design nameplate outlet capacity of 5.25 Mtpa, is expected to be placed in service in March 2018. Under normal operating conditions and after accounting for maintenance downtime and other losses, the firm contracted capacity for LNG loading onto ships will be approximately 4.6 Mtpa (0.66 Bcfe/day). Cove Point has authorization from the DOE to export up to 0.77 Bcfe/day (approximately 5.75 Mtpa) should the liquefaction facilities perform better than expected. The Liquefaction Project will enable the Cove Point LNG Facility to liquefy domestically produced natural gas and export it as LNG. The Liquefaction Project has been constructed on land already owned by Cove Point, which is within the developed area of the existing Cove Point LNG Facility, and will be integrated with a number of the facilities that are currently operational. Domestic natural gas will be delivered to the Cove Point LNG Facility through the Cove Point Pipeline for liquefaction and will be exported as LNG. The total costs of developing the Liquefaction Project are estimated to be approximately $4.1 billion, excluding financing costs. Through December 31, 2017, Cove Point incurred $4.0 billion of development and construction costs associated with the Liquefaction Project. Dominion Energy has indicated that it intends to provide the funding necessary for the remaining costs for the Liquefaction Project, but it is under no obligation to do so.

Many of the existing facilities at the Cove Point LNG Facility will be used to provide the liquefaction service. The Liquefaction Project will utilize existing storage tanks at the Cove Point LNG

Facility to store LNG produced by the new liquefaction facilities. The Liquefaction Project will utilize the existing off-shore two-berth pier and insulated LNG and gas piping from the pier to the on-shore Cove Point LNG Facility. Cove Point is constructing new facilities to liquefy the natural gas on land it already owns (which encompasses more than 1,000 acres). No change will be made to the Cove Point LNG Facility’s current storage, import, or regasification capabilities and only minor modifications will be made to the Cove Point LNG Facility itself, such as adding piping tie-ins and electrical/control connections to integrate the liquefaction facility with the existing LNG regasification facilities.

COVE POINT’S EXPORT CUSTOMERS

Cove Point has executed service contracts for the Liquefaction Project with the Export Customers, each of which has contracted for 50% of the available capacity. The Export Customers together will have firm access to 6.8 Bcfe of the existing storage capacity, with the balance of the existing storage capacity available for Cove Point’s existing Import Shippers and Storage Customers. The Export Customers have each entered into a 20-year agreement for the liquefaction and export services, which they may annually elect to switch to import services, provided that the other Export Customer agrees to switch. In addition, each of the Export Customers has entered into an accompanying 20-year service agreement for firm transportation on the Cove Point Pipeline.

Upon commercial operation of the Liquefaction Project, a substantial portion of Cove Point’s revenues will be dependent upon the payment of these two customers. Cove Point’s future results and liquidity are primarily dependent upon the payment of the Export Customers under their respective contracts, and on their continued willingness and ability to perform their contractual obligations.

Cove Point will provide terminal services for the Export Customers as a tolling service, and the Export Customers will be responsible for procuring their own natural gas supplies and transporting such supplies to or from the Cove Point LNG Facilities. To deliver the feed gas for liquefaction to the Cove Point LNG Facility, each Export Customer entered into a firm transportation service agreement to utilize the Cove Point Pipeline, with a maximum firm transportation quantity of 430,000 Dths/day for each Export Customer. This amount of firm transportation capacity will enable Export Customers to deliver to the Cove Point LNG Facility the feed gas, including fuel, required on days of peak liquefaction, utilizing both their firm liquefaction rights and an expected level of authorized overrun service. In the event of an election of import/regasification service, each of the Export Customers will have a regasification capacity of 330,000 Dths/day.

DECG

DECG operates as an open access, transportation-only interstate pipeline company in South Carolina and southeastern Georgia. At December 31, 2017, DECG’s natural gas system consisted of nearly 1,500 miles of transmission pipeline of up to 24 inches in diameter and five compressor stations with approximately 34,500 installed compressor horsepower. DECG’s system transports gas to its customers from the transmission systems of Southern Natural Gas Company at Port Wentworth, Georgia and Aiken County,

South Carolina; Southern LNG, Inc. at Elba Island, near Savannah, Georgia; Elba Express Company at Port Wentworth, Georgia; and Transco in Cherokee and Spartanburg counties in South Carolina. All of DECG’s operations are regulated by FERC.

DECG’s customers include SCE&G (which uses natural gas for electricity generation and for gas distribution to retail customers), SCANA Energy Marketing, Inc. (which markets natural gas to industrial and “sale for resale” customers, primarily in the southeastern U.S.), municipalities, county gas authorities, federal and state agencies, marketers, power generators and industrial customers primarily engaged in the manufacturing or processing of ceramics, paper, metal and textiles.

DECG’s revenues are primarily derived from reservation charges for firm services as provided for in its FERC-approved tariff. DECG’s pipeline system has contracted pipeline capacity of approximately 790,073 Dths/day. More than 90% of this capacity is contracted beyond 2019.

In 2014, DECG executed three binding precedent agreements for the approximately $125 million Charleston Project. In February 2017, DECG received FERC authorization to construct and operate the project facilities, which are expected to be placed into service in March 2018. The Charleston Project is supported by long-term contracts with terms ranging from 10 to 30 years.

Dominion Energy Questar Pipeline

Dominion Energy Questar Pipeline owns and operates interstate natural gas pipelines and storage facilities in the western U.S., providing natural gas transportation and underground storage services in Utah, Wyoming and Colorado. Dominion Energy Questar Pipeline’s operations are primarily regulated by FERC. At December 31, 2017, Dominion Energy Questar Pipeline owned and operated nearly 2,200 miles of natural gas transportation pipelines across northeastern and central Utah, northwestern Colorado and southwestern Wyoming. 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 18 transmission and storage compressor stations with approximately 221,200 combined installed compressor horsepower. Dominion Energy Questar Pipeline also owns gathering lines as well as processing facilities near Price, Utah, which provide for dew-point control to meet gas-quality specifications of downstream pipelines. Additionally, Dominion Energy Questar Pipeline owns and operates 50% of White River Hub, an 11-mile FERC-regulated natural gas transportation pipeline in western Colorado, which is accounted for under the equity method.

Dominion Energy Questar Pipeline’s transportation customers include its affiliate, Questar Gas Company, which provides the largest share of transportation revenues, as well as Enterprise Gas Processing, LLC, Rockies Express Pipeline LLC, Citadel Energy Marketing LLC, Wyoming Interstate Company, LLC, Pacificorp, Encana Marketing (USA) Inc. and other unaffiliated end-users, marketers and producers in the Rocky Mountain region. The Dominion Energy Questar Pipeline systems interconnect with several major, unaffiliated natural gas pipeline systems owned by Kern River Gas Transmission Company, Ruby Pipeline, LLC, Rockies Express Pipeline, LLC, Northwest Pipeline, LLC, Wyoming Interstate Company, TransColorado Gas Transmission Company, LLC, and others.

Dominion Energy Questar Pipeline’s transportation revenues are primarily derived from reservation charges for firm services as provided for in its FERC-approved tariff. At December 31, 2017, Dominion Energy Questar Pipeline’s pipeline system had contracted pipeline capacity of approximately 5,787,630 Dths/day. Approximately 16% of that capacity is committed to by Dominion Energy Questar Pipeline’s affiliate, Questar Gas Company. Of the total committed capacity, approximately 14% relates to contracts that expire in 2018, 80% relates to contracts that expire in 2019 or beyond, and the remaining 6% of contracts operate under evergreen contracts that contain customary termination features. Dominion Energy Questar Pipeline expects that the contracts expiring in 2018, including those with Questar Gas Company, will be renewed under similar terms as the existing agreements.

Dominion Energy Questar Pipeline owns four natural gas storage facilities totaling 55.8 Bcf of working gas storage capacity. The Clay Basin storage facility in northeastern Utah has a certificated capacity of 120.2 Bcf, including 54.0 Bcf of working gas. In addition, Dominion Energy Questar Pipeline owns three smaller storage aquifers in northeastern Utah and western Wyoming.

Dominion Energy Questar Pipeline’s natural gas storage customers include its affiliate, Questar Gas Company, which provides the largest share of storage revenues, as well as Puget Sound Energy Inc., Intermountain Gas Company and other unaffiliated customers.

Dominion Energy Questar Pipeline’s natural gas storage revenues are primarily derived from long-term contracts for storage capacity at the Clay Basin storage facility. Approximately 27% of the total storage working gas capacity is contracted with Questar Gas Company. Of the total contracted working gas capacity, 15% of the volumes expire in 2018 while the remaining 85% are contracted through 2019 or beyond. The contracts that expire in 2018 are all expected to be renewed under similar terms as the existing agreements.

In March 2017, Dominion Energy Questar Pipeline committed to upgrade certain facilities and increase capacity, including the Hyrum Project, and entered into agreements to provide firm transportation service to Questar Gas Company, an affiliate, through 2027. Total costs of these projects are expected to be approximately $10 million through 2027.

In December 2017, Dominion Energy Questar Pipeline filed with FERC to convert a portion of existing interruptible storage capacity to firm capacity and increase the minimum required deliverability at the Clay Basin storage facility by the end of 2018. Total costs of this project are estimated to be approximately $5 million.

Iroquois

Iroquois is a Delaware limited partnership which 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. At December 31, 2017,

Dominion Energy Midstream holds a 25.93% noncontrolling partnership interest in Iroquois, which is accounted for under the equity method.

RELATIONSHIP WITH DOMINION ENERGY

We view our relationship with Dominion Energy as a significant competitive strength. We believe this relationship will provide us with potential acquisition opportunities from a broad portfolio of existing midstream assets that meet our strategic objectives, as well as access to personnel with extensive technical expertise and industry relationships. Dominion Energy has granted us a right of first offer with respect to any future sale of its common equity interests in Cove Point. We may also acquire newly issued common equity or additional preferred equity interests in Cove Point in the future, provided that any issuances of additional equity interests in Cove Point would require both our and Dominion Energy’s approval. Any additional equity interests that we acquire in Cove Point would allow us to participate in the significant growth in cash flows and income expected following operational commencement of the Liquefaction Project. In connection with the Offering, Dominion Energy also granted us a right of first offer with respect to any future sale of its indirect ownership interest in Blue Racer, which is a midstream company focused on the Utica Shale formation, and its indirect ownership interest in Atlantic Coast Pipeline, which is focused on constructing a natural gas pipeline running from West Virginia through Virginia to North Carolina. In addition, acquisition opportunities, such as the DECG Acquisition and the Dominion Energy Questar Pipeline Acquisition, may arise from future midstream pipeline, terminaling, processing, transportation and storage assets acquired or constructed by Dominion Energy.

Dominion Energy, headquartered in Richmond, Virginia, 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. At December 31, 2017, Dominion Energy served 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. Dominion Energy’s portfolio of midstream pipeline, terminaling, processing, transportation and storage assets includes its indirect ownership interests in Blue Racer and Atlantic Coast Pipeline, both of which are described in more detail below, and the assets and operations of Dominion Energy Gas and Dominion Energy Questar. Dominion Energy Gas consists primarily of (i) The East Ohio Gas Company d/b/a Dominion Energy Ohio, a regulated natural gas distribution company, (ii) DETI, an interstate natural gas transmission pipeline company, and (iii) Dominion Iroquois, Inc., which holds a 24.07% noncontrolling partnership interest in Iroquois. Dominion Energy Questar consists primarily of Questar Gas Company, a regulated natural gas distribution company, and Wexpro, a natural gas exploration and production company which supplies natural gas to Questar Gas Company under a cost-of-service framework.

Blue Racer is a midstream energy company focused on the design, construction, operation and acquisition of midstream assets. Blue Racer is investing in natural gas gathering and

processing assets in Ohio and West Virginia, targeting primarily the Utica Shale formation, and is an equal partnership between Dominion Energy and Caiman, with Dominion Energy contributing midstream assets, including both gathering and processing 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.

Atlantic Coast Pipeline is a limited liability company owned at December 31, 2017 by 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 to increase natural gas supplies in the region. Construction of the pipeline is subject to receiving all necessary regulatory and other approvals, including without limitation CPCNs from FERC and all required environmental permits. In October 2017, Atlantic Coast Pipeline received the FERC order authorizing the construction and operation of the project, subject to other pending federal and state approvals, with the facilities expected to be in service in late 2019. DETI will provide the services necessary to oversee the construction of, and to subsequently operate and maintain, the facilities and projects undertaken by, and subject to the approval of, Atlantic Coast Pipeline. The pipeline is expected to serve as a new, independent route for transportation of shale and conventional interstate gas supplies for markets in the mid-Atlantic region of the U.S.

At December 31, 2017, Dominion Energy is our largest unitholder, holding 18,504,628 common units (27% of all outstanding), 11,365,628 Series A Preferred Units (38% of all outstanding) and 31,972,789 subordinated units (100% of all outstanding). Dominion Energy also owns our general partner and owns 100% of our IDRs. As a result of its significant ownership interests in us, we believe Dominion Energy will be motivated to support the successful execution of our business strategies and will provide us with acquisition opportunities, although it is under no obligation to do so. Dominion Energy views us as a significant part of its growth strategy, and we believe that Dominion Energy will be incentivized to contribute or sell additional assets to us and to pursue acquisitions jointly with us in the future. However, Dominion Energy will regularly evaluate acquisitions and dispositions and may, subject to compliance with our right of first offer with respect to Cove Point, Blue Racer and Atlantic Coast Pipeline, elect to acquire or dispose of assets in the future without offering us the opportunity to participate in those transactions. Moreover, Dominion Energy will continue to be free to act in a manner that is beneficial to its interests without regard to ours, which may include electing not to present us with future acquisition opportunities.

