DOMINION ENERGY, INC - Annual Report: 2019 (Form 10-K)

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Common Stock, no par value

Limited Liability Company Membership Interests

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

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

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

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non-accelerated

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12b-2

Virginia Electric and Power Company

Dominion Energy Gas Holdings, LLC

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non-affiliates

Portions of Dominion Energy’s 2020 Proxy Statement are incorporated by reference in Part III.

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

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

Dominion Energy, Inc., Virginia Electric and

Power Company and Dominion Energy Gas Holdings, LLC

 

 

 

 

Glossary of Terms

    

10-K

    

    

    

 

    

Part I

, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Dominion Energy’s strategy is to be a leading sustainable provider of electricity, natural gas and related services to customers primarily in the eastern and Rocky Mountain regions of the U.S. As of December 31, 2019, Dominion Energy’s portfolio of assets includes approximately 30,700 MW of electric generating capacity, 10,400 miles of electric transmission lines, 85,000 miles of electric distribution lines, 14,600 miles of natural gas transmission, gathering and storage pipelines and 103,400 miles of gas distribution pipeline, exclusive of service lines. As of December 31, 2019, Dominion Energy serves more than 7 million utility and retail energy customers and operates one of the nation’s largest underground natural gas storage systems, with approximately 1 trillion cubic feet of storage capacity.

In January 2019, Dominion Energy completed the SCANA Combination in a merger valued at $13.4 billion. SCANA, which operates as a wholly-owned subsidiary of Dominion Energy, is primarily engaged in the generation, transmission and distribution of electricity in the central, southern and southwestern portions of South Carolina and in the distribution of natural gas in North Carolina and South Carolina. DESC, a wholly-owned subsidiary of SCANA, is consolidated by Dominion Energy and remains an SEC registrant. However, its Form is filed separately and is not combined herein.

Dominion Energy continues to focus on expanding and improving its regulated and long-term contracted electric and natural gas businesses while transitioning to a cleaner energy future. The $26 billion growth capital plan for 2019 through 2023 includes a focus on upgrading the electric system in Virginia through investments in additional renewable generation facilities, strategic undergrounding and energy conservation programs. Renewable generation facilities are expected to include investments in utility-scale solar and offshore wind projects. In addition, Dominion Energy is currently seeking, or intends to seek, license extensions for its regulated nuclear power stations in Virginia. Other drivers for the growth capital expenditure plan include agriculture-waste-to-energy initiatives, the replacement of gas distribution pipeline, the construction of infrastructure to handle the increase in natural gas production from the Marcellus and Utica Shale formations, including investing in Atlantic Coast Pipeline which is focused on constructing an approximately natural gas pipeline running from West Virginia through Virginia to North Carolina, to increase natural gas supplies in the region. Dominion Energy also plans to continue upgrading its gas and electric transmission and distribution networks while also meeting environmental requirements and standards set by various regulatory bodies. 

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

a limited liability company formed in September 2013,is a wholly-owned subsidiary of Dominion Energy and a holding company. Following the Dominion Energy Gas Restructuring, Dominion Energy Gas serves as the intermediate parent company for Dominion Energy’s FERC-regulated interstate natural gas transmission pipeline and underground storage systems in the eastern and Rocky Mountain regions of the U.S., as well as for the Cove Point LNG Facility. Dominion Energy Gas’ principal operating subsidiaries include DETI, DECG, Dominion Energy Questar Pipeline and a controlling 75% interest in Cove Point. In addition, Dominion Energy Gas holds a 50% noncontrolling partnership interest in Iroquois, a FERC-regulated interstate natural gas pipeline. All of Dominion Energy Gas’ membership interests are owned by Dominion Energy.

The Companies make their SEC filings available, free of charge, including the annual report on Form quarterly

 

 

reports on Form current reports on Form and any amendments to those reports, through Dominion Energy’s website, http://www.dominionenergy.com, as soon as reasonably practicable after filing or furnishing the material to the SEC. Information contained on Dominion Energy’s website, including but not limited to reports mentioned in , is not incorporated by reference in this report.

In January 2019, Dominion Energy and SCANA completed a merger valued at $13.4 billion, inclusive of SCANA’s outstanding debt, which totaled $6.9 billion at closing. SCANA operates as a wholly-owned subsidiary of Dominion Energy. See Note 3 to the Consolidated Financial Statements for additional information.

 

 

In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy marketing operations for total consideration of $143 million, subject to customary approvals and certain adjustments. In December 2017, the first phase of the agreement closed for $79 million. In October 2018, the second phase of the agreement closed for $63 million. Pursuant to the agreement, Dominion Energy entered into a commission agreement with the buyer upon the first closing in December 2017, under which the buyer will pay a commission in connection with the right to use Dominion Energy’s brand in marketing materials and other services over a term. See Note 10 to the Consolidated Financial Statements for additional information.

