Item 1. Business

General

Dominion Energy

, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Dominion Energy’s strategy is to be a leading 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

stock-for-stock

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

10-K

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

600-mile

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.

Over the past decade, Dominion Energy has transitioned to a more regulated, less volatile earnings mix as evidenced by its capital investments in regulated infrastructure, including the SCANA Combination and Dominion Energy Questar Combination, and in infrastructure with output sold under long-term purchase agreements, as well as the divestiture of interests in certain merchant generating facilities and natural gas gathering and processing investments. Dominion Energy expects approximately 95% of

earnings from its primary operating segments to come from regulated and long-term contracted businesses. Dominion Energy’s nonregulated operations include merchant generation and natural gas retail energy marketing operations. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Energy Gas.

Virginia Power

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

Dominion Energy Gas,

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.

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

Employees

At December 31, 2019, Dominion Energy had approximately 19,100 full-time employees, of which approximately 5,400 are subject to collective bargaining agreements, including approximately 6,000 full-time employees at Virginia Power, of which approximately 2,500 are subject to collective bargaining agreements and approximately 1,400 full-time employees at Dominion Energy Gas, of which approximately 700 are subject to collective bargaining agreements.

Where You Can Find More Information About The Companies

The Companies file their annual, quarterly and current reports, proxy statements and other information with the SEC. Their SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov.

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

10-K,

quarterly

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reports on Form

10-Q,

current reports on Form

8-K

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

Environmental Strategy

, is not incorporated by reference in this report.

Acquisitions and Dispositions

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

Pending Acquisition of Interest in Atlantic Coast Pipeline and Pivotal LNG, Inc.

In February 2020, Dominion Energy entered into agreements with Southern to acquire its 5% membership interest in Atlantic Coast Pipeline and its 100% ownership interest in Pivotal LNG, Inc., for approximately $175 million in aggregate, plus certain purchase price adjustments. See Note 9 to the Consolidated Financial Statements for additional information.

Acquisition of SCANA

In January 2019, Dominion Energy and SCANA completed a

stock-for-stock

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.

Purchase of Dominion Energy Midstream Units

In January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy through the issuance of 22.5 million shares of Dominion Energy common stock. See Note 20 to the Consolidated Financial Statements for additional information.

Dominion Energy Gas Restructuring

In November 2019, Dominion Energy Gas finalized a restructuring whereby Dominion Energy’s wholly-owned subsidiaries, DCP and DMLPHCII, were contributed to Dominion Energy Gas. In addition, Dominion Energy Gas’ wholly-owned subsidiaries, East Ohio and DGP, were distributed to Dominion Energy. This restructuring was accounted for by Dominion Energy Gas as a reorganization of entities under common control. See Note 3 to the Consolidated Financial Statements for additional information.

Sale of Interest in Cove Point

In December 2019, Dominion Energy completed the sale of a 25% noncontrolling interest in Cove Point to Brookfield in exchange for cash consideration of $2.1 billion, subject to working capital adjustments. See Note 3 to the Consolidated Financial Statements for additional information.

Acquisition of Interest in Wrangler

In December 2019, Dominion Energy acquired a 20% noncontrolling interest in Wrangler, a partnership with Interstate Gas Supply, Inc., along with $301 million in cash as part of its initial contribution of certain retail energy marketing operations. See Note 9 to the Consolidated Financial Statements for additional information.

Sale of Certain Merchant Generation Facilities

In December 2018, Dominion Energy completed the sale of Fairless and Manchester for total consideration of $1.2 billion, subject to customary closing adjustments. See Note 10 to the Consolidated Financial Statements for additional information.

Sale of Interest in Blue Racer

In December 2018, Dominion Energy completed the sale of its 50% limited partner interest in Blue Racer for total consideration of $1.2 billion. In addition, the purchaser agreed to pay additional consideration contingent upon the achievement of certain financial performance milestones of Blue Racer from 2019 through 2021. See Note 9 to the Consolidated Financial Statements for additional information.

Acquisition of Dominion Energy Questar

In September 2016, Dominion Energy completed the Dominion Energy Questar Combination for total consideration of $4.4 billion and Dominion Energy Questar became a wholly-owned subsidiary of Dominion Energy.