See Note 22 to the Consolidated Financial Statements for a discussion of the significant contracts entered into with Dominion Energy.

COMPETITION

All of the regasification and storage capacity of the Cove Point LNG Facility, and all of the transportation capacity of the Cove Point Pipeline is either under contract or expected to be utilized by the Liquefaction Project. The Liquefaction Project’s capacity is also fully contracted 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.

DECG’s pipeline system generates a substantial portion of its revenue from long-term firm contracts for transportation services and is therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, 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 Questar Pipeline’s pipeline system generates a substantial portion of its revenue from long-term firm contracts for transportation and storage services and is therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, Dominion Energy Questar Pipeline’s pipeline system and storage facilities face competitive pressures from similar facilities in the Rocky Mountain region in terms of location, rates, terms of service and availability and reliability of service.

REGULATION

Dominion Energy Midstream is subject to regulation by various federal, state and local authorities, including the SEC, FERC, EPA, DOE, DOT and Maryland Commission.

FERC Regulation

The design, construction and operation of interstate natural gas pipelines, LNG terminals (including the Liquefaction Project) and other facilities, the import and export of LNG, and the transportation of natural gas are all subject to various regulations, including the approval of FERC under Section 3 (for LNG terminals) and Section 7 (for interstate transportation facilities) of the NGA, as well as the Natural Gas Policy Act of 1978, as amended, to construct and operate the facilities. For the Cove Point LNG Facility, Cove Point is required to maintain authorization from FERC under Section 3 and Section 7 of the NGA. The design, construction and operation of the Cove Point LNG Facility and its proposed Liquefaction Project, and the import and export of LNG, are highly regulated activities. FERC’s approval under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, are required for the proposed Liquefaction Project. DECG and Dominion Energy Questar Pipeline are required to maintain authorization from FERC under Section 7 of the NGA.

Under the NGA, FERC is granted authority to approve, and if necessary, set “just and reasonable rates” for the transportation, including storage, or sale of natural gas in interstate commerce. In

addition, under the NGA, with respect to the jurisdictional services, we are not permitted to unduly discriminate or grant undue preference as to our rates or the terms and conditions of service. FERC has the authority to grant certificates allowing construction and operation of facilities used in interstate gas transportation and authorizing the provision of services. Under the NGA, FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale in interstate commerce of natural gas for resale for ultimate consumption for domestic, commercial, industrial, or any other use, and to natural gas companies engaged in such transportation or sale. However, FERC’s jurisdiction does not extend to the production or local distribution of natural gas.

In general, FERC’s authority to regulate interstate natural gas pipelines and the services that they provide includes:

In November 2016, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with 23 proposed rates to be effective January 1, 2017. Cove Point proposed an annual cost-of-service of approximately $140 million. In December 2016, FERC accepted a January 1, 2017 effective date for all proposed rates but five which were suspended to be effective June 1, 2017. Under the terms of the settlement agreement filed by Cove Point in August 2017 and approved by FERC in November 2017, Cove Point’s rates effective October 2017 result in decreases to annual revenues and depreciation expense of approximately $17.7 million and $3.0 million, respectively, compared to the rates in effect through December 2016. In addition, to the extent market conditions exist that neither import nor export services are being sufficiently utilized and LNG cooling quantities are required, the Import Shippers’ responsibility for costs incurred for any LNG cooling quantities received prior to the earlier of operational commencement of the Liquefaction Project or March 2018 would be reduced to approximately half of such amounts incurred. If the Liquefaction Project has not commenced operations prior to March 2018 and LNG cooling quantities are required, Cove Point is responsible for any costs incurred until the Liquefaction Project commences operations. Upon operational commencement of the Liquefaction Project, the Import Shippers will have responsibility for costs incurred on certain LNG cooling quantities.

In connection with Dominion Energy’s acquisition of DECG on January 31, 2015, Dominion Energy agreed to a rate moratorium which precludes DECG from filing a Section 4 NGA general rate case to establish base rates that would have been effective prior to January 1, 2018.

LIQUEFACTION PROJECT

In April 2013, Cove Point filed its application with FERC requesting authorization to construct, modify and operate the Liquefaction Project, as well as enhance the Cove Point Pipeline. In May 2014, FERC staff issued its EA for the Liquefaction Project.

In the EA, FERC staff addressed a variety of topics related to the proposed construction and development of the Liquefaction Project and its potential impact to the environment, including in the areas of geology, soils, groundwater, surface waters, wetlands, vegetation, wildlife and aquatic resources, special status species, land use, recreation, socioeconomics, air quality and noise, reliability and safety, and cumulative impacts. In September 2014, Cove Point received the FERC Order which authorized the construction and operation of the Liquefaction Project. In the FERC Order, FERC concluded that if constructed and operated in accordance with Cove Point’s application and supplements, and in compliance with the environmental conditions set forth in the FERC Order, the Liquefaction Project would not constitute a major federal action significantly affecting the quality of the human environment. In October 2014, Cove Point commenced construction of the Liquefaction Project.

Two parties previously separately filed petitions for review of the FERC Order in the U.S. Court of Appeals for the D.C. Circuit, which petitions were consolidated. In July 2016, the court denied one party’s petition for review of the FERC Order. The court also issued a decision remanding the other party’s petition for review of the FERC Order to FERC for further explanation of how FERC’s decision that a previous transaction with an existing import shipper was not unduly discriminatory. In September 2017, FERC issued its order on remand from the U.S. Court of Appeals for the D.C. Circuit, and reaffirmed its rulings in its prior orders that Cove Point did not violate the prohibition against undue discrimination by agreeing to a capacity reduction and early contract termination with the existing import shipper. In October 2017, the party filed a request for rehearing of the FERC Order on remand. This case is pending.

Energy Policy Act of 2005

The EPACT and FERC’s policies promulgated thereunder contain numerous provisions relevant to the natural gas industry and to interstate pipelines. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties. Additionally, the EPACT amended Section 3 of the NGA to establish or clarify FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, although except as specifically provided in the EPACT, nothing in the EPACT is intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals. The EPACT amended the NGA to, among other things, prohibit market manipulation. In accordance with the EPACT, FERC issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud.

DOE Regulation

Prior to importing or exporting LNG, Cove Point must receive approvals from the DOE. Cove Point previously received import authority in connection with the construction and operation of the Cove Point LNG Facility and more recently also received authority to export the commodity.

In October 2011, the DOE granted FTA Authorization for the export of up to 1.0 Bcfe/day of natural gas to countries that have or will enter into an FTA for trade in natural gas. In September 2013, the DOE also granted Non-FTA Authorization approval for the export of up to 0.77 Bcfe/day of natural gas to countries that do not have an FTA for trade in natural gas. The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively. In June 2016, a party filed a petition for review of the DOE’s Non-FTA Authorization approval in the U.S. Court of Appeals for the D.C. Circuit. In November 2017, the U.S. Court of Appeals for the D.C. Circuit issued an order denying the petition for review.

In July 2017, Cove Point submitted an application for a temporary operating permit to the Maryland Department of the Environment, as required prior to the date of first production of LNG for commercial purposes of exporting LNG. The permit was received in December 2017.

DOT Regulation

The Cove Point Pipeline, DECG and Dominion Energy Questar Pipeline are subject to regulation by the DOT, under the PHMSA, pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline and underground natural gas storage facilities. The NGPSA requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections.

The PSIA, which is administered by the DOT Office of Pipeline Safety, governs the areas of testing, education, training and communication. The PSIA requires pipeline companies to perform extensive integrity tests on natural gas transportation pipelines that exist in high population density areas designated as “high consequence areas.” Pipeline companies are required to perform the integrity tests on a seven-year cycle. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. Pipeline operators also must develop integrity management programs for gas transportation pipelines, which requires pipeline operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline, as necessary; and implement preventive and mitigation actions.

The Cove Point Pipeline, DECG and Dominion Energy Questar Pipeline are subject to the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission and underground storage facilities. Our underground natural gas storage facilities are subject to DOT regulation through PHMSA, which oversees the safety, security, monitoring and compliance of such facilities.

State Regulation

The Maryland Commission regulates electricity suppliers, fees for pilotage services to vessels, construction of generating stations and

certain common carriers engaged in the transportation for hire of persons in the state of Maryland. See Note 19 to the Consolidated Financial Statements for additional information.

Worker Health and Safety

Dominion Energy Midstream is subject to a number of federal and state laws and regulations, including OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. Dominion Energy Midstream has an internal safety, health and security program designed to monitor and enforce compliance with worker safety requirements and routinely reviews and considers improvements in its programs. Cove Point is also subject to the U.S. Coast Guard’s Maritime Security Standards for Facilities, which are designed to regulate the security of certain maritime facilities. Dominion Energy Midstream believes that it is in material compliance with all applicable laws and regulations related to worker health and safety. Notwithstanding these preventative measures, incidents may occur, including those outside of Dominion Energy Midstream’s control.

ENVIRONMENTAL REGULATION

General

Dominion Energy Midstream’s operations are subject to stringent, comprehensive and evolving federal, regional, state and local laws and regulations governing environmental protection. These laws and regulations may, among other things, require the acquisition of permits or other approvals to conduct regulated activities, restrict the amounts and types of substances that may be released into the environment, limit operational capacity of the facilities, require the installation of environmental controls, limit or prohibit construction activities in sensitive areas such as wetlands or areas inhabited by endangered or threatened species and impose substantial liabilities for pollution resulting from operations. The cost of complying with applicable environmental laws, regulations and rules is expected to be material. Failure to comply with these laws and regulations may also result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and the issuance of orders enjoining some or all of Dominion Energy Midstream’s operations in affected areas.

Dominion Energy Midstream has applied for or obtained the necessary environmental permits for the construction and operation of its facilities. Many of these permits are subject to reissuance and continuing review. Additional information related to Dominion Energy Midstream’s environmental compliance matters, including current and planned capital expenditures relating to environmental compliance, can be found in Future Issues and Other Matters in Item 7. MD&A.

Air Emissions

The regulation of air emissions under the CAA and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. The CAA new source review regulations require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply

with stringent air permit requirements or install and operate specific equipment or technologies to control emissions. Obtaining necessary air permits has the potential to delay the development of our projects.

The regulation of air emissions under the CAA requires that we obtain various construction and operating permits, including Title V air permits, and incur capital expenditures for the installation of certain air pollution control devices at our facilities. We have taken and expect to continue to take certain measures to comply with various regulations specific to our operations, such as National Emission Standards for Hazardous Air Pollutants, New Source Performance Standards, new source review and federal and state regulatory measures imposed to meet national ambient air quality standards. We have incurred, and expect to continue to incur, substantial capital expenditures to maintain compliance with these and other air emission regulations that have been promulgated or may be promulgated or revised in the future.

Global Climate Change

The national and international attention in recent years on GHG emissions and their relationship to climate change has resulted in federal, regional and state legislative and regulatory action in this area. Dominion Energy Midstream supports national climate change legislation that would provide a consistent, economy-wide approach to addressing this issue and is currently taking action to protect the environment and address climate change while meeting the future needs of its customers. Dominion Energy Midstream’s CEO and its management are responsible for compliance with the laws and regulations governing environmental matters, including climate change.

In response to findings that emissions of GHGs present an endangerment to public health and the environment, the EPA adopted regulations under existing provisions of the CAA in April 2010, that require a reduction in emissions of GHGs from motor vehicles. These rules took effect in January 2011 and established GHG emissions as regulated pollutants under the CAA. In June 2014, the U.S. Supreme Court ruled that the EPA lacked the authority under the CAA to require PSD or Title V permits for stationary sources based solely on GHG emissions. However, the Court upheld the EPA’s ability to require best available control technology for GHG for sources that are otherwise subject to PSD or Title V permitting for conventional pollutants. In August 2016, the EPA issued a draft rule proposing to reaffirm that a GHG source’s obligation to obtain a PSD or Title V permit for GHG’s is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the new source review program, and to set a significant emissions rate at 75,000 tons per year of CO₂ equivalent emissions under which a source would not be required to apply best available control technology for its GHG emissions. Due to uncertainty regarding what additional actions states may take to amend their existing regulations and what action the EPA ultimately takes to address the court ruling under a new rulemaking, we cannot predict the impact to the financial statements at this time.

In January 2015, as part of its Climate Action Plan, the EPA announced plans to reduce methane emissions from the oil and gas sector including natural gas processing and transmission sources. In July 2015, the EPA announced the next generation of its

voluntary Natural Gas Star Program. The program covers the entire natural gas sector from production to distribution, with more emphasis on transparency and increased reporting for both annual emissions and reductions achieved through implementation measures. DECG joined the EPA’s voluntary Natural Gas Star Program in July 2016 and submitted an implementation plan in September 2016.

Maryland, along with eight other Northeast states, has implemented regulations requiring reductions in CO₂ emissions through the RGGI, a cap and trade program covering CO₂ emissions from electric generating units in the Northeast. The CPCN required that the Liquefaction Project submit a Climate Action Plan to the Maryland Department of the Environment and gain approval of the plan. The Dominion Energy Cove Point Liquefaction Facility Climate Action Plan was approved in November 2017. Additionally, by not connecting to the larger grid, the Liquefaction Project generating station is exempt from purchasing RGGI carbon emission allowances. Furthermore, the CPCN requires Cove Point to make payments over time totaling approximately $48 million to the SEIF and Maryland low income energy assistance programs.