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

 

 

 

 

 

 

 

 

 

 

Virginia Power’s growth capital plan includes spending approximately $16 billion from 2019 through 2023 to upgrade or add new transmission lines, distribution lines, substations, and other facilities, as well as maintain existing and construct new generation capacity to meet growing electricity demand within its service territory in order to maintain reliability and regulatory compliance. The proposed infrastructure projects and investment commitments are intended to address both continued customer growth and increases in electricity consumption which are primarily driven by new and larger data center customers, as well as support its Subsequent License Renewal projects as it is seeking license extensions for the regulated nuclear fleet in Virginia. See Properties and Environmental Strategy for additional information on this and other utility projects.

Virginia Power has also created a plan to transform its electric grid into a smarter, stronger and greener grid. This plan will address the structural limitations of Virginia Power’s distribution grid in a systematic manner in order to recognize and

 

 

accommodate fundamental changes and requirements in the energy industry. The objective is to address both customer and system needs by (i) achieving even higher levels of reliability and resiliency against natural and threats, (ii) leveraging technology to enhance the customer experience and improve the operation of the system and (iii) safely and effectively integrating new utility-scale renewable generation and storage as well as customer–level distributed energy resources such as rooftop solar and battery storage. In 2019, the Virginia Commission approved a portion of this plan.

Revenue provided by electric distribution and generation operations is based primarily on rates established by the Virginia and North Carolina Commissions. Approximately 84% of revenue comes from serving Virginia jurisdictional customers. Base rates for the Virginia jurisdiction are set using a modified rate model, and are generally designed to allow an opportunity to recover the cost of providing utility service and earn a reasonable return on investments used to provide that service. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures. Electric operations continue to focus on improving service and experience levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 138 minutes for the three-year average ending 2019, up from the previous three-year average of 134 minutes. This increase is primarily due to increased storm activity.

and no such competition is currently permitted. Historically, since its electric transmission facilities are integrated into PJM and electric transmission services are administered by PJM, there was no competition in relation to transmission service provided to customers within the PJM region. However, competition from PJM transmission owners for development, construction and ownership of certain transmission facilities in Virginia Power’s service territory is permitted pursuant to Order 1000, subject to state and local siting and permitting approvals. This could result in additional competition to build and own transmission infrastructure in Virginia Power’s service area in the future and could allow Dominion Energy to seek opportunities to build and own facilities in other service territories. Additionally, there is some competition for Virginia Power’s generation operations for Virginia jurisdictional electric utility customers that meet certain size requirements or that seek to purchase 100% renewable energy from competitive suppliers. See under in for more information. Currently, North Carolina does not offer retail choice to electric customers.

Virginia Power’s operations are not currently subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 16 to 25 years. However, in the future, such operations may compete with other power generation facilities to serve certain large-scale customers after the power purchase agreements expire.

Virginia Power’s electric distribution and generation operations, including the rates it may charge to jurisdictional customers, as well as wholesale electric transmission rates, tariffs and terms of service, are subject to regulation by the Virginia and North Carolina Commissions as well as FERC, the NRC, the EPA, the DOE and the Army Corps of Engineers. See and in in Item 7 MD&A and Notes 13 and 23 to the Consolidated Financial Statements for additional information.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

contractual obligations in in Item 7. MD&A.

 

 

 

 

 

 

 

 

 

 

 

 

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

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

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

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

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

 

 

 

Under the current operating licenses, Virginia Power is scheduled to decommission the Surry and North Anna units during the period 2032 to 2078. NRC regulations allow licensees to apply for extension of an operating license in up to increments. In 2019, Virginia Power applied for renewal of its operating licenses for an additional 20 years for the two nuclear units at Surry. Under these renewal applications, the two nuclear units will be allowed to generate electricity through 2052 and 2053, if approved. Virginia Power expects to submit a license extension application for the two units at North Anna in 2020. Between the four units, Virginia Power estimates that it could spend approximately $3 billion to $4 billion over the next several years on the relicensing process. The existing regulatory framework in Virginia provides rate recovery mechanisms for such costs. The most recent site-specific study completed for Surry and North Anna was performed in 2019.

 

 

 

 

 

 

 

 

 

The Gas Transmission & Storage Operating Segment of Dominion Energy Gas includes FERC regulated interstate natural gas transmission pipeline and underground storage systems in the eastern and Rocky Mountain regions of the U.S. (primarily through DETI, DECG and Dominion Energy Questar Pipeline), LNG import/export and storage (through its 75% controlling interest in Cove Point) as well as a 50% noncontrolling partnership interest in Iroquois. See below for additional information regarding the Iroquois investment.