Acquisition of Wholly-Owned Merchant Solar Projects

In 2019, Dominion Energy completed the acquisition of various merchant solar projects in North Carolina, South Carolina and Virginia. These projects are expected to cost a total of approximately $425 million once constructed, including the initial acquisition cost, and generate approximately 241 MW combined.

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

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

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

See Note 3 and Note 10 to the Consolidated Financial Statements for additional information.

Acquisition of Virginia Power Solar Projects

In 2019, Virginia Power entered into agreements to acquire various solar development projects in Virginia. Four of these projects closed in 2019 and the fifth closed in January 2020 with a total expected cost of approximately $765 million once constructed, including initial acquisition costs, and will generate approximately 448 MW combined.

In 2018, Virginia Power entered into agreements to acquire various solar development projects in North Carolina and Virginia. These projects closed in 2019 with a total cost of $297 million, including initial acquisition costs, and generate 175 MW combined.

In 2017, Virginia Power entered into agreements to acquire various solar development projects in North Carolina. The projects closed in 2018 and 2019 with a total cost of $282 million, including initial acquisition costs, and generate 155 MW combined.

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See Note 10 to the Consolidated Financial Statements for additional information.

Sale of Certain Retail Energy Marketing Assets

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

ten-year

term. See Note 10 to the Consolidated Financial Statements for additional information.

Assignment of Tower Rental Portfolio

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

Acquisition of Non-Wholly-Owned Merchant Solar Projects

In 2015, Dominion Energy acquired 50% of the units in Four Brothers and Three Cedars from SunEdison for $107 million. In November 2016, NRG acquired the 50% of units in Four Brothers and Three Cedars previously held by SunEdison. In August 2018, NRG’s ownership in Four Brothers and Three Cedars was transferred to GIP. The facilities began commercial operations in the third quarter of 2016, with generating capacity of 530 MW, at a cost of $1.1 billion.

Sale of Interest in Merchant Solar Projects

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

Dominion Energy Midstream Acquisition of Interest in Iroquois

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

Acquisition of DECG

In January 2015, Dominion Energy completed the acquisition of 100% of the equity interests of DECG from SCANA for $497 million in cash, as adjusted for working capital.

Assignments of Shale Development Rights

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

two-year

extension of the term of the original agreement. The conveyance of development rights resulted in the recognition of $43 million of previously deferred revenue. In April 2016, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the immediate conveyance of a 32% partial interest in the remaining approximately 70,000 acres. This conveyance resulted in the recognition of the remaining $35 million of previously deferred revenue. In August 2017, Dominion Energy Gas and 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.

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

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

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

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

Operating Segments

In December 2019, Dominion Energy strategically realigned its segments which resulted in the formation of five primary operating segments: Dominion Energy Virginia, Gas Transmission & Storage, Gas Distribution, Dominion Energy South Carolina and Contracted Generation. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service companies and other functions (including unallocated debt). In addition, Corporate and Other includes specific items attributable to Dominion Energy’s other operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.

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

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

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

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

Primary Operating Segment		Description of Operations		Dominion Energy				Virginia Power				Dominion Energy Gas
Dominion Energy Virginia		Regulated electric distribution			X				X
		Regulated electric transmission			X				X
		Regulated electric generation fleet (1)			X				X
Gas Transmission & Storage		Regulated gas transmission and storage (2)			X								X
		LNG terminalling and storage			X								X
		Nonregulated retail energy marketing			X
Gas Distribution		Regulated gas distribution and storage (3)			X
Dominion Energy South Carolina		Regulated electric distribution			X
		Regulated electric transmission			X
		Regulated electric generation fleet			X
		Regulated gas distribution and storage			X
Contracted Generation		Merchant electric generation fleet			X

(1)	Includes Virginia Power’s nonjurisdictional generation operations.

(2)	Includes gathering and processing activities.

(3)	Includes Wexpro’s natural gas development and production operations.

Dominion Energy Virginia

The Dominion Energy Virginia Operating Segment is substantially composed of Virginia Power’s regulated electric transmission, distribution (including customer service) and generation (regulated electric utility and its related energy supply) operations, which serve approximately 2.6 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.