GHG EMISSIONS

Dominion Energy began tracking and reporting GHG emissions at the Cove Point LNG Facility in 2010 under the EPA’s GHG Reporting Program and voluntarily tracked such emissions prior to 2010. A comprehensive methane leak survey is conducted each year in accordance with the EPA rule to detect leaks and to quantify leaks from compressor units.

Annual GHG emissions at the Cove Point LNG Facility have remained fairly constant from 2011 to 2016, ranging from 141,250 to 183,800 metric tons of CO₂ equivalent. Approximately 95% of these emissions are CO₂ emissions from combustion sources, such as compressor engines and heaters. Only 5% of the annual Cove Point GHG emissions comes from methane emissions. Compared to other fossil fuels, natural gas has a much lower carbon emission rate with an ample regional supply, promoting energy and economic security. In 2016, annual GHG emissions from Dominion Energy Midstream’s facilities, including the Cove Point LNG Facility, five compressor stations and pipeline blowdown emissions between compressor stations in South Carolina and two compressor stations in Virginia were approximately 285,600 metric tons of CO₂ equivalent emissions. The 2016 GHG emissions above do not include Dominion Energy Questar Pipeline, which became part of Dominion Energy Midstream in December 2016.

Water

The CWA is a comprehensive program requiring a broad range of regulatory tools including a permit program with strong enforcement mechanisms to authorize and regulate discharges to surface waters. Dominion Energy Midstream must comply with applicable aspects of the CWA programs at its operating facilities. Dominion Energy Midstream has applied for or obtained the necessary environmental permits for the operation of its facilities.

The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of effluent into surface waters. Pursuant to these laws, permits must be obtained to

discharge into state waters or waters of the U.S. Any such discharge into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal and state law require appropriate containment berms and similar structures to help prevent the accidental release of petroleum into the environment. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of activities. 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 Midstream’s projects and operations may potentially impact tidal and non-tidal wetlands. In these instances, Dominion Energy Midstream must obtain authorization from the appropriate federal, state and local agencies prior to impacting a subject wetland. The authorizing agency may impose significant direct or indirect mitigation costs to compensate for regulated impacts to wetlands. The approval timeframe may also be extended and potentially affect project schedules resulting in a material adverse effect on Dominion Energy Midstream’s business and contracts.

Waste and Chemical Management

Dominion Energy Midstream 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 Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act of 1980, the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act. Dominion Energy Midstream must comply with all these regulations which have impacts on operations and projects. Dominion Energy Midstream generates waste from all business areas, including gas storage wells. Currently, all gas storage well construction and maintenance activities are regulated by federal and state agencies.

Protected Species

The Endangered Species Act and analogous state laws establish prohibitions on activities that can result in harm to specific species of plants and animals. In some cases those prohibitions could impact the viability of projects, result in lengthy regulatory reviews prior to the issuance of required authorizations or impose requirements for capital expenditures to reduce a facility’s impacts on a species.

EMPLOYEES

Dominion Energy Midstream is managed and operated by the Board of Directors and executive officers of Dominion Energy Midstream GP, LLC, our general partner. We do not have any employees, nor does our general partner. All of the employees that conduct our business are employed by affiliates, and our general partner secures the personnel necessary to conduct our operations through its services agreement with DES. We reimburse our general partner and its affiliates for the associated costs of obtaining the personnel necessary for our operations pursuant to our partnership

agreement. At December 31, 2017, Cove Point had approximately 200 full-time employees and was supported by 10 full-time DES employees.

WHERE YOU CAN FIND MORE INFORMATION

Dominion Energy Midstream files its annual, quarterly and current reports and other information with the SEC. Its 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 it files 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.

Dominion Energy Midstream makes its 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 our internet website, http://www.dominionenergymidstream.com, as soon as reasonably practicable after filing or furnishing the material to the SEC. Information contained on our website is not incorporated by reference in this report.

Item 1A. Risk Factors

Dominion Energy Midstream’s business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond its 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.

RISKS INHERENT IN OUR ABILITY TO GENERATE STABLE AND GROWING CASH FLOWS

Our cash generating assets are the Preferred Equity Interest, our pipeline operations, and our equity method investments in Iroquois and White River Hub, the cash receipts from which may not be sufficient following the establishment of cash reserves and payment of costs and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders. Our sources of cash are funds we receive from (i) Cove Point on the Preferred Equity Interest, which we expect will result in an annual payment to us of $50.0 million, (ii) our pipelines’ operations and (iii) distributions received with respect to our interests in Iroquois and White River Hub, which we expect will generate sufficient cash to enable us to pay the minimum quarterly distributions on the common and subordinated units. These sources may not generate sufficient cash from operations following the establishment of cash reserves and payment of costs and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders. The amount of cash we can distribute on our common and subordinated units is almost

entirely dependent upon Cove Point’s ability to generate Net Operating Income, our pipelines’ ability to generate cash from operations and Iroquois and White River Hub’s ability to make distributions to their partners. Due to our relative lack of asset diversification, an adverse development at Cove Point, our pipelines, Iroquois or White River Hub would have a significantly greater impact on our financial condition and results of operations than if we maintained a more diverse portfolio of assets. Cove Point’s ability to make payments on the Preferred Equity Interest, our pipelines’ cash generated from operations and Iroquois and White River Hub’s ability to make distributions to their partners will depend on several factors beyond our control, some of which are described below.

The Preferred Equity Interest is non-cumulative. Cove Point will make Preferred Return Distributions on a quarterly basis provided it has sufficient cash and undistributed Net Operating Income (determined on a cumulative basis from the closing of the Offering) from which to make Preferred Return Distributions. Preferred Return Distributions are non-cumulative. In the event Cove Point is unable to fully satisfy Preferred Return Distributions during any quarter, we will not have a right to recover any missed or deficient payments.

An inability to obtain needed capital or financing on satisfactory terms, or at all, could have an adverse effect on our operations and ability to generate cash flow. We are dependent on our credit facility with Dominion Energy for any borrowings necessary to meet our working capital and other financial needs. In certain circumstances, we are able to extend the credit facility at our option. However, there can be no assurance that conditions for such extension will be met. A new credit facility with Dominion Energy or a third party may bear a higher interest rate than the current credit facility, which could adversely affect our cash flow.

If Dominion Energy’s funding resources were to become unavailable to Dominion Energy, our access to funding would also be in jeopardy. In the future, an inability to obtain additional financing from other sources on acceptable terms could negatively affect our financial condition, cash flows, anticipated financial results or impair our ability to generate additional cash flows. Our ability to obtain bank financing or to access the capital markets for future debt or equity offerings may be limited by our financial condition at the time of any such financing or offering, the covenants contained in any other credit facility or other debt agreements in place at the time, adverse market conditions or other contingencies and uncertainties that are beyond our control. Our failure to obtain the funds necessary to maintain, develop and increase our asset base could adversely impact our growth and profitability.

If we do not make acquisitions on economically acceptable terms or fail to adequately integrate acquired assets, our future growth and our ability to increase distributions to our unitholders will be limited. Our ability to grow depends on our ability to make accretive acquisitions either from Dominion Energy or third parties, and we may be unable to do so for any of the following reasons, without limitation:

Additionally, a failure to adequately integrate acquired assets into our processes and systems could impact operations and result in compliance risks.

We may not be able to obtain financing or successfully negotiate future acquisition opportunities offered by Dominion Energy. If Dominion Energy offers us the opportunity to purchase additional equity interests in Cove Point or interests in Blue Racer or Atlantic Coast Pipeline, or other assets or equity interests, we may not be able to successfully negotiate a purchase and sale agreement and related agreements, we may not be able to obtain any required financing on acceptable terms or at all for such purchase and we may not be able to obtain any required governmental and third party consents. The decision whether or not to accept such offer, and to negotiate the terms of such offer, will be made by our general partner consistent with its duties under our partnership agreement. Our general partner may decline the opportunity to accept such offer for a variety of reasons, including a determination that the acquisition of the assets at the proposed purchase price would result in a risk that the conversion of subordinated units would not occur.

The acquisitions we may make could adversely affect our business and cash flows. The acquisitions we may make involve potential risks, including:

In connection with acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our future funds and other resources.

Our level of indebtedness may increase and reduce our financial flexibility and ability to pay distributions. At December 31, 2017, we had the following outstanding indebtedness: $26.4 million under our $300.0 million credit facility with Dominion Energy, $300.0 million under a term loan agreement

and $435.0 million of senior and medium-term notes acquired in connection with the Dominion Energy Questar Pipeline Acquisition. We may borrow under our $300.0 million credit facility with Dominion Energy to pursue acquisitions and future organic growth opportunities, or to otherwise meet our financial needs. Although the credit facility does not contain any financial tests and covenants that we must satisfy as a condition to making distributions, we are required to pay any amounts then due and payable under such agreement prior to making any distributions to our unitholders, notwithstanding our stated cash distribution policy. Also, while such credit facility only contains limited representations, warranties and ongoing covenants consistent with other credit facilities made available by Dominion Energy to certain of its other affiliates, we are required to obtain Dominion Energy’s consent prior to creating any mortgage, security interest, lien or other encumbrance outside the ordinary course of business on any of our property, assets or revenues during the term of such agreement. Failure to obtain any such consent from Dominion Energy in the future could have an adverse impact on our ability to implement our business strategies, generate revenues and pay distributions to our unitholders.

In connection with the Dominion Energy Questar Pipeline Acquisition, we borrowed $300.0 million under a term loan agreement that matures in December 2019. Interest on the borrowed amount accrues at a variable rate determined based on our ratio of total debt to cash flow, and interest payments are due on a quarterly basis. Upon maturity of the term loan agreement, any amounts then due and payable will need to be paid before we are permitted to make distributions to our unitholders. The term loan agreement contains customary representations, warranties and covenants consistent with other debt arrangements made available to similarly situated borrowers. See Note 17 to the Consolidated Financial Statements for additional information.

In the future, we may incur additional significant indebtedness pursuant to other term loans, credit facilities or similar arrangements in order to make future acquisitions or to develop our assets. As amounts under any indebtedness we incur become due and payable, we expect that the instruments pursuant to which such indebtedness is incurred will require that we repay such amounts prior to making any distributions to our unitholders. We also expect that such instruments may contain financial tests and covenants that are not present in our credit facility with Dominion Energy that we would need to satisfy as a condition to making distributions. Should we be unable to satisfy any such restrictions, we will be prohibited from making cash distributions to our unitholders notwithstanding our stated cash distribution policy.

Our level of indebtedness could affect our ability to generate stable and growing cash flows in several ways, including the following:

In addition, borrowings under our credit facility with Dominion Energy and the term loan agreement bear interest at variable rates. Additionally, credit facilities we or our subsidiaries may enter into in the future may bear interest at variable rates. If the interest rates on future credit facilities are tied to market interest rates and market interest rates increase, such variable-rate debt will create higher debt-service requirements, which could adversely affect our cash flow.

In addition to our debt-service obligations, our future operations may require substantial investments on a continuing basis. Our ability to make scheduled debt payments, to refinance our obligations with respect to our indebtedness and to fund capital and non-capital expenditures necessary to maintain the condition of our operating assets, properties and systems software, as well as to provide capacity for the growth of our business, depends on our financial and operating performance. General economic conditions and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt.

Cost and expense reimbursements owed to our general partner and its affiliates will reduce the amount of distributable cash flow to our unitholders. Our general partner will not receive a management fee or other compensation for its management of our partnership, but we are obligated to reimburse our general partner and its affiliates for all expenses incurred and payments made on our behalf. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform various general, administrative and support services for us or on our behalf, and corporate overhead costs and expenses allocated to us by Dominion Energy. Our partnership agreement provides that our general partner will determine the costs and expenses that are allocable to us and does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. The payment of fees to our general partner and its affiliates and the reimbursement of expenses could adversely affect our ability to pay cash distributions to our unitholders.

RISKS INHERENT IN OUR INVESTMENT IN COVE POINT

Cove Point’s revenue is generated by contracts with a limited number of customers, and Cove Point’s ability to generate cash required to make payments on the Preferred Equity Interest is substantially dependent upon the performance of these customers under their contracts. Cove Point provides service to

approximately 30 customers, including the Storage Customers, marketers or end users and the Import Shippers. The three largest customers comprised approximately 69%, 90% and 90% of the total transportation and storage revenues for the years ended December 31, 2017, 2016 and 2015, respectively. Cove Point’s largest customer represented approximately 31%, 70% and 70% of such amounts in 2017, 2016 and 2015, respectively. Because Cove Point has a small number of customers, its contracts subject it to counterparty risk. The ability of each of Cove Point’s customers to perform its obligations to Cove Point will depend on a number of factors that are beyond our control. Cove Point’s future results and liquidity are substantially dependent upon the performance of these customers under their contracts, and on such customers’ continued willingness and ability to perform their contractual obligations. Cove Point is also exposed to the credit risk of any guarantor of these customers’ obligations under their respective agreements in the event that Cove Point must seek recourse under a guaranty. Any such credit support may not be sufficient to satisfy the obligations in the event of a counterparty default. In addition, if a controversy arises under an agreement resulting in a judgment in Cove Point’s favor where the counterparty has limited assets in the U.S. to satisfy such judgment, Cove Point may need to seek to enforce a final U.S. court judgment in a foreign tribunal, which could involve a lengthy process. Upon the expiration of Cove Point’s import contracts, we expect these contracts will not be renewed.