The Gas Transmission & Storage Operating Segment of Dominion Energy also includes nonregulated retail natural gas marketing, development of renewable natural gas and LNG infrastructure and its investments in Atlantic Coast Pipeline, Align RNG and Wrangler. See below for additional information regarding the Atlantic Coast Pipeline, Align RNG and Wrangler investments.

Earnings for the primarily result from rates established by FERC. Approximately 94% of Dominion Energy Gas’ transmission capacity is subscribed including 91% under long-term contracts (two years or greater) and 3% on a basis. Dominion Energy Gas’ storage services are 100% subscribed with long-term contracts. Revenues derived from Dominion Energy Gas’ pipeline operations are primarily from reservation charges for firm transportation and storage services as provided for in their FERC-approved tariffs. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their capital investments.

Additionally, Dominion Energy Gas receives revenue from firm contractual arrangements, including negotiated rates, for certain LNG storage and terminalling services. The Liquefaction Facility has a firm contracted capacity for LNG loading onto ships of approximately 4.6 Mtpa (0.66 bcfe/day)

 

 

 

Dominion Energy Gas’ natural gas transmission and storage operations, as well as its LNG import and storage operations are regulated primarily by FERC.See in for more information.

For a description of existing facilities see Item 2.Properties

Thefollowing significant projects are under construction or development to better serve customers or expand its service offerings.

In August 2018, DETI executed a binding precedent agreement with a customer for the West Loop project. The project is expected to cost approximately $95 million and provide 150,000 Dths per day of firm transportation service from Pennsylvania to Ohio for delivery to a proposed combined-cycle, natural electric power generation facility to be located in Columbiana County, Ohio. In December 2018, DETI filed an application to request FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service by the end of 2021.

In December 2014, DETI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header project, a project to provide approximately 1,500,000 Dths per day of firm transportation service to various customers. Atlantic Coast Pipeline has continued to experience delays in obtaining permits necessary for construction and delays in construction due to judicial actions. As a result, project cost estimates are $725 million to $775 million, excluding financing costs. Project construction is expected to be completed by the end of 2021 with in early 2022.

In September 2015, Dominion Energy, through Dominion Energy Midstream, acquired an additional 25.93% interest in Iroquois. In November 2019, following completion of the Dominion Energy Gas Restructuring, this 25.93% investment was transferred to Dominion Energy Gas which now holds a 50% interest in Iroquois, with TransCanada holding the remaining 50% interest. Iroquois owns and operates a 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 through interconnecting pipelines and exchanges. Iroquois’ pipeline extends from the U.S.-Canadian border at Waddington, New York

 

 

 

—In September 2014, Dominion Energy, along with Duke and Southern, announced the formation of Atlantic Coast Pipeline. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion Energy an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. The members hold the following membership interests: Dominion Energy, 48%; Duke, 47%; and Southern, 5%. In February 2020, Dominion Energy entered an agreement to acquire Southern’s 5% membership interest. Atlantic Coast Pipeline is focused on constructing an approximately natural gas pipeline running from West Virginia through Virginia to North Carolina. Atlantic Coast Pipeline has executed agreements with customers for a substantial majority of the capacity of the Atlantic Coast Pipeline Project. See Future Issues and Other Matters in Item 7 for information on estimated project costs and date and Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Atlantic Coast Pipeline.

—In November 2018, Dominion Energy announced the formation of Align RNG, an equal partnership with Smithfield Foods, Inc. As announced in October 2019, Align RNG expects to invest $500 million to develop assets to capture methane from hog farms across Virginia, North Carolina, Utah, Arizona and California and convert it into pipeline quality natural gas.

—In September 2019, Dominion Energy, announced the formation of Wrangler, a nonregulated natural gas retail energy marketing business serving Georgia and other southeastern states in the U.S. Wrangler was created in partnership with Interstate Gas Supply, Inc., with Dominion Energy contributing its nonregulated retail energy marketing operations and Interstate Gas Supply, Inc. contributing cash. Dominion Energy has a 20% noncontrolling ownership interest in Wrangler. See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Wrangler.

The Gas Distribution Operating Segment of Dominion Energyincludes Dominion Energy’s regulated natural gas sales, transportation, gathering and distribution operations in Ohio, West Virginia, North Carolina, Utah, southwestern Wyoming and southeastern Idaho (through East Ohio, Hope, PSNC and Questar Gas) which collectively serve approximately 3.0 million residential, commercial and industrial customers.