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

20-year

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

ten-year

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

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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

man-made

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

cost-of-service

rate model, and are generally designed to allow an opportunity to recover the cost of providing utility service and earn a reasonable return on investments used to provide that service. 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.

Earnings may reflect variations in the timing or nature of expenses as compared to those contemplated in current rates, such as labor and benefit costs, capacity expenses, the timing, duration and costs of scheduled and unscheduled outages as well as the customer’s ability to choose a generation service provider. The cost of fuel and purchased power is generally collected through fuel cost-recovery mechanisms established by regulators and does not materially impact net income. The cost of new generation facilities is generally recovered through rate adjustment clauses in Virginia. Variability in earnings from rate adjustment clauses reflects changes in the authorized ROE and the carrying amount of these facilities, which are largely driven by the timing and amount of capital investments, as well as depreciation. See Note 13 to the Consolidated Financial Statements for additional information.

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

Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into PJM wholesale electricity markets. Consistent with the increased authority given to NERC by EPACT, Virginia Power’s electric transmission operations are committed to meeting NERC standards, modernizing its infrastructure and maintaining superior system reliability.

Competition

There is no competition for electric distribution service within Virginia Power’s service territory in Virginia and North Carolina

and no such competition is currently permitted. Historically, since its electric transmission facilities are integrated into PJM and electric transmission services are administered by PJM, there was no competition in relation to transmission service provided to customers within the PJM region. However, competition from

non-incumbent

PJM transmission owners for development, construction and ownership of certain transmission facilities in Virginia Power’s service territory is 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

Electric

under

State Regulations

in

Regulation

for more information. Currently, North Carolina does not offer retail choice to electric customers.

Virginia Power’s

non-jurisdictional

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.

Regulation

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

State Regulations

and

Federal Regulations

in

Regulation, Future Issues and Other Matters

in Item 7 MD&A and Notes 13 and 23 to the Consolidated Financial Statements for additional information.

Properties

For a description of existing facilities see Item 2. Properties.

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

	•	Mt. Storm-to-Valley ($290 million);

	•	Gainesville-to-Haymarket ($170 million);

	•	Idylwood -to-Tysons ($125 million);

	•	Glebe substation and North Potomac Yard terminal station underground ($125 million);

	•	Remington/Gordonsville/Pratts Area Improvement (including Remington-to-Gordonsville, and new Gordonsville substation transformer) ($115 million);

	•	Idylwood substation ($105 million);

	•	Harmony Village-to-White Stone ($105 million);

	•	Elmont-to-Ladysmith ($90 million);

	•	Lanexa-to-Northern Neck ($90 million);

	•	Loudoun-to-Ox ($70 million);

	•	Mt. Storm substation ($70 million);

	•	Bristers-to-Chancellor ($65 million); and

	•	Dooms-to-Valley ($65 million).

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Virginia Power is investing in transmission substation physical security and expects to invest an additional $125 million to $175 million through 2024 to strengthen its electrical system to better protect critical equipment, enhance its spare equipment process and create multiple levels of security.

Virginia legislation provides for the recovery of costs, subject to approval by the Virginia Commission, for Virginia Power to move approximately 4,000 miles of electric distribution lines underground. The program is designed to reduce restoration outage time by moving Virginia Power’s most outage-prone overhead distribution lines underground, has an annual investment cap of approximately $175 million and is expected to be completed by 2028. The Virginia Commission has approved four phases of the program encompassing approximately 1,350 miles of converted lines and $545 million in capital spending (with $523 million recoverable through Rider U).

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

•	Virginia Power plans to acquire or construct certain solar facilities in Virginia and North Carolina. See Notes 10 and 13 to the Consolidated Financial Statements for more information.

•	Virginia Power continues to consider the construction of a third nuclear unit at a site located at North Anna. See Future Issues and Other Matters in Item 7 for more information on this project.

•	Virginia Power is considering the construction of an approximately $2 billion hydroelectric pumped storage facility in Southwest Virginia.

•	Virginia Power has announced an approximately $400 million project to replace approximately 1,500 diesel buses with electric buses at school districts in Virginia by 2025.