Cove Point’s contracts may become subject to termination or force majeure provisions under certain circumstances that, if triggered for any reason, could have an adverse effect on Cove Point and its ability to make payments on the Preferred Equity Interest. In the event any of Cove Point’s customers become entitled to terminate their further contractual obligations to Cove Point and exercise such right, such termination could have a material adverse effect on Cove Point’s business, financial condition, operating results, cash flow, liquidity and prospects, which could have an adverse impact on Cove Point’s ability to pay the Preferred Return Distributions.

Cove Point is not currently receiving any revenues under its export contracts, and the export contracts may be terminated by Export Customers if certain conditions precedent are not met or for other reasons. Cove Point’s agreements with the Export Customers, while executed, will not begin generating revenues for Cove Point prior to commercial operation of the Liquefaction Project. In addition, the Export Customers may become entitled to terminate, or be relieved from, their contractual obligations to Cove Point under certain circumstances, including: (i) failure of certain conditions precedent to be met or waived by specified dates; (ii) the occurrence and continuance of certain events of force majeure (including the loss of Non-FTA Authorization); (iii) delays in the commencement of commercial operation of the Liquefaction Project beyond specified time periods; and (iv) failure by Cove Point to satisfy its contractual obligations after any applicable cure periods. If such agreements were terminated, there can be no assurance that Cove Point will be able to replace such agreements on comparable terms. Our ability to effect such a replacement is dependent upon, among other things, the global market for LNG. The termination of, and failure to replace, the export contracts could have an adverse impact on

Cove Point’s ability to pay the Preferred Return Distributions if Cove Point was unable to generate sufficient annual cash flows from other sources.

Cove Point’s existing revenue streams are insufficient to pay the full amount of Preferred Return Distributions. Through December 31, 2016, Cove Point had 800,000 Dths/day of regasification and firm transportation capacity under contract with Statoil pursuant to an import contract, which decreased to a maximum of 277,650 Dths/day of such capacity in 2017. Statoil’s obligations under the import contract expired on May 1, 2017 in order to provide capacity to be utilized in connection with the Liquefaction Project. Following the expiration of this contract with Statoil, Cove Point does not generate annual cash flows sufficient to pay Preferred Return Distributions in full. In October 2016, we caused Cove Point to set aside a distribution reserve sufficient to pay two quarters of Preferred Return Distributions (and two quarters of similar distributions with respect to any other preferred equity interests in Cove Point). However, there can be no assurance that funds will be available or sufficient for such purpose or that Cove Point will have sufficient cash and undistributed Net Operating Income to permit it to continue to make Preferred Return Distributions. The distribution reserve was fully utilized to fund the quarterly Preferred Return Distributions paid in November 2017 and February 2018.

Cove Point may be unable to commence commercial operation of the Liquefaction Project for a variety of reasons, some of which are outside of its control, and some of which are described below. In the event Cove Point is unable to commence commercial operation of the Liquefaction Project or if the export contracts are terminated and not replaced and, in either case, Cove Point does not have sufficient cash and Net Operating Income from other sources, Cove Point will not be able to pay the Preferred Return Distributions and distributions with respect to any future preferred equity interests acquired by us. The inability of Cove Point to make Preferred Return Distributions could have a significant impact on our ability to pay distributions to our unitholders. Similarly, the inability of Cove Point to generate revenues sufficient to support the payment of distributions on additional preferred equity interests that may otherwise be made available to us could adversely impact our overall business plan and ability to generate stable and growing cash flows.

Various factors could negatively affect the timing or overall development or commercial operation of the Liquefaction Project, which could adversely affect Cove Point’s ability to make payments on the Preferred Equity Interest. Completion of the Liquefaction Project could be delayed or commercial operation could be affected by factors such as:

Any delay in completion of the Liquefaction Project may prevent Cove Point from commencing liquefaction operations

when or at levels anticipated, which could cause a delay in the receipt of revenues therefrom, require Cove Point to pay damages to its customers, or in event of significant delays beyond certain time periods, permit either or both of Cove Point’s Export Customers to terminate their contractual obligations to Cove Point. As a result, any significant delay or inability to perform, whatever the cause, could have a material adverse effect on Cove Point’s operating results and its ability to make payments on the Preferred Equity Interest. In addition, the successful completion of the Liquefaction Project is subject to the risk of cost overruns, which may make it difficult to finance the completion of the Liquefaction Project.

Cove Point is dependent on Dominion Energy to fund the costs necessary to develop infrastructure projects, including the Liquefaction Project. If Dominion Energy is unwilling or unable to supply the funding necessary to develop infrastructure projects, Cove Point may be required to seek additional financing in the future and may not be able to secure such financing on acceptable terms. The Liquefaction Project, which is estimated to cost approximately $4.1 billion, excluding financing costs, is expected to be placed into service in March 2018. Additionally, in January 2018, Cove Point received FERC authorization to construct and operate the approximately $150 million Eastern Market Access Project. Construction on this project is expected to begin in the second quarter of 2018, and the project facilities are expected to be placed into service in early 2019.

To date, Dominion Energy has funded development and construction costs associated with these expansion projects. Dominion Energy has indicated that it intends to provide the funding necessary for the remaining development costs and other capital expenditures of Cove Point, but it has no contractual obligation to do so and has not secured all of the funding necessary to cover these costs, as it intends to finance these costs as they are incurred using its consolidated operating cash flows in addition to proceeds from capital markets transactions. Cove Point’s existing revenue streams and cash reserves will be insufficient for it to complete these infrastructure projects. If Dominion Energy is unwilling to provide funding for the remaining development costs and other capital expenditures, or is unable to obtain such funding in the amounts required or on terms acceptable to Dominion Energy, Cove Point would have to obtain additional funding from lenders, in the capital markets or through other third parties. Any such additional funding may not be available in the amounts required or on terms acceptable to Cove Point and Dominion Energy Midstream. The failure to obtain any necessary additional funding could cause these expansion projects to be delayed or not be completed.

If Cove Point does obtain bank financing or access the capital markets, incurring additional debt may significantly increase interest expense and financial leverage, which could compromise Cove Point’s ability to fund future development and acquisition activities and restrict Cove Point’s ability to make payments on the Preferred Equity Interest, which would in turn limit our ability to make distributions to our unitholders.

Dominion Energy has also entered into guarantee arrangements on behalf of Cove Point to facilitate the Liquefaction Project, including guarantees supporting the terminal services and transportation agreements as well as the engineering, procurement and construction contract for the Liquefaction Project. Two of

the guarantees have no stated limit, one guarantee has a $150 million limit, and one guarantee has a $1.75 billion aggregate limit with an annual draw limit of $175 million. If Cove Point was required to replace these guarantees with other credit support, the cost could be significant.

Some of the approvals for the Liquefaction Project may be subject to further conditions, review and/or revocation. Cove Point has received the required approvals to construct and operate the Liquefaction Project from the DOE, FERC and the Maryland Commission. These approvals are subject to continued compliance with the applicable permit conditions. However, 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. The issuance of the FERC Order approving the Liquefaction Project was upheld by the D.C. Circuit. Cove Point does not know whether any existing or potential interventions or other actions by third parties will interfere with Cove Point’s ability to maintain such approvals, but loss of any material approval could have a material adverse effect on the development or operation of the facility. In addition, the Liquefaction Project has been the subject of litigation in the past and could be the subject of litigation in the future. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect Cove Point’s operations, financial condition, and ability to make payments on the Preferred Equity Interest.

To maintain the cryogenic readiness of the Cove Point LNG Facility, Cove Point may need to purchase and process LNG. Cove Point needs to maintain the cryogenic readiness of the Cove Point LNG Facility when the terminal facilities are not being used by existing customers. Each year, one or two LNG cargos are procured and are billed to Cove Point’s Import Shippers pursuant to a cost recovery mechanism set forth in Cove Point’s FERC Gas Tariff. Such mechanism provides that, to the extent market conditions exist that neither import nor export services are being sufficiently utilized and LNG cooling quantities are required, the Import Shippers’ responsibility for costs incurred for any LNG cooling quantities received prior to the earlier of operational commencement of the Liquefaction Project or March 2018 would be reduced to approximately half of such amounts incurred. If the Liquefaction Project has not commenced operations prior to March 2018 and LNG cooling quantities are required, Cove Point is responsible for any costs incurred until the Liquefaction Project commences operations. Upon operational commencement of the Liquefaction Project, the Import Shippers will have responsibility for costs incurred on certain LNG cooling quantities.

Following the completion of the Liquefaction Project, the Cove Point LNG Facility will be a bi-directional facility, reducing the risk that it will not be used for either import or export, and the addition of liquefaction facilities, which can be used to liquefy any boil-off gas, is expected to reduce any need for Cove Point to procure LNG for cooling purposes. However, Cove Point may need to maintain or obtain funds necessary to procure LNG to maintain the cryogenic readiness of the Cove Point LNG Facility in the future, which could adversely impact its ability to make payments on the Preferred Equity Interest.

RISKS INHERENT IN OUR BUSINESS GENERALLY

We are dependent on contractors and regulators for the successful completion of infrastructure projects and may be unable to complete infrastructure projects within initially anticipated timing. Infrastructure projects have been announced and additional projects may be considered in the future. We compete for projects with companies of varying size and financial capabilities, including some that may have advantages competing for natural gas supplies. Commencing construction on announced and future projects may require approvals from applicable state and federal agencies. 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 our control. Even if facility construction, pipeline, expansion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of our business following completion of the projects may not meet expectations. Start-up and operational issues can arise in connection with the commencement of commercial operation at our facilities. Such issues may include failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, we may not be able to timely and effectively integrate the projects into our 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 our ability to realize the anticipated benefits from the infrastructure projects.

We may not be able to maintain, renew or replace our existing portfolio of customer contracts successfully, or on favorable terms and since these contracts are with a limited number of customers, we are subject to customer concentration risk. Upon contract expiration, customers may not elect to re-contract with us as a result of a variety of factors, including the amount of competition in the industry, changes in the price of natural gas and supply areas, their level of satisfaction with our services, the extent to which we are able to successfully execute our 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 us. Further, we are subject to customer concentration risk in that several customers represent the majority of our contracted capacity. Producers with direct commodity price exposure face liquidity constraints, which could present a credit risk to Dominion Energy Midstream.

Our business is exposed to customer credit risk, and we may not be able to fully protect ourselves against such risk. Our business is subject to the risks of nonpayment and nonperformance by our customers. We have in the past and expect to continue to undertake capital expenditures based on commitments from customers upon which we expect to realize a return. Nonperformance by our customers of those commitments or termination of those commitments resulting from our inability to timely meet our obligations could result in substantial losses to us. In addition, some of our customers, counterparties and suppliers

may be highly leveraged and subject to their own operating and regulatory risks and, even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. Volatility in commodity prices might have an impact on many of our customers, which in turn could have a negative impact on their ability to meet their obligations to us. We manage our exposure to credit risk through credit analysis and monitoring procedures, and sometimes collateral, such as letters of credit, prepayments, liens on customer assets and guarantees. However, these procedures and policies cannot fully eliminate customer credit risk, and to the extent our policies and procedures prove to be inadequate, it could negatively affect our financial condition and results of operations.

Our results of operations, as well as construction of infrastructure projects, may be affected by changes in the weather. Fluctuations in weather can affect demand for our services. For example, milder than normal weather can reduce demand for gas transmission services. In addition, severe weather, including hurricanes, winter storms, earthquakes, floods and other natural disasters can disrupt operation of our facilities and cause service outages, construction delays and property damage that require incurring additional expenses. Furthermore, our operations, especially Cove Point, could be adversely affected and our 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 or a change in sea level or sea temperatures.

Our operations and construction activities are subject to operational hazards, equipment failures, supply chain disruptions and personnel issues, which could create significant liabilities and losses, and negatively affect Cove Point’s ability to make payments on the Preferred Equity Interest and our ability to make distributions. Operation of our facilities and the development of the Liquefaction Project and infrastructure projects involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, regulatory compliance deficiencies, pipeline integrity, including potential seam deficiencies, fuel supply 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. Because our transmission facilities, pipelines and other facilities are interconnected with those of third parties, the operation of our facilities and pipelines could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties. Our business is dependent upon sophisticated information technology systems and network infrastructure, the failure of which could prevent us from accomplishing critical business functions.

Operation of our facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of our facilities and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are inherent risks of our business. Unplanned outages typically increase operation and maintenance expenses and may reduce our revenues as a result of

selling fewer services or incurring increased rate credits to customers. If we are unable to perform our contractual obligations, penalties or liability for damages could result.

In addition, there are many risks associated with our operations and the transportation, storage and processing of natural gas and LNG, including fires, explosions, uncontrolled releases of natural gas or other substances, the collision of third party equipment with pipelines and other environmental incidents. Such incidents could result in the loss of human life or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or the property of third parties; 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 transmission facilities near populated areas, including residential areas, commercial business centers and industrial risks, could increase the level of damages resulting from these risks. We maintain property and casualty insurance that may cover certain damage and claims caused by such incidents, but other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available, in which case such risks or losses could create significant liabilities that negatively affect Cove Point’s ability to make payments on the Preferred Equity Interest or our ability to make distributions.