Earnings for the Gas Distribution Operating Segment of Dominion Energyprimarily result from rates established by the Ohio, West Virginia, North Carolina, Utah, Wyoming and Idaho Commissions. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their capital investments. Variability in earnings primarily results from changes in operating and maintenance expenditures, as well as changes in rates and the economy.

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

 

 

 

Gas Distribution’s operations, including the rates that it may charge customers, are regulated by the Ohio, West Virginia, North Carolina, Utah, Wyoming and Idaho Commissions as well as PHMSA and the U.S. Department of Transportation. See in for more information.

For a description of existing facilities see Item 2.Properties

—In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In September 2016, the Ohio Commission approved a stipulation filed jointly by East Ohio and the Staff of the Ohio Commission to continue the PIR program and associated cost recovery for another five-year term beginning in 2017, and to permit East Ohio to increase its annual capital expenditures to $200 million by 2018 with a 3% increase per year thereafter subject to the annual cost recovery rate increase caps proposed by East Ohio. See Note 13 in the Consolidated Financial Statements for further information.

—In 2010, Questar Gas began replacing aging high pressure infrastructure under a cost-tracking mechanism that allows it to place into rate base and earn a return on capital expenditures associated with a multi-year natural gas infrastructure-replacement program upon the completion of each project. At that time, the commission-allowed annual spending in the replacement program was approximately $55 million.

In its 2014 Utah general rate case, Questar Gas received approval to include intermediate high pressure infrastructure in the replacement program and increase the annual spending limit to approximately $65 million, adjusted annually using a gross domestic product inflation factor. At that time, 420 miles of high pressure pipe and 70 miles of intermediate high pressure pipe were identified to be replaced in the program over a period. Questar Gas has spent an average of $68 million each year through 2019 under this program. The program is evaluated in each Utah general rate case. In February 2020, the Utah Commission approved the 2020 annual spending limit for the infrastructure replacement program to be $72 million, adjusted annually thereafter using a gross domestic product inflation factor.

In April 2019, Questar Gas filed a request with the Utah Commission for to construct an LNG storage facility with a liquefaction rate of 8.2 million cubic feet per day. In October 2019, the Utah Commission granted to construct the LNG storage facility.

—The North Carolina Commission has authorized PSNC to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. Projected integrity management plant investment for the period 2020 to 2022 for which recovery is expected is approximately $95 million.

Dominion Energy’s natural gas supply is obtained from various sources including purchases from major and independent producers in the and Gulf Coast regions, local producers in the Appalachian area, gas marketers and, for Questar Gas specifically, from Wexpro and other producers in the Rocky Mountain region. Wexpro’s gas development and production operations serve over half of Questar Gas’ gas supply requirements in accordance with the Wexpro Agreement and the Wexpro II Agreement, comprehensive agreements with the states of Utah and Wyoming.

 

 

 

 

 

DESC’s electric distribution service, including the rates it may charge to jurisdictional customers, is subject to regulation by the South Carolina Commission. DESC’s electric generation operations are subject to regulation by the South Carolina Commission, FERC, the NRC, the EPA, the DOE and various other federal, state and local authorities. DESC’s electric transmission service is primarily regulated by FERC and the DOE. DESC’s gas distribution operations are subject to regulation by the South Carolina Commission, as well as PHMSA, the U.S. Department of Transportation and the South Carolina Office of Regulatory Staff for enforcement of federal and state pipeline safety requirements. See and in for more information.

 

 

 

 

 

 

 

 

—DESC purchases natural gas under contracts with producers and marketers on both a short-term and long-term basis at market-based prices. The gas is delivered to

 

 

—DESC primarily obtains coal through short-term and long-term contracts with suppliers located in eastern Kentucky, Tennessee, Virginia and West Virginia. These contracts provide for approximately 2.1 million tons annually. These contracts expire at various times through 2020. Spot market purchases may occur when needed or when prices are believed to be favorable.

—DESC primarily utilizes long-term contracts to support its nuclear fuel requirements. DESC, for itself and as agent for Santee Cooper, and Westinghouse are parties to a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, DESC supplies enriched products to Westinghouse, who in turn supplies nuclear fuel assemblies for Summer. Westinghouse is DESC’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements through 2033.

DESC has a interest in one licensed, operating nuclear reactor at Summer in South Carolina.

The current operating license for Summer expires in 2042. NRC regulations allow licensees to apply for extension of an operating license in up to increments. DESC is considering an operating license renewal for Summer.