•

In November 2018, Virginia Power received approval from the Virginia Commission for its petition seeking a prudency determination as provided in the GTSA with respect to the proposed Coastal Virginia Offshore Wind Pilot project, consisting of two 6 MW wind turbine generators located approximately 27 miles off the coast of Virginia Beach, Virginia in federal waters, and for a CPCN, for the generation tie line connecting the generators to shore. This project is expected to cost approximately $300 million and to be placed into service by the end of 2020.

•	In September 2019, Virginia Power filed an application with PJM for the Coastal Virginia Offshore Wind Commercial project to interconnect 2,640 MW of wind energy between 2024 and 2026 off the coast of Virginia as an expansion of the Coastal Virginia Offshore Wind Pilot project, expected to increase the total cost of the project by up to approximately $8 billion.

•	Virginia Power is considering the construction of simple cycle combustion turbines in Virginia. These projects are expected to be placed in service beginning 2023.

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

Sources of Energy Supply

Virginia Power uses a variety of fuels to power its electric generation fleet and purchases power for utility system load requirements and to satisfy physical forward sale requirements. Some of these agreements have fixed commitments and are included as

contractual obligations in

Future Cash

Payments for Contractual Obligations and Planned Capital Expenditures

in Item 7. MD&A.

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

Source		2019				2018				2017
Natural gas			41	%			33	%			32	%
Nuclear (1)			29				29				32
Purchased power, net			17				19				14
Coal (2)			8				13				17
Renewable/hydro (3)			5				5				5
Oil			—				1				—
Total			100	%			100	%			100	%

(1)	Excludes ODEC’s 11.6% ownership interest in North Anna.

(2)	Excludes ODEC’s 50.0% ownership interest in the Clover power station.

(3)	Includes solar and biomass.

Nuclear Fuel

—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.

Fossil Fuel

—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

Mid-Continent

and Gulf Coast regions, purchases from local producers in the Appalachian area and Marcellus and Utica regions, purchases from gas marketers and withdrawals from underground storage fields owned by Dominion Energy or third parties. 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 coal supply is obtained through long-term contracts and short-term spot agreements from domestic suppliers.

Biomass—

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

Purchased Power

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

Seasonality

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

Nuclear Decommissioning

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

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

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

The estimated cost to decommission Virginia Power’s four nuclear units is reflected in the table below and is primarily based upon site-specific studies completed in 2019. These cost studies are generally completed every four to five years. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire.

Under the current operating licenses, Virginia Power is scheduled to decommission the Surry and North Anna units during the period 2032 to 2078. NRC regulations allow licensees to apply for extension of an operating license in up to

20-year

increments. 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 estimated decommissioning costs, funds in trust and current license expiration dates for Surry and North Anna are shown in the following table:

		NRC license expiration year				Most recent cost estimate (2019 dollars) (1)				Funds in trusts at December 31, 2019				2019 contributions to trusts
(dollars in millions)
Surry
Unit 1			2032				$ 803				$ 815				$ —
Unit 2			2033				794				803				—
North Anna
Unit 1 (2)			2038				720				651				—
Unit 2 (2)			2040				724				612				—
Total							$3,041				$2,881				$—

(1)	The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on Virginia Power’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Virginia Power’s nuclear decommissioning AROs and includes the expectation that 20-year license extensions are approved for all units.

(2)	North Anna is jointly owned by Virginia Power (88.4%) and ODEC (11.6%). However, Virginia Power is responsible for 89.26% of the decommissioning obligation. Amounts reflect 89.26% of the decommissioning cost for both of North Anna’s units.

Also see Notes 9, 14 and 23 to the Consolidated Financial Statements for further information about nuclear decommissioning trust investments, AROs and nuclear decommissioning, respectively.

Gas Transmission & Storage

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

Investments

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

Investments

below for additional information regarding the Atlantic Coast Pipeline, Align RNG and Wrangler investments.

Gas Transmission & Storage’s growth capital plan includes spending approximately $4 billion from 2019 through 2023 to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability. Demand for natural gas is expected to continue to grow as initiatives to transition to gas from more carbon-intensive fuels are implemented. This plan includes Dominion Energy’s portion of spending for the Atlantic Coast Pipeline Project.

Earnings for the

Gas Transmission & Storage Operating Segment of Dominion Energy and Dominion Energy Gas

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

year-to-year

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

fee-based

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)

14

under normal operating conditions and after accounting for maintenance downtime. Variability in earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, which are dependent on weather, changes in commodity prices and the economy.