We do not own all of the land on which our facilities are located, which could result in disruptions to our operations. We do not own all of the land on which our facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our assets on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.

We are subject to complex governmental regulation, including pipeline safety and integrity regulations, that could adversely affect our results of operations and subject us to monetary penalties. Our operations are subject to extensive federal, state and local regulation, including the NGPSA, 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 infrastructure assets and pipeline safety, among other matters. Our businesses are subject to regulatory regimes which could result in substantial monetary penalties if we are found not to be in compliance.

Federal and state agencies frequently impose conditions on our activities. These restrictions have become more stringent over time and can limit or prevent the construction of new transmission or distribution pipelines and related facilities. For example, we are subject to regulation by the DOT under PHMSA, which has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. PHMSA non-compliance presents a risk due to significant legislative mandates and pending rulemaking. The most recent reauthorization of PHMSA

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

Our operations are also subject to a number of environmental laws and regulations that impose significant compliance costs on us, and existing and future environmental and similar laws and regulations could result in increased compliance costs or additional operating restrictions. Our operations and the Liquefaction Project and infrastructure projects are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, handling and disposal of hazardous materials and other wastes, and protection of natural resources and human health and safety. Many of these laws and regulations, such as the CAA, the CWA, the Oil Pollution Act of 1990, and the Resource Conservation and Recovery Act, as amended, and analogous state laws and regulations require us to commit significant capital toward permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and the purchase of emission allowances and/or offsets in connection with the construction and operations of facilities. Violation of these laws and regulations could lead to substantial liabilities, fines and penalties, limitations on our ability to operate or to capital expenditures related to pollution control equipment that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Additionally, federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment.

Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are unable to estimate our compliance costs with certainty due to our inability to predict the requirements and timing of implementation of any future environmental rules or regulations. Other factors that affect our ability to predict future environmental expenditures with certainty include the difficulty in estimating any future clean-up costs and quantifying liabilities under environmental laws that impose joint and several liability on all responsible parties. However, such expenditures, if material, could result in the impairment of assets or otherwise adversely affect the results of our operations, financial performance or liquidity and the ability of Cove Point to make payments on the Preferred Equity Interest or our ability to make distributions.

Any additional federal and/or state requirements imposed on energy companies mandating limitations on GHG emissions or requiring efficiency improvements, may adversely impact our business. There are potential impacts on our natural gas businesses as federal or state GHG legislation or regulations may require GHG emission reductions from the natural gas sector and

could affect demand for natural gas. Several regions of the U.S. have moved forward with GHG emission regulations, such as in the Northeast. There are numerous other regulatory approaches currently in effect or being considered to address GHGs, including additional future regulation by the EPA, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program, or U.S. treaty commitments. Additional regulation of air emissions, including GHGs, under the CAA may be imposed on the natural gas sector, including rules to limit methane gas emissions. For example, the EPA adopted regulations in June 2016 to regulate upstream methane emissions from oil and gas production. Compliance with GHG emission reduction requirements may require the retrofitting or replacement of equipment or could otherwise increase the cost to operate and maintain our facilities. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products, which in turn could affect demand for natural gas.

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

War, intentional acts and other significant events could adversely affect our operations or the development of the Liquefaction Project and infrastructure projects. We cannot predict the impact that world hostility may have on the energy industry in general or on our business in particular, including the development of the Liquefaction Project and infrastructure projects. Any retaliatory military strikes or sustained military campaign may affect our operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets. In addition, our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Furthermore, the physical compromise of our facilities could adversely affect our ability to manage our 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, which could negatively impact our results of operations, financial condition and Cove Point’s ability to make payments on the Preferred Equity Interest or our ability to make distributions.

We are dependent upon our affiliates and their key personnel and employees, and we may not find a suitable replacement if the services agreements with DES and other affiliates are terminated or such key personnel are no longer available to us, which would materially and adversely affect us. We are managed and operated by the Board of Directors and executive officers of Dominion Energy Midstream GP, LLC, our general partner. We do not have any employees, nor does our general partner. All of the employees that conduct our business are employed by affiliates, and our general partner secures the personnel necessary to conduct our operations through its services agreement with DES. Our executive officers and the employees that conduct our business may have conflicts in allocating their time and services among us and our affiliates. Although our Board of Directors has

control over our executive officers, we have no authority over the individual employees. Accordingly, we are reliant upon, and our success depends upon, our affiliates’ personnel and services. The failure of any of our affiliates’ key personnel to service our business with the requisite time and dedication, the departure of such personnel from our affiliates or the failure of our affiliates to attract and retain key personnel would each materially and adversely affect our ability to conduct our business. Furthermore, if any of the services agreements with DES or other affiliates are terminated and suitable replacements for such entities are not secured in a timely manner or at all, we would likely be unable to conduct our business, which would materially and adversely affect us.

Hostile cyber intrusions could severely impair our operations, lead to the disclosure of confidential information, damage our reputation and otherwise have an adverse effect on our business. We own assets deemed by FERC as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run our facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. gas transmission system or our operations could view our computer systems, software or networks as attractive targets for a cyber-attack. For example, malware has been designed to target software that runs the nation’s critical infrastructure such as gas pipelines. In addition, our businesses require that we and our vendors collect and maintain sensitive customer data, as well as confidential employee and unitholder information, which is subject to electronic theft or loss.

A successful cyber attack on the systems that control our gas transmission assets or the Cove Point Facilities could severely disrupt business operations, preventing us from serving customers or collecting revenues. The breach of certain business systems could affect our ability to correctly record, process and report financial 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 our 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. We maintain property and casualty insurance that may cover certain damage caused by potential cybersecurity 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 our business, financial condition, results of operations and Cove Point’s ability to make payments on the Preferred Equity Interest or our ability to make distributions.

Certain of our operations are subject to FERC’s rate-making policies, which could limit our ability to recover the full cost of operating our assets, including earning a reasonable return, and have an adverse effect on Cove Point’s ability to make payments on the Preferred Equity Interest or our ability to make distributions. We are subject to extensive regulations relating to the jurisdictional rates we can charge for our natural gas regasification, storage and transportation services. FERC establishes both the maximum and minimum rates we can charge for

jurisdictional services. The basic elements of rate-making that FERC considers are the costs of providing service, the volumes of gas being transported and handled, the rate design, the allocation of costs between services, the capital structure and the rate-of-return that a regulated entity is permitted to earn. The profitability of our business is dependent on our ability, through the rates that we are permitted to charge, to recover costs and earn a reasonable rate of return on our capital investment. FERC or our customers can challenge our existing jurisdictional rates, which we may be required to change should FERC find those rates to be unjust and unreasonable. Such a challenge could adversely affect our ability to maintain current revenue levels.

Upon filing a rate case, or when or if Cove Point, DECG, Dominion Energy Questar Pipeline, Iroquois or White River Hub has to defend its rates in a proceeding commenced by a customer or FERC, it will be required, among other things, to support its rates, by showing that they reflect recovery of its costs plus a reasonable return on its investment, in accordance with cost of service ratemaking.

In addition, as part of our obligations to support rates, we are required to establish the inclusion of an income tax allowance in our cost of service as just and reasonable. On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a MLP. FERC’s current policy permits pipelines and storage companies to include a tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines and storage companies owned by partnerships or limited liability companies, the current tax allowance policy reflects the actual or potential income tax liability on the FERC jurisdictional income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. FERC issued the Notice of Inquiry in response to a remand from the U.S. Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that an oil pipeline organized as a partnership would not “double recover” its taxes under the current policy by both including a tax allowance in its cost-based rates and earning a return on equity calculated on a pre-tax basis. We cannot predict whether FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on either income tax allowances or return on equity calculations for pipeline companies organized as part of a MLP. However, any modification that reduces or eliminates an income tax allowance for pipeline companies organized as a part of a MLP or decreases the return on equity for such pipelines could result in an adverse impact on our revenues associated with the transportation and storage services we provide pursuant to cost-based rates. Some entities have authority to charge market-based rates and therefore this tax allowance issue does not affect the rates that they charge their customers.

An adverse determination by FERC with respect to our open access rates could have a material adverse effect on our revenues, earnings and cash flows and Cove Point’s ability to make payments on the Preferred Equity Interest or our ability to make distributions.

The 2017 Tax Reform Act could have a material impact on our FERC-regulated operations including rates charged to customers, cash flows, and financial results. Dominion Energy Midstream does not include a provision for income taxes as it is a pass-through entity for income tax purposes; however our regulated subsidiaries impute an income tax allowance in determining the rates charged to customers. In light of the reduction in the income tax rate in the 2017 Tax Reform Act, our FERC-regulated 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 the 2017 Tax Reform Act and all other drivers. It is unclear if FERC will mandate a one-time rate reset or Section 5 rate case for our regulated subsidiaries; however, states as well as customers have petitioned FERC to request changes in rates as a result of the 2017 Tax Reform Act. In addition, Dominion Energy Midstream’s 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 are to be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred taxes will be determined by FERC.

RISKS INHERENT IN AN INVESTMENT IN US

Dominion Energy owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Dominion Energy, have conflicts of interest with us and limited duties, and they may favor their own interests to our detriment and that of our unitholders. Dominion Energy owns and controls our general partner and appoints all of the directors of our general partner. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Dominion Energy. Therefore, conflicts of interest may arise between Dominion Energy or any of its affiliates, including our general partner, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:

In addition, we may compete directly with Dominion Energy and entities in which it has an interest for acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us.

The Board of Directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all on our common and subordinated units. The Board of Directors of our general partner adopted a cash distribution policy pursuant to which we intend to make quarterly distributions on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. However, the Board of Directors of our general partner may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters.

In addition, our partnership agreement does not require us to pay any distributions at all on our common and subordinated units. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our common and subordinated unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the Board of Directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of Dominion Energy to the detriment of our common unitholders.

Our general partner intends to limit its liability regarding our obligations. Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our common and subordinated unitholders.

We expect to distribute a significant portion of our distributable cash flow to our partners, which could limit our ability to grow and make acquisitions. We plan to distribute most of our distributable cash flow, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the cash that we have available to distribute to our common and subordinated unitholders.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our units. Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, and otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.

Our partnership agreement restricts the remedies available to holders of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the Conflicts Committee then it will be presumed that, in making its decision, taking any action or failing to act, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or Dominion Energy Midstream, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units. Our Series A Preferred Units rank senior to all of our other classes or series of equity securities with respect to distribution rights. These preferences may adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.

In addition, distributions on the Series A Preferred Units accrue and are cumulative. Our obligation to pay distributions on our Series A Preferred Units or on the common units issued following the conversion of such Series A Preferred Units, may impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions and other general partnership purposes. Our obligations to the holders of Series A Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

Dominion Energy and other affiliates of our general partner may compete with us. Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory, and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including Dominion Energy, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Dominion Energy may compete with us for investment opportunities and may own an interest in entities that compete with us.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and Dominion Energy. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such

opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

The holder or holders of our IDRs may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to the IDRs, without the approval of the Conflicts Committee or the holders of our common units. This could result in lower distributions to holders of our common units. The holder or holders of a majority of our IDRs (initially our general partner) have the right, at any time when there are no subordinated units outstanding, and we have made cash distributions in excess of the highest then-applicable target distribution for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units equal to the number of common units that would have entitled the holder to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the IDRs for the quarter prior to the reset election.

We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per unit without such conversion. However, our general partner may transfer the IDRs at any time. It is possible that our general partner or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the IDRs expect that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, the holders of the IDRs may be experiencing, or may expect to experience, declines in the cash distributions it receives related to the IDRs and may therefore desire to be issued our common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units to the holders of the IDRs in connection with resetting the target distribution levels.

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade. Compared to the holders of common stock in a corporation, unitholders have limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its Board of Directors. The Board of Directors of our general partner, including the independent directors, is chosen

entirely by Dominion Energy, as a result of it owning our general partner, and not by our unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent. If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders are unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to prevent its removal. The vote of the holders of at least 66 ²/₃% of all outstanding common and subordinated units and Series A Preferred Units voting together as a single class is required to remove our general partner. At December 31, 2017, Dominion Energy owned an aggregate of 47.5% of our limited partner interest. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide Dominion Energy the ability to prevent the removal of our general partner.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in default under our term loan agreement. Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. The new owner of our general partner would then be in a position to replace the Board of Directors and executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the Board of Directors and executive officers of our general partner. This effectively permits a change of control without the vote or consent of the unitholders. In addition, a change of control would constitute an event of default under our term loan agreement. During the continuance of an event of default under our term loan agreement, the administrative agent may declare all amounts payable by us immediately due and payable. In addition, holders of our Series A Preferred Units are entitled to certain conversion and redemption rights upon a change in control.

The IDRs may be transferred to a third party without unitholder consent. Our general partner may transfer the IDRs to a third party at any time without the consent of our unitholders. If our general partner transfers the IDRs to a third party, our general partner would not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time. For example, a transfer of IDRs by our general partner could reduce the likelihood of Dominion Energy accepting offers made by us relating to assets owned by Dominion Energy, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or

price. If at any time our general partner and its affiliates own more than 80% of any class of outstanding limited partner interests other than the Series A Preferred Units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of such class of limited partner interests held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the limited call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its limited call right.