The ContractedGeneration Operating Segment derives its earnings primarily from Dominion Energy’s merchant generation assets, as well as from associated capacity and ancillary services. Variability in earnings provided by Millstone relates to changes in market-based prices received for electricity and capacity as well as the timing, duration and costs of scheduled and unscheduled outages. Approximately half of Millstone’s output is sold under the Millstone 2019 power purchase agreements, which commenced in October 2019 following approval by PURA in 2019. Market-based prices for electricity are largely dependent on commodity prices and the demand for electricity. Capacity prices are dependent upon resource requirements in relation to the supply available (both existing and new) in the forward capacity auctions, which are held approximately three years in advance of the associated delivery year. Dominion Energy manages the electric price volatility of Millstone by hedging a substantial portion of its expected near-term energy sales not subject to the Millstone 2019 power purchase agreements with derivative instruments.

 

 

Dominion Energy’s contracted generation fleet is subject to regulation by the NRC, the EPA, the DOE, the Army Corps of Engineers and other federal, state and local authorities. See in Item 7, MD&A and Notes 13 and 23 to the Consolidated Financial Statements for more information.

Dominion Energy plans to acquire or construct certain solar facilities in the See Note 10 to the Consolidated Financial Statements for more information.

Contracted Generation’s renewable fleet utilizes solar and wind energy to power its electric generation while Millstone utilizes nuclear fuel to power its electric generation. In addition, Dominion Energy occasionally purchases electricity from the spot market to satisfy physical forward sale requirements, as described below. Some of these agreements have fixed commitments and are included as contractual obligations in in Item 7. MD&A.

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

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

 

 

 

 

 

 

 

 

 

 

 

 

The Regulation Act provides for a rate model and permits Virginia Power to seek recovery of costs for new generation projects, including pumped hydroelectricity generation and storage facilities as well as extensions of operating licenses of nuclear power generation facilities, FERC-approved transmission costs, underground distribution lines, certain environmental compliance, conservation and energy efficiency programs and renewable energy programs through stand-alone rate adjustment clauses, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.

In March 2018, the GTSA reinstated base rate reviews on a triennial basis other than the first review, which will be a quadrennial review, occurring for Virginia Power in 2021 for the four successive test periods beginning January 1, 2017 and ending December 31, 2020.

 

 

See in Item 7. MD&A and Note 13 to the Consolidated Financial Statements for additional information.

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

DESC’s retail electric base rates in South Carolina are regulated on a basis subject to South Carolina statutes and the rules and procedures of the South Carolina Commission. South Carolina base rates are set by a process that allows DESC to recover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the South Carolina Commission, retail electric rates may be subject to review and possible reduction, which may decrease DESC’s future earnings. Additionally, if the South Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, DESC’s future earnings could be negatively impacted. Fuel costs are reviewed annually by the South Carolina Commission, as required by statute, and fuel rates are subject to revision in these annual fuel proceedings.

See Notes 3 and 13 to the Consolidated Financial Statements for additional information.

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

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

 

 

 

 

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

PSNC is subject to regulation of rates and other aspects of its business by the North Carolina Commission. When necessary, PSNC seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the by rate class. Base rates for PSNC are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. The volumetric charges for the residential and commercial customers are subject to revenue decoupling and adjusted for changes in usage per customer.

See Notes 3 and 13 to the Consolidated Financial Statements for additional information.

DESC is subject to regulation of rates and other aspects of its natural gas distribution service by the South Carolina Commission. DESC provides retail natural gas service to customers in areas in which it has received authorization from the South Carolina Commission and in municipalities in which it holds a franchise. DESC’s base rates can be adjusted annually, pursuant to the Natural Gas Rate Stabilization Act, for recovery of costs related to natural gas infrastructure. Base rates are set based on the by rate class approved by the South Carolina Commission in the latest general rate case. Base rates for DESC are based primarily on a rate design methodology in which the majority of operating costs are recovered through volumetric charges. DESC also utilizes a weather normalization adjustment to adjust its base rates during the winter billing months for residential and commercial customers to mitigate the effects of unusually cold or warm weather.

Since October 2000, East Ohio has offered the Energy Choice program, under which residential and commercial customers are encouraged to purchase gas directly from retail suppliers or through a community aggregation program. In October 2006, East Ohio restructured its commodity service by entering into gas purchase contracts with selected suppliers at a fixed price above the New York Mercantile Exchange settlement and passing that gas cost to customers under the Standard Service

 

 

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

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

 

 

Dominion Energy and Dominion Energy Gas operate in compliance with FERC standards of conduct, which prohibit the sharing of certain transmission information or customer specific data by its interstate gas transmission and storage companies with function employees. Pursuant to these standards of conduct, Dominion Energy and Dominion Energy Gas also make certain informational postings available on Dominion Energy’s website.