Dominion Energy’s retail energy marketing operations compete in nonregulated energy markets. Dominion Energy has a large concentration of natural gas customers in markets where utilities have a long-standing commitment to customer choice.

Competition

Gas Transmission & Storage Operating Segment—Dominion Energy and Dominion Energy Gas

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

Dominion Energy Gas’ pipeline systems generate a substantial portion of their revenue from long-term firm contracts for transportation services and are therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, Dominion Energy Gas’ pipeline system will face competitive pressures from similar facilities that serve the eastern and Rocky Mountain regions in terms of location, rates, terms of service, and flexibility and reliability of service.

Cove Point’s gas transportation, LNG import and storage operations, as well as the Liquefaction Facility’s capacity, are contracted primarily under long-term fixed reservation fee agreements. However, in the future Cove Point may compete with other independent terminal operators as well as major oil and gas companies on the basis of terminal location, services provided and price. Competition from terminal operators primarily comes from refiners and distribution companies with marketing and trading arms. In addition, the Liquefaction Facility may face competition on a global scale as international customers explore other options to meet their energy needs.

Gas Transmission & Storage Operating Segment—Dominion Energy

Dominion Energy’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy markets for natural gas, and provides service to approximately 380,000 customer accounts in five states. The heaviest concentration of customers in these markets is located in states where utilities have the advantage of long-standing commitment to customer choice, primarily Ohio and Pennsylvania.

Regulation

Gas Transmission & Storage Operating Segment—Dominion Energy and Dominion Energy Gas

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

See

Federal Regulations

in

Regulation

for more information.

Properties

For a description of existing facilities see Item 2.

Properties

.

The

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

Gas Transmission & Storage Operating Segment—Dominion Energy and Dominion Energy Gas

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

gas-fired

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-service

in early 2022.

Gas Transmission & Storage Operating Segment—Dominion Energy

In November 2019, Dominion Energy entered into an arrangement with Vanguard Renewables to convert methane from U.S. dairy farms into clean, renewable natural gas that can heat homes, power businesses and fuel vehicles. Under this arrangement, Dominion Energy will own the projects and market the renewable natural gas, and Vanguard Renewables will design, develop and operate the projects. Dominion Energy plans to invest $200 million into this project through 2024.

Investments

Gas Transmission & Storage Operating Segment—Dominion Energy and Dominion Energy Gas

Iroquois—

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

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

15

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. In January 2020, Iroquois filed an application with FERC to expand certain existing compression stations in New York and Connecticut. The project is expected to cost approximately $275 million and be placed in service by the end of 2023. See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Iroquois.

Gas Transmission & Storage Operating Segment—Dominion Energy

Atlantic Coast Pipeline

—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

600-mile

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

in-service

date and Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Atlantic Coast Pipeline.

Align RNG

—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.

Wrangler

—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.

Sources of Energy Supply

Dominion Energy and Dominion Energy Gas’ large underground natural gas storage network and the location of their pipeline systems are a significant link between the country’s major interstate gas pipelines and large markets in the eastern and Rocky Mountain regions of the U.S. Dominion Energy and Dominion Energy Gas’ pipelines are part of an interconnected gas transmission system, which provides access to supplies nationwide for local distribution companies, marketers, power generators and industrial and commercial customers.

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

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

Seasonality

Due to the nature of Dominion Energy and Dominion Energy Gas’ gas transmission and storage operations, seasonal fluctuations do not have a material impact on earnings.

The earnings of Dominion Energy’s retail energy marketing operations, however vary seasonally as a result of the impact of changes in temperature. Generally, the demand for gas peaks during the winter months to meet heating needs.

Gas Distribution

The Gas Distribution Operating Segment of Dominion Energy

includes 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.

Gas Distribution’s growth capital plan includes spending approximately $4 billion from 2019 through 2023 to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability. Planned capital spending is driven by infrastructure needs from a growing customer base in states with expanding economies, replacing aging assets for reliability and safety and meeting demands for natural gas to support the transition from more carbon intensive fuels.

Earnings for the Gas Distribution Operating Segment of Dominion Energy

primarily 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.