If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended. At December 31, 2017, Dominion Energy owned an aggregate of 50.6% of our common and subordinated units.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain unitholders. Our general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates chargeable to our customers, (ii) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property or (iii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

We may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests. Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units or equal to our Series A Preferred Units. In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank to our common units may (i) reduce or eliminate the amount of distributable cash flow to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) further subordinate the claims of the common unitholders to our assets in the event of our liquidation.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units or Series A Preferred Units in the public or private markets, including sales by Dominion Energy or other large holders. At December 31, 2017, Dominion Energy held 18,504,628 common units, 11,365,628 Series A Preferred Units and 31,972,789 subordinated units. All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period.

Our Series A Preferred Units are convertible into common units on a one-for-one basis, subject to certain limitations and adjustments and subject to certain minimum conversion amounts, (i) in whole or in part at the option of the holders of the Series A Preferred Units any time after December 1, 2018 or prior to a liquidation of Dominion Energy Midstream or (ii) in whole or in part at our option any time after December 1, 2019 under certain circumstances. In addition, the holders of our Series A Preferred Units are entitled to certain conversion and redemption rights upon a change of control. In certain circumstances and subject to certain limitations, we may be permitted to issue common units in lieu of cash to satisfy redemption prices with respect to the Series A Preferred Units. The number of units issued for such payments will be determined based on the value of our common units and the specified premium set forth in our partnership agreement for conversion or redemption of the Series A Preferred Units in certain circumstances, and could be substantial, especially during periods of significant declines in market prices of our common units. If a substantial portion of our subordinated units or Series A Preferred Units are converted into common units or if we issued a substantial number of common units in lieu of cash to satisfy redemption prices with respect to the Series A Preferred Units, common unitholders could experience significant dilution.

Sales by Dominion Energy or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to Dominion Energy and the purchasers of our common units and Series A Preferred Units under the Private Placement Agreement. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of

any units that they hold. In addition, under the Private Placement Agreement, the purchasers and their assignees have registration rights with respect to (i) the common units purchased thereunder and (ii) the common units issuable upon conversion of the Series A Preferred Units they hold. Alternatively, we may be required to undertake a future public or private offering of common units and use the net proceeds from such offering to redeem an equal number of common units held by Dominion Energy.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our units. Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors of our general partner, cannot vote on any matter.

Unitholders may have liability to repay distributions. Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, as amended, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners that received the distribution and knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to Dominion Energy Midstream are not counted for purposes of determining whether a distribution is permitted.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements. The common units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s Board of Directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements.

TAX RISKS TO UNITHOLDERS

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes and not being subject to a material amount of entity-level taxation. If the IRS were to treat us as a corporation for federal income tax purposes, or if we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced. The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from

the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state, local, or foreign income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Currently, we own assets and conduct business in states that impose margin or franchise taxes. In the future, we may expand our operations. Imposition of a similar tax on us in other jurisdictions to which we expand could substantially reduce our cash available for distribution to our unitholders.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes, or differing interpretations, possibly applied on a retroactive basis. The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative, or judicial action, changes or differing interpretations at any time. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the “qualifying income” exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the IRC (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.

However, any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly

traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any similar future legislative changes could negatively impact the value of an investment in our units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

If the IRS were to contest the U.S. federal income tax positions we take, the market for our common units could be adversely impacted, and the cost of any IRS contest would reduce our cash available for distribution to our unitholders. We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Additionally, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

If the IRS makes audit adjustments to our income tax returns for taxable years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced, and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf. Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustments into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced, and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’

behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us. Our unitholders are required to pay U.S. federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, our unitholders may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected. If a unitholder sells common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease such unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable to a unitholder if it sells such units at a price greater than its tax basis in those units, even if the price the unitholder receives is less than its original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.

A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than the unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, the unitholder may recognize ordinary income from our allocations of income and gain to the unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us. In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the 2017 Tax Reform Act for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them. Investment in our common units by tax-exempt entities, such as employee benefit plans and IRAs raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trades or businesses) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units. Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.

The 2017 Tax Reform Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units. Because we cannot match transferors and transferees of our common units, and for other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of the provisions of the IRC of 1986, as amended, or existing and proposed Treasury regulations thereunder. Our counsel is unable to opine as to the validity of this approach. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of

our common units or result in audit adjustments to our unitholders’ tax returns.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss, or deduction based upon the ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we could be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition. Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned common units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

We may adopt certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units. In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge our valuation methods and the resulting allocations of income, gain, loss and deduction. A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss allocated to our unitholders. It also could affect the amount of gain recognized on a unitholder’s sale of our common units, have a negative impact on the value of

the common units, or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

Our unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our common units. In addition to U.S. federal income taxes, our unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements.

We currently own assets and conduct business in multiple states, most of which currently impose a personal income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose income or similar taxes on nonresident individuals. It is each unitholder’s responsibility to file all foreign, U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of investment in our common units.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

At December 31, 2017, Dominion Energy Midstream’s assets consisted primarily of its preferred equity interest in Cove Point, the physical properties owned by DECG and Dominion Energy Questar Pipeline and its noncontrolling partnership interests in Iroquois and White River Hub. These physical properties are described in Item 1. Business, which description is incorporated herein by reference.

Item 3. Legal Proceedings

From time to time Dominion Energy Midstream may be 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 Dominion Energy Midstream, as applicable, 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 Dominion Energy Midstream may be involved in various legal proceedings.

See Notes 14 and 20 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 Dominion Energy Midstream is a party or by which its interests may be affected.

Item 4. Mine Safety Disclosures

Not applicable.

DISTRIBUTIONS OF AVAILABLE CASH

Our partnership agreement provides that our general partner will make a determination as to whether to make a distribution, but our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the Board of Directors of our general partner adopted a cash distribution policy effective as of the Offering which set forth our general partner’s intention with respect to the distributions to be made to unitholders. We cannot pay any distributions on any junior securities, including any of the common units, subordinated units or IDRs, prior to paying the quarterly distribution payable to the Series A Preferred Units, including any previously accrued and unpaid distributions.

Definition of Available Cash

Any distributions we make will be characterized as made from “operating surplus” or “capital surplus.” Distributions from operating surplus are made differently than cash distributions that we would make from capital surplus. Operating surplus distributions will be made to our unitholders and, if we make quarterly distributions above the first target distribution level described below, to the holder of our IDRs. We do not anticipate that we will make any distributions from capital surplus. In such an event, however, any capital surplus distribution would be made pro rata to all unitholders, but the IDRs would generally not participate in any capital surplus distributions with respect to those rights. Any distribution from capital surplus would result in a reduction of the minimum quarterly distribution and target distribution levels and, if we reduce the minimum quarterly distribution to zero and eliminate any unpaid arrearages, thereafter capital surplus would be distributed as if it were operating surplus and the IDRs would thereafter be entitled to participate in such distributions. In determining operating surplus and capital surplus, we will only take into account our proportionate share of our consolidated subsidiaries that are not wholly-owned, such as Cove Point.

We define operating surplus as:

Disbursements made, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period but on or before the date on which cash or cash equivalents will be distributed with respect to such period shall be deemed to have been made, received, established, increased or reduced, for purposes of determining operating surplus, within such period if our general partner so determines. Cash received from Cove Point or from our interest in any entity for which we account using the equity method will not be included to the extent it exceeds our proportionate share of such entity’s operating surplus (calculated as if the definition of operating surplus applied to such entity from the date of our acquisition of such an interest without any basket similar to that described in the first bullet above). Operating surplus does not reflect cash generated by our operations. For example, it includes a basket of $45.0 million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deducted from operating surplus at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deduction.

We define operating expenditures in our partnership agreement to generally mean all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner or its affiliates, payments made under hedge contracts (provided that (1) with respect to amounts paid in connection with the initial purchase of a hedge contract, such amounts will be amortized over the life of the applicable hedge contract and (2) payments made in connection with the termination of any hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such hedge contract), officer compensation, repayment of working capital borrowings, interest on indebtedness and capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:

Intent to Distribute the Minimum Quarterly Distribution

Pursuant to our cash distribution policy, within 60 days after the end of each quarter, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.1750 per unit, or $0.70 per unit on an annualized basis, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. The Board of Directors of our general partner may change the foregoing distribution policy at any time and from time to time, and even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner. Our partnership agreement does not contain a requirement for us to pay distributions to our unitholders, and there is no guarantee that we will pay the minimum quarterly distribution, or any distribution, on the units in any quarter. However, our partnership agreement does contain provisions intended to motivate our general partner to make steady, increasing and sustainable distributions over time. We cannot pay any distributions on any junior securities, including any of the common units, subordinated units and the IDRs, prior to paying the quarterly distribution payable to holders of the Series A Preferred Units, including any previously accrued and unpaid distributions. Please see Notes 17 and 22 to the Consolidated Financial Statements for a discussion of the provisions included in our term loan agreement and credit facility with Dominion Energy, respectively, that may restrict our ability to make distributions.

General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner owns the IDRs and may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.

Incentive Distribution Rights

IDRs represent the right to receive increasing percentages (15.0%, 25.0% and 50.0%) of quarterly distributions from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the IDRs, but may transfer these rights separately from its general partner interest.

If for any quarter:

then we will make additional distributions from operating surplus for that quarter among the unitholders and the holders of the IDRs in the following manner:

Percentage Allocations of Distributions from Operating Surplus

The following table illustrates the percentage allocations of distributions from operating surplus between the unitholders and the holders of our IDRs based on the specified target distribution levels. The amounts set forth under the column heading “Marginal Percentage Interest in Distributions” are the percentage interests of the holders of our IDRs and the unitholders in any distributions from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit.” The percentage interests shown for our unitholders and the holders of our IDRs for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume there are no arrearages on common units.

SUBORDINATION PERIOD

General

Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions from operating surplus each quarter in an amount equal to $0.1750 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions from operating surplus may be made on the subordinated units, all of which are owned by Dominion Energy. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distribution from operating surplus for any quarter until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient cash from operating surplus to pay the minimum quarterly distribution on the common units.

Determination of Subordination Period

The subordination period began upon the closing date of the Offering and ends when we satisfy one of the three tests set forth in our partnership agreement as described below.

The first test would be satisfied as of the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending June 30, 2018, if each of the following has occurred:

The second test would be satisfied if each of the following has occurred:

The third test would be satisfied as of the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending June 30, 2018, if each of the following has occurred:

For the period after closing of the Offering through December 31, 2014, our partnership agreement prorated the minimum quarterly distribution based on the actual length of the period, and used such prorated distribution for all purposes, including in determining whether there are any arrearages in payment of the minimum quarterly distribution on the common units.

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis and will then participate pro rata with the other common units in distributions, and all common units will thereafter no longer be entitled to arrearages.

MD&A discusses Dominion Energy Midstream’s results of operations and general financial condition. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data.

CONTENTS OF MD&A

MD&A consists of the following information:

FORWARD-LOOKING STATEMENTS

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

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

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

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

PARTNERSHIP OVERVIEW

We are a growth-oriented Delaware limited partnership formed on March 11, 2014 by Dominion Energy to initially own the Preferred Equity Interest and the general partner interest in Cove Point, which owns LNG terminalling, storage, regasification and transportation assets. We expect that our relationship with Dominion Energy, which has substantial additional midstream assets, should provide us the opportunity over time to grow a portfolio of natural gas terminaling, processing, storage, transportation and related assets. The Preferred Equity Interest is a perpetual, non-convertible preferred equity interest entitled to Preferred Return Distributions so long as Cove Point has sufficient cash and undistributed Net Operating Income (determined on a cumulative basis from the closing of the Offering) from which to make Preferred Return Distributions. Preferred Return Distributions will be made on a quarterly basis and will not be cumulative. Until the Liquefaction Project is completed, Cove Point was prohibited from making a distribution on its common equity interests until it had a distribution reserve sufficient to pay two quarters of Preferred Return Distributions. The distribution reserve was fully funded in October 2016 and was fully utilized in November 2017 and February 2018 to fund the quarterly Preferred Return Distribution. The Preferred Equity Interest is also entitled to receive Additional Return Distributions, and should benefit from the expected increased cash flow and income associated with the Liquefaction Project upon commercial operation. We expect the Preferred Equity Interest to have limited exposure to the capital expenditure requirements associated with the future expansion of the Cove Point Facilities, as Dominion Energy, although it is under no obligation to do so, has indicated that it intends to provide such funding. Our results of operations and financial condition will be dependent on the performance of Cove Point, and we believe that the discussion and analysis of Cove Point’s financial condition and operations is important to our unitholders.

On April 1, 2015, Dominion Energy Midstream acquired from Dominion Energy all issued and outstanding membership interests in DECG. DECG owns and operates nearly 1,500 miles

of FERC-regulated open access, transportation-only interstate natural gas pipeline in South Carolina and southeastern Georgia.

On September 29, 2015, Dominion Energy Midstream acquired a 25.93% noncontrolling partnership interest in Iroquois. Iroquois, a Delaware limited partnership, owns and operates a 416-mile FERC-regulated interstate natural gas transmission pipeline that extends from the Canada-U.S. border through the states of New York and Connecticut.

On December 1, 2016, Dominion Energy Midstream acquired from Dominion Energy all of the issued and outstanding membership interests of Dominion Energy Questar Pipeline. Dominion Energy Questar Pipeline owns and operates nearly 2,200 miles of interstate natural gas pipelines and 18 transmission and storage compressor stations in the western U.S., providing natural gas transportation and underground storage services in Utah, Wyoming and Colorado.