Each of the Companies’ operating segments is subject to substantial laws, regulations and compliance costs with respect to environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of significant penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Companies. If compliance expenditures and associated operating costs are not recoverable from customers through regulated rates (in regulated businesses) or market prices (in unregulated businesses), those costs could adversely affect future results of operations and cash flows. The Companies have applied for or obtained the necessary environmental permits for the construction and operation of their facilities. Many of these permits are subject to reissuance and continuing review. For a discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance required to be discussed in this Item, see in in Item 7. MD&A. Additional information can also be found in Item 3. Legal Proceedings and Note 23 to the Consolidated Financial Statements.

The Companies support a federal climate change program that would provide a consistent, economy-wide approach to addressing this issue. Regardless of federal action, the Companies are reducing their GHG emissions while meeting the growing needs of their customers. Dominion Energy’s CEO and operating segment CEOs are responsible for compliance with the laws and regulations governing environmental matters, including GHG emissions, and Dominion Energy’s Board of Directors receives periodic updates on these matters. See below in in Item 7. MD&A and Note 23 to the Consolidated Financial Statements for information on climate change legislation and regulation.

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

Dominion Energy is subject to various federal and state laws and implementing regulations governing the management, storage, treatment, reuse and disposal of waste materials and hazardous substances, including the Resource Conservation and Recovery Act of 1976, CERCLA, the Emergency Planning and Community Act of 1986 and the Toxic Substances Control Act of 1976. Dominion Energy’s operations and construction activities, including activities associated with oil and gas production and gas storage wells, generate waste. Across Dominion Energy, completion water is disposed at commercial disposal

 

 

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

The NRC also requires Dominion Energy and Virginia Power to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and Dominion Energy and Virginia Power are required by the NRC to be financially prepared. For information on decommissioning trusts, see , and above and Notes 3 and 9 to the Consolidated Financial Statements. See Notes 3 and 23 to the Consolidated Financial Statements for information on spent nuclear fuel.

 

 

 

 

 

 

 

 

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

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

 

 

In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR Program, the Natural Gas STAR Methane Challenge 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. Dominion Energy is a member of the Methane Challenge program and East Ohio, Hope, DETI and Questar Gas were founding partners. Dominion Energy is a member of the EPA’s voluntary Natural Gas STAR program. Dominion Energy joined the One Future Coalition and participated in the 2018 and 2019 progress reports. One Future is an group and member companies pledge to limit methane emissions to below 1% of gas throughput across the entire natural gas value chain. The entities acquired in the SCANA Combination are expected to join the voluntary methane programs in 2020.

 

 

 

Dominion Energy’s investment plan from 2019 through 2023 includes a focus on upgrading the electric system in Virginia through investments in additional renewable generation facilities, smart meters, customer information platform, intelligent grid devices and associated control systems, physical and cyber security investments, strategic undergrounding and energy conservation programs. Dominion Energy also plans to upgrade its gas and electric transmission and distribution networks and meet environmental requirements and standards set by various regulatory bodies. These enhancements are aimed at meeting Dominion Energy’s continued goal of providing reliable service, to address increasing electricity consumption, and make Dominion Energy’s system more responsive to customers’ desire to more efficiently manage their energy consumption and more adaptive to renewable resources and battery technologies. See for additional information.

The Companies have also implemented infrastructure improvements and improved operational practices to reduce the GHG emissions from their natural gas facilities. Dominion Energy and Dominion Energy Gas, in connection with the investment plan, are also pursuing the construction or upgrade of regulated infrastructure in their natural gas businesses. The Companies have made voluntary commitments as part of the EPA Methane Challenge Program to continue to reduce methane emissions as part of these improvements. See for additional information, including natural gas infrastructure projects.

 

 

 

 

 

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

 Revenue provided by the Companies’ electric transmission, distribution and generation operations and by gas transmission and distribution operations is based primarily on rates approved by state and federal regulatory agencies. The profitability of the Companies’ businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.

In states other than Virginia, Dominion Energy and Virginia Power’s retail electric base rates for generation and distribution services to customers are regulated on a basis subject to the statutes, rules and procedures of such states. Dominion Energy’s rates for gas distribution to retail customers are similarly regulated at the state level. If retail electric or gas earnings exceed the returns established by state utility commissions, retail electric rates or gas rates may be subject to review and possible reduction, which may decrease the Companies’ future earnings. Additionally, if any state utility commission

 

 SCANA and DESC are defendants in numerous federal and state legal proceedings and governmental investigations relating to the decision to abandon construction at the NND Project. Among other things, the lawsuits and investigations allege misrepresentation, failure to properly manage the NND Project, unfair trade practices and violation of anti-trust laws. Additionally, pursuant to the SCANA Merger Agreement and applicable indemnification agreements, SCANA is indemnifying former directors and officers of SCANA and DESC who are defendants in federal and state legal proceedings relating to the decision to abandon construction at the NND Project and the subsequent SCANA Combination. Among other things, the lawsuits allege breaches of various fiduciary duties.