Competition

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

State Regulations

in

Regulation

for additional information.

In Ohio, there has been no legislation enacted to require supplier choice for natural gas distribution consumers. However, East Ohio has offered an Energy Choice program to residential and commercial customers since October 2000. East Ohio has since taken various steps approved by the Ohio Commission toward exiting the merchant function, including restructuring its

16

commodity service and placing Energy Choice-eligible customers in a direct retail relationship with participating suppliers. Further, in April 2013, East Ohio fully exited the merchant function for its nonresidential customers, which are now required to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2019, approximately 1.1 million of East Ohio’s 1.2 million Ohio customers were participating in the Energy Choice program.

Competition in PSNC’s natural gas distribution operations is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and the ability to retain large commercial and industrial customers.

In all of Dominion Energy’s gas service territories, electric utilities offer electricity as a rival energy source and compete for the space heating, water heating and cooking markets. The principal means to compete against alternative fuels is lower prices, and natural gas historically has maintained its price advantage in the residential and commercial markets. Competition for heating as well as general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes the decision as to which types of equipment to install, as a result customers tend to use their chosen energy source for the life of the equipment.

Regulation

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

State Regulations

in

Regulation

for more information.

Properties

For a description of existing facilities see Item 2.

Properties

.

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

East Ohio

—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.

Questar Gas

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

In its 2014 Utah general rate case, Questar Gas received approval to include intermediate high pressure infrastructure in the replacement program and increase the annual spending limit to approximately $65 million, adjusted annually using a gross domestic product inflation factor. At that time, 420 miles of high pressure pipe and 70 miles of intermediate high pressure pipe were identified to be replaced in the program over a

17-year

period. Questar Gas has spent 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

pre-approval

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

pre-approval

to construct the LNG storage facility.

In 2018, legislation became effective in Utah which is designed to spur economic growth in rural communities without natural gas service. The legislation allows Questar Gas to spend up to $50 million over three years, and up to $125 million over five years, for expansion of distribution facilities to bring natural gas to residential and commercial customers in rural parts of Utah, subject to Utah Commission approval. See Note 13 to Consolidated Financial Statements for more information.

PSNC

—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.

In 2018, PSNC began constructing a high-pressure distribution pipeline that will span 35 miles and will provide enhanced safety to the corresponding service area. The project is expected to cost approximately $80 million, excluding financing costs, and is anticipated to be placed into service by mid-2020. This project is expected to be recovered through the pipeline integrity tracker mechanism described above.

During 2019, PSNC began the construction of approximately 38 miles of transmission pipeline between Franklinton, North Carolina and Clayton, North Carolina, which will provide the capacity necessary to support the growing natural gas demand in PSNC’s service territory. The project is expected to cost approximately $165 million, excluding financing costs, and is anticipated to be placed into service in 2021.

Sources of Energy Supply

Dominion Energy’s natural gas supply is obtained from various sources including purchases from major and independent producers in the

Mid-Continent

and Gulf Coast regions, local producers in the Appalachian area, gas marketers and, for Questar Gas specifically, from Wexpro and other producers in the Rocky Mountain region. Wexpro’s gas development and production operations serve 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.

17

Seasonality

Gas Distribution’s business earnings vary seasonally, as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Historically, the majority of these earnings have been generated during the heating season, which is generally from November to March; however, implementation of rate mechanisms for transportation services for East Ohio, and gas sales for Questar Gas and PSNC have reduced the earnings impact of weather-related fluctuations.

Dominion Energy South Carolina

The Dominion Energy South Carolina Operating Segment is comprised of DESC’s generation, transmission and distribution of electricity to approximately 740,000 customers in the central, southern and southwestern portions of South Carolina and the distribution of natural gas to approximately 390,000 residential, commercial and industrial customers in South Carolina.

DESC’s growth capital plan includes spending approximately $2 billion from 2019 through 2023 to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability.

Revenue provided by DESC’s electric distribution operations is based primarily on rates established by the South Carolina Commission. 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.

DESC’s electric transmission operations serve its electric distribution operations as well as certain wholesale customers. Revenue provided by such electric transmission operations is based on a FERC-approved formula rate mechanism under DESC’s open access transmission tariff or based on retail rates established by the South Carolina Commission.