Business Strategy

Dominion Energy Midstream’s primary business objective is to generate stable and growing cash flows, which will enable it to maintain and increase cash distributions per unit over time. We intend to accomplish this objective by executing the following strategies:

BASIS OF PRESENTATION

Dominion Energy owns the general partner interest and the Preferred Equity Interest in Cove Point. As discussed in Note 16 to the Consolidated Financial Statements, Dominion Energy Midstream is the primary beneficiary of, and therefore consolidates, Cove Point. As such, Dominion Energy Midstream’s investment in the Preferred Equity Interest and Cove Point’s preferred equity interest are eliminated in consolidation. Dominion Energy’s retained common equity interest in Cove Point is reflected as noncontrolling interest.

The DECG Acquisition is considered to be a reorganization of entities under common control. As a result, Dominion Energy Midstream’s basis in DECG is equal to Dominion Energy’s cost basis in the assets and liabilities of DECG. On April 1, 2015, DECG became a wholly-owned subsidiary of Dominion Energy Midstream and is therefore consolidated by Dominion Energy Midstream. The accompanying financial statements and related notes include the historical results and financial position of DECG beginning January 31, 2015, the inception date of common control.

The Dominion Energy Questar Pipeline Acquisition is considered to be a reorganization of entities under common control. As a result, Dominion Energy Midstream’s basis in Dominion Energy Questar Pipeline is equal to Dominion Energy’s cost basis in the assets and liabilities of Dominion Energy Questar Pipeline. On December 1, 2016, Dominion Energy Questar Pipeline became a wholly-owned subsidiary of Dominion Energy Midstream and is therefore consolidated by Dominion Energy Midstream. The accompanying financial statements and related notes have been retrospectively adjusted to include the historical results and financial position of Dominion Energy Questar Pipeline beginning September 16, 2016, the inception date of common control.

The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES, DECGS (DEPC prior to January 1, 2016) or DEQPS to Dominion Energy Midstream on the basis of direct and allocated methods in accordance with Dominion Energy Midstream’s services agreements with DES, DECGS (DEPC prior to January 1, 2016) and DEQPS. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES, DECGS (DEPC prior to January 1, 2016) or DEQPS resources that is attributable to the entities, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES, DECGS (DEPC prior to January 1, 2016) or DEQPS service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.

HOW WE EVALUATE OUR OPERATIONS

Dominion Energy Midstream management uses a variety of financial metrics to analyze our performance. These metrics are significant factors in assessing our operating results and include: (1) EBITDA; (2) Adjusted EBITDA; and (3) distributable cash flow.

EBITDA, Adjusted EBITDA and Distributable Cash Flow

EBITDA represents net income including noncontrolling interest and predecessors before interest and related charges, income tax and depreciation and amortization. Adjusted EBITDA represents EBITDA after adjustment for the EBITDA attributable to predecessors and a noncontrolling interest in Cove Point held by Dominion Energy, less income from equity method investees, plus distributions from equity method investees. Subsequent to the Dominion Energy Questar Pipeline Acquisition, we define distributable cash flow as Adjusted EBITDA less distributions to preferred unitholders, maintenance capital expenditures and interest expense and adjusted for known timing differences between cash and income.

EBITDA, Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures used by our management and by external users of our financial statements, such as investors and securities analysts, to assess:

The GAAP measure most directly comparable to EBITDA and Adjusted EBITDA is net income, and the GAAP measure most directly comparable to distributable cash flow is net cash provided by operating activities. EBITDA, Adjusted EBITDA and distributable cash flow should not be considered alternatives to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA, Adjusted EBITDA and distributable cash flow exclude some, but not all, items that affect net income and operating income, and these measures may vary among other companies. Therefore, EBITDA, Adjusted EBITDA and distributable cash flow as presented may not be comparable to similarly titled measures of other companies.

FACTORS IMPACTING COMPARABILITY OF OUR FINANCIAL RESULTS

Our historical results of operations and cash flows for the periods presented may not be comparable, either from period to period, or going forward, principally for the following reasons:

Cove Point Rate Case

In August 2017, Cove Point filed a proposed stipulation and settlement agreement with FERC, which was approved in November 2017. Under the terms of the settlement agreement, Cove Point’s rates effective October 2017 result in decreases to annual revenues and depreciation expense of approximately $17.7 million and $3.0 million, respectively, compared to the rates in effect through December 31, 2016. See Note 14 to the Consolidated Financial Statements for more information.

Dominion Energy Questar Pipeline Acquisition

In October 2016, Dominion Energy Midstream, following approval by the Conflicts Committee of Dominion Energy Midstream GP, LLC, its general partner, entered into the Dominion Energy Questar Pipeline Contribution Agreement to acquire Dominion Energy Questar Pipeline from Dominion Energy. Upon closing of the agreement in December 2016, Dominion Energy Midstream became the owner of all of the issued and outstanding membership interests of Dominion Energy Questar Pipeline in exchange for consideration consisting of 6,656,839 common units, 11,365,628 Series A Preferred Units and cash of $822.7 million, $300.0 million of which was treated as a debt-financed distribution, for a total value of $1.29 billion. In addition, Dominion Energy Questar Pipeline’s debt of $435.0 million remained outstanding. In connection with the financing of the Dominion Energy Questar Pipeline Acquisition, Dominion Energy Midstream issued 15,525,000 common units to the public in November 2016. Additionally, in December 2016, Dominion Energy Midstream issued 5,990,634 common units and 18,942,714 Series A Preferred Units through a private placement and borrowed $300.0 million under a three-year term loan agreement. See Note 4 to the Consolidated Financial Statements for additional information regarding the Dominion Energy Questar Pipeline Acquisition.

As a result of the transaction, Dominion Energy Midstream owns 100% of the membership interests in Dominion Energy Questar Pipeline and therefore consolidates Dominion Energy Questar Pipeline in its financial statements. Because the contribution of Dominion Energy Questar Pipeline by Dominion Energy to Dominion Energy Midstream is considered to be a reorganization of entities under common control, Dominion Energy Questar Pipeline’s assets and liabilities were recorded in Dominion Energy Midstream’s Consolidated Financial Statements at Dominion Energy’s historical cost. Common control began on September 16, 2016, concurrent with Dominion Energy’s acquisition of Dominion Energy Questar.

Iroquois Rate Settlement

In October 2016, FERC issued an order approving a settlement reached between the parties in the Section 5 rate case initiated on Iroquois’ tariff rates. The settlement resulted in a reduction of Iroquois’ rates to be phased in from September 2016 through September 2018. As a result, Dominion Energy Midstream’s

equity method earnings from Iroquois are expected to decrease ratably during the phase-in period and ultimately by approximately 20% for 2019, excluding the effects of any growth projects. Dominion Energy Midstream’s distributions received from Iroquois are expected to remain consistent with historical levels.

Acquisition of Interest in Iroquois

On August 14, 2015, Dominion Energy Midstream entered into Contribution Agreements with NG and NJNR. On September 29, 2015, pursuant to the Contribution Agreements, Dominion Energy Midstream acquired a 25.93% noncontrolling partnership interest in Iroquois, consisting of NG’s 20.4% and NJNR’s 5.53% partnership interests in Iroquois and, in exchange, Dominion Energy Midstream issued common units representing limited partnership interests in Dominion Energy Midstream to both NG (6,783,373 common units) and NJNR (1,838,932 common units). The number of units was based on the volume-weighted average trading price of Dominion Energy Midstream’s common units for the five trading days prior to August 14, 2015, or $33.23 per unit. The Iroquois investment, accounted for under the equity method, was recorded at $216.5 million based on the value of Dominion Energy Midstream’s common units at closing, including $0.5 million of external transaction costs.

DECG Acquisition

On April 1, 2015, Dominion Energy Midstream entered into a Purchase, Sale and Contribution Agreement with Dominion Energy pursuant to which Dominion Energy Midstream acquired from Dominion Energy all of the issued and outstanding membership interests of DECG in exchange for total consideration of $500.8 million, as adjusted for working capital. The sale of DECG from Dominion Energy to Dominion Energy Midstream is considered to be a reorganization of entities under common control. As a result, Dominion Energy Midstream’s basis is equal to Dominion Energy’s cost basis in the assets and liabilities of DECG. Subsequent to the transaction, Dominion Energy Midstream owns 100% of the membership interests in DECG and therefore consolidates DECG.

Import Contracts

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, assuming it becomes operational, will extend the economic life of Cove Point. 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.

Liquefaction Project

Following the completion and initial startup phase of the Liquefaction Project, we expect that Cove Point will be able to pay the Preferred Return Distributions using a small percentage of its total available cash flows, as we expect Cove Point’s total annual revenues, including reservation charges on the Cove Point Pipeline, to increase substantially notwithstanding the expiration or termination of any existing contracts with its Import Shippers or Storage Customers.

Income Taxes

Federal and state income taxes are reflected on the historical financial statements of Cove Point. Dominion Energy Midstream, as a pass-through entity, generally is not subject to income taxes and does not record any provision for income taxes in its Consolidated Financial Statements. Income taxes will not be included in future periods, except to the extent Dominion Energy Midstream acquires interests in business activities that are conducted in states that impose income taxes on partnerships or if it were to acquire a controlling interest in an entity that is subject to income taxes. However, when Dominion Energy Midstream acquires a controlling interest in a business from Dominion Energy that had previously been subject to income taxes, the income taxes incurred by the business would be included in Dominion Energy Midstream’s Consolidated Financial Statements for any period in which Dominion Energy owned the controlling interest.

ACCOUNTING MATTERS

Critical Accounting Policies and Estimates

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

ACCOUNTING FOR REGULATED OPERATIONS

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

Dominion Energy Midstream evaluates whether or not recovery of its regulatory assets through future rates is probable and makes various assumptions in its analyses. The expectations of future recovery are generally based on orders issued by FERC or

historical experience, as well as discussions with FERC and legal counsel. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. See Note 13 to the Consolidated Financial Statements for additional information.

USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING

At December 31, 2017, Dominion Energy Midstream reported $819.2 million of goodwill on its Balance Sheet.

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

In general, Dominion Energy Midstream estimates the fair value of its reporting units by using a combination of discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. Fair value estimates are dependent on subjective factors such as Dominion Energy Midstream’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion Energy Midstream’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion Energy Midstream has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent tests had been 10% lower, the resulting fair value would have still been greater than the carrying value of the reporting unit tested, indicating that no impairment was present.

See Note 12 to the Consolidated Financial Statements for additional information.

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

Impairment testing for an individual or group of long-lived assets, including intangible assets with definite lives, and equity method investments is required when circumstances indicate those assets may be impaired. When a long-lived asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. When an equity method investment’s carrying amount exceeds its fair value, and the decline in value is deemed to be other-than-temporary, an impairment is recognized to the extent that the fair value is less than its carrying amount. Performing an impairment test on long-lived assets and equity method investments involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets in the case of long-lived assets, and

developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of a market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about the operations of the long-lived assets and equity method investments and the selection of an appropriate discount rate. When determining whether a long-lived asset or asset group has been impaired, management groups assets at the lowest level that has identifiable cash flows. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset or underlying assets of equity method investees, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions.

New Accounting Standards

See Note 3 to the Consolidated Financial Statements for a discussion of new accounting standards.

RESULTS OF OPERATIONS

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

ANALYSIS OF CONSOLIDATED OPERATIONS

Overview

Net revenue reflects operating revenue less purchased gas expense. Purchased gas expense includes the value of natural gas retained for use in routine operations and the cost of LNG cooling quantity purchases. LNG cooling quantity purchases are required for Cove Point to maintain the cryogenic readiness of the Cove Point LNG Facility to the extent market conditions exist that neither import nor, once the Liquefaction Project is completed, export services are being sufficiently utilized. Historically, one or two LNG cooling cargos have been procured annually and billed to the Import Shippers pursuant to certain provisions in Cove Point’s FERC Gas Tariff. Increases or decreases in purchased gas expenses related to LNG cooling quantities are offset by corresponding increases or decreases in operating revenues and thus have been financially neutral to Dominion Energy Midstream. Under the terms of the stipulation and settlement agreement approved by FERC in November 2017, the Import Shippers’ responsibility for costs incurred for any LNG cooling cargos received prior to the earlier of operational commencement of the Liquefaction Project or March 2018 would be reduced to approximately half of such amounts incurred. If the Liquefaction Project has not commenced operations prior to March 2018 and LNG cooling quantities are required, Cove Point is responsible for any costs incurred until the Liquefaction Project commences operations. Upon operational commencement of the Liquefaction Project, the Import Shippers will have responsibility for costs incurred on certain LNG cooling quantities. As Cove Point’s contracts with the Export Customers contain similar cost recovery mechanisms, any LNG cooling quantities procured would be financially neutral to Dominion Energy Midstream upon operational commencement of the Liquefaction Project.

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

2017 vs. 2016

Net revenue increased 6%, primarily due to Dominion Energy Questar Pipeline operations being included for all of 2017 ($164.5 million), the St. Charles Transportation Project ($2.6 million), which was placed into service in June 2016, the Columbia to Eastover Project ($3.4 million), which was placed into service in November 2016, and the Keys Energy Project ($5.3 million), which was placed in service in March 2017. These increases were partially offset by a decrease from import contracts in 2017 ($143.6 million) and the impact of the Cove Point rate case approved by FERC in November 2017 ($5.8 million). Operating revenue increased $185.5 million and purchased gas increased $21.0 million as a result of Dominion Energy Questar Pipeline operations being included for all of 2017. The increases in operating revenue and purchased gas were partially offset by a $17.1 million decrease due to the absence of the receipt of an LNG cooling cargo in 2017, as compared to the receipt of one LNG cooling cargo in 2016.