 Dominion Energy and Virginia Power’s generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize RTOs to make changes in market design. FERC also periodically reviews Dominion Energy’s authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets or its interpretation of market rules, Dominion Energy or Virginia Power’s authority to sell power at market-based rates, or changes to pricing rules or rules involving revenue calculations, could adversely impact the future results of Dominion Energy or Virginia Power’s generation business. For example, in December 2019, FERC issued an order on PJM’s Minimum Offer Price Rule proposals finding the PJM tariff unjust and unreasonable and directed PJM to expand the Minimum Offer Price Rule to all existing and new generation resources benefitting from a state subsidy to address the effects of state subsidies on new and existing resources on the PJM capacity market. The expanded Minimum Offer Price Rule will set a floor price on new and existing state subsidized resources that do not seek a FERC exemption, increasing their risk of failing to clear the capacity auction and

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

 Excess accumulated deferred income taxes due to the reduction in the corporate income tax rates to 21% under the provisions of the 2017 Tax Reform Act have been recognized as regulatory liabilities and are expected to be shared with customers, generally through reductions in future rates or in the form of credits to customer bills. The 2017 Tax Reform Act includes provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential reductions in future rates attributable to other, related excess deferred taxes may be determined by our regulators. The amount and timing of these reductions could be material to the Companies’ results of operations, cash flows and/or financial condition.

 

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

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

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

 The ACE Rule, which became effective in September 2019, is targeted at reducing CO emissions from existing coal-fired power plants. The ACE

 Dominion Energy and Virginia Power historically produced and continue to produce coal ash, or CCRs, as a of their coal-fired generation operations. The ash is stored and managed in impoundments (ash ponds) and landfills located at 11 different facilities, eight of which are at Virginia Power.

 

 Several facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects have been announced and additional projects may be considered in the future. The Companies compete for projects with companies of varying size and financial capabilities, including some that may have competitive advantages. Commencing construction on announced and future projects may require approvals from applicable state and federal agencies, and such approvals could include mitigation costs which may be material to the Companies. Projects may not be able to be completed on time or in accordance with our estimated costs as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a decline in the credit strength of counterparties or vendors, or other factors beyond the Companies’ control. For example, Atlantic Coast Pipeline has experienced certain delays in obtaining and maintaining permits necessary for construction along with construction delays due to judicial actions which has impacted the cost and schedule for the Atlantic Coast Pipeline Project. Even if facility construction, pipeline, expansion, electric transmission line, conversion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of the Companies following completion of the projects may not meet expectations.  and operational issues can arise in connection with the commencement of commercial operations 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, the Companies may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies’ ability to realize the anticipated benefits from the facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects.

 The Companies are currently simultaneously developing, constructing or commissioning several major projects, including the Atlantic Coast Pipeline Project, the Supply Header project and the Coastal Virginia Offshore Wind project. Several of the Companies’ key projects are increasingly large-scale, complex and being constructed in constrained geographic areas or in difficult terrain, for example, the Atlantic Coast Pipeline Project. The advancement of the Companies’ ventures is also affected by the interventions, litigation or other activities of stakeholder and advocacy groups, some of which oppose natural and energy infrastructure projects. For example, certain landowners and stakeholder groups oppose the Atlantic Coast Pipeline Project, which could impede construction activities or the

acquisition of and other land rights on a timely basis or on acceptable terms. Given that these projects provide the foundation for the Companies’ strategic growth plan, if the Companies are unable to obtain or maintain the required approvals, develop the necessary technical expertise, allocate and coordinate sufficient resources, adhere to budgets and timelines, effectively handle public outreach efforts, or otherwise fail to successfully execute the projects, there could be an adverse impact to the Companies’ financial position, results of operations and cash flows. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect the Companies’ ability to execute their business plan.

 Fluctuations in weather can affect demand for the Companies’ services. For example, milder than normal weather can reduce demand for electricity and gas transmission and distribution services. In addition, severe weather, including hurricanes, winter storms, earthquakes, floods and other natural disasters can stress systems, disrupt operation of the Companies’ facilities and cause service outages, production delays and property damage that require incurring additional expenses. Changes in weather conditions can result in reduced water levels or changes in water temperatures that could adversely affect operations at some of the Companies’ power stations. Furthermore, the Companies’ operations could be adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level or sea temperatures. Due to the location of Dominion Energy and Virginia Power’s electric utility service territories and a number of its other facilities in the eastern portions of the states of South Carolina, North Carolina and Virginia which are frequently in the path of hurricanes, we experience the consequences of these weather events to a greater degree than many of our industry peers.

 Operation of the Companies’ facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to

 

Certain operations are conducted through partnership arrangements, such as Atlantic Coast Pipeline and Iroquois, to which Dominion Energy and Dominion Energy Gas have significant influence but do not control the operations of such entities. Accordingly, Dominion Energy and Dominion Energy Gas may have limited ability to influence, as they do not control, certain day to day activities affecting the operations and do not have unilateral control over decisions that may have a material financial impact on the partnership participants. Dominion Energy and Dominion Energy Gas also conduct

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

 From time to time, political and public sentiment in connection with significant transactions and infrastructure projects, such as the Atlantic Coast Pipeline, the SCANA Merger and the abandonment of the NND Project, may result in a significant amount of adverse press coverage and other adverse public statements affecting the Companies. Additionally, any failure by the Companies to realize voluntary targets set with respect to the reduction of GHG emissions or other long-term goals could lead to adverse press coverage and other adverse public statements affecting the Companies. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims.

 

 

 The success of Dominion Energy’s contracted generation business depends upon favorable market conditions including the ability to sell power at prices sufficient to cover its operating costs. Dominion Energy operates in active wholesale markets that expose it to price volatility for electricity and nuclear fuel as well as the credit risk of counterparties. Dominion Energy attempts to manage its price risk by entering into long-term power purchase agreements with customers as well as hedging transactions, including short-term and long-term fixed price sales and purchase contracts.

 Upon contract expiration, customers may not elect to with Dominion Energy and Dominion Energy Gas as a result of a variety of factors, including the amount of competition in the industry, changes in the price of electricity or natural gas, their level of satisfaction with Dominion Energy and Dominion Energy Gas’ services, the extent to which Dominion Energy and Dominion Energy Gas are able to successfully execute their business plans and the effect of the regulatory framework on customer demand. The failure to replace any such customer contracts on

 Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated, cost-based recourse rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue as a result of these “negotiated rate” contracts could decrease Dominion Energy and Dominion Energy Gas’ earnings and cash flows.

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

 

The Companies cannot predict the impact that any future terrorist attacks or retaliatory military or other action may have on the energy industry in general or on the Companies’ businesses in particular. Any such future attacks or retaliatory action may adversely affect the Companies’ operations in a variety of ways, including by disrupting the power, fuel and other markets in which the Companies operate or requiring the implementation of additional, more costly security guidelines and measures. The Companies’ infrastructure facilities, including nuclear facilities and projects under construction, could be direct targets or indirect casualties of an act of terror or other physical attack. Any physical compromise of the Companies’ facilities could adversely affect the Companies’ ability to generate, purchase, transmit or distribute electricity, store, transmit or distribute natural gas, store or export LNG or otherwise operate their respective facilities in the most efficient manner or at all. In addition, the amount and scope of insurance coverage maintained against losses resulting from any such attack may not be sufficient to cover such losses or otherwise adequately compensate for any business disruptions that could result.

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

 While Dominion Energy has assumed that a certain level of transaction and integration expenses will be incurred, there are a number of factors beyond its control that could affect the total amount or the timing of its integration expenses. Potential complexities associated with integrating SCANA, including its utility businesses, while at the same time continuing to provide consistent, high quality services

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

 The Companies are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment

 

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

 The Companies rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for business plans with increasing capital expenditure needs, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or declines in market reputation either for the Companies or their industry in general, or general financial market disruptions outside of the Companies’ control could increase their cost of borrowing or restrict their ability to access one or more financial markets. Market disruptions could stem from general market disruption due to general credit market or political events, the planned phase out of LIBOR by the end of 2021 or reform or replacement of other benchmark rates, the failure of financial institutions on which the Companies rely or the bankruptcy of an unrelated company. Increased costs and restrictions on the Companies’ ability to access financial markets may be severe enough to affect their ability to execute their business plans as scheduled.

 The performance of the capital markets affects the value of the assets that are held in trusts to satisfy future obligations to decommission Dominion Energy and Virginia Power’s nuclear plants and under Dominion Energy and Dominion Energy Gas’ pension and other postretirement benefit plans. The Companies have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates.

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

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

 

Goodwill is evaluated for impairment annually or more frequently if an event or circumstance occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Other intangible assets and long-lived assets are evaluated for impairment on an annual basis or more frequently whenever events or circumstances indicate that an asset’s carrying value may not be recoverable. If Dominion Energy or Dominion Energy Gas’ goodwill, including the goodwill recorded by Dominion Energy in connection with the

 

In addition, Virginia Power’s electric distribution network includes approximately 58,400 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Where have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, Virginia Power owns 471 substations.