Other operations and maintenance increased 40% primarily due to Dominion Energy Questar Pipeline operations being included for all of 2017 ($33.0 million) and increases in labor and outside service costs associated with Cove Point’s operations affected by the Liquefaction Project ($13.1 million). These

increases were partially offset by a decrease in acquisition-related costs ($5.0 million) and the absence of organizational design initiative costs incurred during the first quarter of 2016 ($3.3 million).

Depreciation and amortization increased 78%, primarily due to Dominion Energy Questar Pipeline operations being included for all of 2017 ($39.8 million), depreciation related to growth projects placed in service ($1.7 million) and revised depreciation rates effective January 2017 at Cove Point ($3.0 million). These increases were partially offset by the Cove Point rate case settlement approved by FERC in November 2017 ($1.0 million).

Other taxes increased 19%, primarily due to Dominion Energy Questar Pipeline operations being included for all of 2017 ($5.0 million) and increased property taxes related to growth projects placed into service ($1.1 million).

Earnings from equity method investees increased 14%, primarily due to White River Hub being included for all of 2017.

Other income increased 97%, primarily related to an increase in AFUDC associated with rate-regulated projects.

Interest and related charges increased $23.8 million, primarily due to debt acquired in the Dominion Energy Questar Pipeline Acquisition ($17.6 million) and an increase in interest rates on outstanding long-term debt in 2017 as compared to 2016 ($6.5 million).

Income tax expense decreased $6.3 million, as a result of the absence of income taxes attributable to the Dominion Energy Questar Pipeline Predecessor.

2016 vs. 2015

Net revenue increased 27% primarily due to the Dominion Energy Questar Pipeline Acquisition ($70.6 million), DECG results being included in Dominion Energy Midstream for twelve months in 2016, as compared to eleven months in 2015 ($5.9 million), the Edgemoor Project ($4.2 million), which was placed into service in December 2015, the St. Charles Transportation Project ($1.9 million), which was placed into service in June 2016, and the Columbia to Eastover Project ($0.5 million), which was placed into service in November 2016. Operating revenue and purchased gas decreased approximately $26.5 million due to the receipt of one LNG cooling cargo in 2016, as compared to the receipt of two LNG cooling cargoes in 2015. The decrease in purchased gas was partially offset by an increase in gas costs as a result of the Dominion Energy Questar Pipeline Acquisition ($12.2 million).

Other operations and maintenance increased 68% primarily due to the Dominion Energy Questar Pipeline Acquisition ($16.5 million), increases in acquisition-related costs as compared to 2015 ($6.5 million), increases in labor and outside services for Cove Point’s operations affected by the Liquefaction Project ($6.2 million), organizational design initiative costs incurred during the first quarter of 2016 ($3.3 million) and the impact of DECG results being included in Dominion Energy Midstream for twelve months in 2016, as compared to eleven months in 2015 ($2.4 million).

Depreciation and amortization increased 40% primarily due to the Dominion Energy Questar Pipeline Acquisition ($15.6 million), DECG results being included in Dominion Energy Midstream for twelve months in 2016, as compared to eleven months in 2015 ($0.8 million) and depreciation related to growth

projects placed into service ($1.0 million). These increases were partially offset by the absence of accelerated depreciation from 2015 asset retirements associated with the Liquefaction Project ($1.5 million).

Other taxes increased 16% primarily due to the Dominion Energy Questar Pipeline Acquisition ($2.3 million), increased property taxes related to expansion capital projects ($1.0 million) and the impact of DECG results being included in Dominion Energy Midstream for twelve months in 2016, as compared to eleven months in 2015 ($0.6 million).

Earnings from equity method investees increased $16.4 million primarily as a result of the September 2015 acquisition of a 25.93% noncontrolling partnership interest in Iroquois.

Other income increased $2.2 million primarily related to an increase in AFUDC associated with rate-regulated projects in 2016.

Interest and related charges increased $6.7 million primarily due to the Dominion Energy Questar Pipeline Acquisition.

Income tax expense increased $4.2 million as a result of $6.3 million of income taxes attributable to the Dominion Energy Questar Pipeline Predecessor, partially offset by the absence of income taxes associated with the DECG Predecessor ($2.1 million).

SEGMENT RESULTS OF OPERATIONS

Presented below is a summary of contributions by Dominion Energy Midstream’s operating segment to net income including noncontrolling interest and predecessors:

Gas Infrastructure

The following table summarizes the key factors impacting Gas Infrastructure’s contribution to net income including noncontrolling interest and predecessors.

2017 vs. 2016

2016 vs. 2015

Corporate and Other

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

Corporate and Other includes items attributable to Dominion Energy Midstream’s operating segment that are not included in profit measures evaluated by executive management in assessing segment performance or in allocating resources among the segments. See Note 25 to the Consolidated Financial Statements for discussion of these items in more detail. Corporate and Other also includes specific items attributable to the Corporate and Other segment. In 2016, this primarily included transition costs of $7.9 million ($6.9 million after-tax) attributable to the Dominion Energy Questar Pipeline Predecessor associated with Dominion’s acquisition of Dominion Energy Questar.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Dominion Energy Midstream’s ongoing principal sources of liquidity may include distributions received from Cove Point from our Preferred Equity Interest, cash generated from operations of DECG and Dominion Energy Questar Pipeline, distributions received from our noncontrolling partnership interests in Iroquois and White River Hub, borrowings under our credit facility with Dominion Energy and issuances of debt and equity securities. We believe that cash from these sources will be sufficient to pay distributions on our common, subordinated and preferred units while continuing to meet our short-term working capital requirements and our long-term capital expenditure requirements. We expect to have sufficient distributable cash flow to pay the minimum quarterly distribution of $0.1750 per common unit and subordinated unit, which equates to $17.5 million per quarter, or $69.9 million per year in the aggregate, based on the number of common units and subordinated units currently outstanding. We do not have a legal or contractual obligation to pay

distributions quarterly or on any other basis or at the minimum quarterly distribution rate or at any other rate on our common or subordinated units, and there is no guarantee that we will pay distributions to such unitholders in any quarter.

Additionally, the holders of the Series A Preferred Units are entitled to receive cumulative quarterly distributions of $0.3134 per Series A Preferred Unit for each quarter ending before December 1, 2018, which distributions commenced with the quarter ended December 31, 2016 with a prorated amount from the date of issuance to be paid for such quarter. We cannot pay any distributions on any junior securities, including any of the common units, subordinated units and the IDRs, prior to paying the quarterly distribution payable to holders of the Series A Preferred Units, including any previously accrued and unpaid distributions.

Outstanding Indebtedness

In connection with the Offering, Dominion Energy Midstream entered into a $300.0 million credit facility with Dominion Energy, allowing it to competitively pursue acquisitions and future organic growth opportunities or to otherwise meet its financial needs. At December 31, 2017 and 2016, $26.4 million and $63.2 million was outstanding against the credit facility, respectively. In January and February 2018, Dominion Energy Midstream drew $34.5 million on the credit facility to fund property tax at DECG and expansion capital expenditures. See Note 22 to the Consolidated Financial Statements for a summary of certain key terms of the credit facility with Dominion Energy.

Dominion Energy Midstream has indicated its intention to obtain a $500.0 million revolving credit facility in the first quarter of 2018 to replace the existing $300.0 million credit facility with Dominion Energy. The revolving credit facility is expected to have a three-year maturity, bear interest at a variable rate and have financial covenants, including a quarterly leverage ratio, similar to the existing $300.0 million term loan agreement described below.

On December 1, 2016, in connection with the Dominion Energy Questar Pipeline Acquisition, Dominion Energy Midstream borrowed $300.0 million under a three-year term loan agreement, with a variable interest rate. Interest on the term loan agreement is payable quarterly, and all principal and accrued interest is due and payable at maturity on December 1, 2019. See Note 17 to the Consolidated Financial Statements for a summary of certain key terms of the term loan agreement.

In connection with the Dominion Energy Questar Pipeline Acquisition, Dominion Energy Midstream acquired the existing long-term debt at Dominion Energy Questar Pipeline. At December 31, 2017, this debt consisted of the following instruments:

Capital Requirements

CAPITAL SPENDING

Our operations can be capital intensive, requiring investments to expand, upgrade, maintain or enhance existing operations and to meet environmental and operational regulations. As defined in our partnership agreement, our capital requirements consist of:

For the year ended December 31, 2017, Dominion Energy Midstream paid total capital expenditures of $919.0 million, which included $87.9 million of maintenance capital expenditures.

Our significant capital projects, all of which are expansion projects, are described further below:

In addition to the expansion projects described above, Cove Point will incur maintenance capital expenditures to acquire spare parts for critical components of its Liquefaction Project. These costs are expected to be approximately $5 million in the first half of 2018.

Dominion Energy has indicated that it intends to provide the funding necessary for the remaining construction costs and other capital expenditures of Cove Point, including the Liquefaction Project and Eastern Market Access Project, but it is under no contractual obligation to do so and has not secured all of the funding necessary to cover these costs, as it intends to finance these costs as they are incurred using its consolidated operating cash flows in addition to proceeds from capital markets transactions. However, Dominion Energy has entered into guarantee arrangements on behalf of Cove Point to facilitate the Liquefaction Project, including guarantees supporting the terminal services and transportation agreements as well as the engineering, procurement and construction contract for the Liquefaction Project. Two of the guarantees have no stated limit, one guarantee has a $150 million limit and one guarantee has a $1.75 billion aggregate limit with an annual draw limit of $175 million. In the event that Dominion Energy does not satisfy its obligations under these guarantee arrangements or otherwise does not agree to provide the funding necessary for the remaining development costs and other capital expenditures of Cove Point, or is unable to obtain such funding in the amounts required or on terms acceptable to Dominion Energy, Cove Point would require substantial external debt or equity financing to complete the construction or other capital expenditures of the Liquefaction Project and Eastern Market Access Project.

Distributions

Distributions are declared subsequent to quarter end. The table below summarizes the quarterly distributions on common and subordinated units.

Record holders of the Series A Preferred Units are entitled to receive cumulative quarterly distributions, payable in cash, payable in kind or a combination thereof at the option of our general partner, equal to $0.3134 in respect of each quarter ending before December 1, 2018. The table below summarizes the quarterly distributions on the Series A Preferred Units.

Cash Flows

A summary of cash flows is presented below:

OPERATING CASH FLOWS

In 2017, net cash provided by Dominion Energy Midstream’s operating activities decreased $5.7 million, primarily due to lower revenues from Cove Point import contracts in 2017, partially offset by Dominion Energy Questar Pipeline operations being included for all of 2017.

INVESTING CASH FLOWS

In 2017, net cash used in Dominion Energy Midstream’s investing activities decreased $1.2 billion, primarily due to lower expenditures for the Liquefaction Project and the absence of the Dominion Energy Questar Pipeline Acquisition.

FINANCING CASH FLOWS

In 2017, net cash provided by Dominion Energy Midstream’s financing activities decreased $1.2 billion, primarily due to lower capital contributions from Dominion Energy to fund the Liquefaction Project and the absence of the issuance of common and preferred units in connection with the Dominion Energy Questar Pipeline Acquisition.

In May 2016, Dominion Energy Midstream filed an SEC shelf registration for the ability to sell common units through an at-the-market program and pursuant to which it may offer from time to time up to $150.0 million aggregate amount of its common units. Sales of common units, if any, will be made by means of ordinary brokers’ transactions on the NYSE, in block transactions, or as otherwise agreed to between the managers and us. In July 2016, Dominion Energy Midstream entered into an equity distribution agreement with nine separate managers to effect sales under the program. In 2017, Dominion Energy Midstream provided sales instructions to three of the managers and issued 574,260 units and received cash proceeds of $18.0 million, net of fees and commissions of $0.2 million. In January 2018, Dominion Energy Midstream provided sales instructions to one manager and issued 125,819 units and received cash proceeds of $3.9 million, net of fees and commissions of $0.1 million. Dominion Energy Midstream still has the ability to issue $127.8 million of common units under the program.

CUSTOMER CONCENTRATION

Dominion Energy Midstream provides service to approximately 150 customers, including the Storage Customers, marketers or end users, power generators, utilities and the Import Shippers. The two largest customers comprised approximately 27% of the total transportation and storage revenues for the year ended December 31, 2017. Upon commencement of commercial operation of the Liquefaction Project, it is expected that the Export Customers will represent a significant portion of the total transportation and storage revenues. See Note 21 to the Consolidated Financial Statements for additional information.

CONTRACTUAL OBLIGATIONS

Dominion Energy Midstream is party to numerous contracts and arrangements obligating it to make cash payments in future years. These contracts include debt agreements, contracts for capital projects and the purchase of goods and services. Presented below is a table summarizing cash payments that may result from contracts of which Dominion Energy Midstream or its subsidiaries is party as of December 31, 2017. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities in the Consolidated Balance Sheets,

other than current maturities of long-term debt. The majority of Dominion Energy Midstream’s current liabilities will be paid in cash in 2018.