Revenue provided by DESC’s electric generation operations is primarily derived from the sale of electricity generated by its utility generation assets and is based on rates established by the South Carolina Commission. Variability in earnings may arise when revenues are impacted by factors not reflected in current rates, such as the impact of weather, customer demand or the timing and nature of expenses or outages.

Revenue provided by DESC’s natural gas distribution operations primarily results from rates established by the South Carolina Commission. Variability in earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, the availability and prices of alternative fuels and the economy.

DESC is a member of the Virginia-Carolinas Reliability Group, one of several geographic divisions within the SERC. The SERC is one of seven regional entities with delegated authority from NERC for the purpose of proposing and enforcing reliability standards approved by NERC.

Competition

There is no competition for electric distribution or generation service within DESC’s retail electric service territory in South Carolina and no such competition is currently permitted. However, competition from third-party owners for development, construction and ownership of certain transmission facilities in DESC’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 DESC’s service area in the future.

Competition in DESC’s natural gas distribution operations is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and the ability to retain large commercial and industrial customers.

Regulation

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

State Regulations

and

Federal Regulations

in

Regulation

for more information.

Properties

For a description of existing facilities see Item 2. Properties.

DESC has the following significant projects under construction or development to better serve customers or expand its service offerings within its service territory:

In 2019, DESC began an initiative to upgrade its electric and gas systems to an AMI whereby over a million smart meters will be installed throughout its service area. This project is estimated to cost approximately $140 million and will be completed by 2023.

Sources of Energy Supply

DESC uses a variety of fuels to power its electric generation fleet and purchases power for utility system load requirements. Presented below is a summary of DESC’s actual system output by energy source:

Source		2019				2018 (1)
Natural gas			46	%			37	%
Coal			27				35
Nuclear (2)			23				20
Renewable/hydro (3)			4				8
Total			100	%			100	%

(1)	Dominion Energy did not acquire DESC until January 2019. These amounts represent data obtained as part of the due diligence performed by Dominion Energy prior to the SCANA Combination.

(2)	Excludes Santee Cooper’s 33.3% undivided ownership interest in Summer.

(3)	Includes solar.

Natural gas

—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

18

South Carolina through firm transportation agreements with various counterparties, which expire between 2021 and 2084.

Coal

—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.

Nuclear

—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.

In addition, DESC has contracts covering its nuclear fuel needs for uranium, conversion services and enrichment services. These contracts have varying expiration dates through 2024. DESC believes that it will be able to renew these contracts as they expire or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services and that sufficient capacity for nuclear fuel supplies and processing exists to allow for normal operations of its nuclear generating unit. 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 fuel and inventory levels.

Seasonality

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

DESC’s gas distribution and storage business earnings vary seasonally as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. The majority of these earnings are generated during the heating season, which is generally from November to March; however, South Carolina has certain rate mechanisms designed to reduce the impact of weather-related fluctuations.

Nuclear Decommissioning

DESC has a

two-thirds

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

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

DESC believes that the decommissioning funds and their expected earnings will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to this trust. DESC will continue to monitor this trust to ensure that it meets the NRC minimum financial assurance requirements, which may include, if needed, the use of Dominion Energy guarantees, surety bonding or other financial instruments recognized by the NRC.

The estimated cost to DESC to decommission its 66.7% ownership in Summer is $646 million (stated in 2019 dollars), which is primarily based upon site-specific studies completed in 2016. These cost studies are generally completed every four to five years. Santee Cooper is responsible for the remaining decommissioning costs, proportionate with its 33.3% ownership in Summer. The cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating license expires. The cost estimate reflects reductions for the expected future recovery of certain spent nuclear fuel costs based on DESC’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in DESC’s nuclear decommissioning ARO. At December 31, 2019, DESC had $214 million in a trust for its proportionate share of these decommissioning activities.

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

20-year

increments. DESC is considering an operating license renewal for Summer.

Contracted Generation

The Contracted Generation Operating Segment includes the operations of Millstone, and associated energy marketing and price risk activities, and Dominion Energy’s long-term contracted renewable electric generation fleet as well as a 50% noncontrolling partnership interest in Fowler Ridge.

Contracted Generation’s growth capital plan includes spending less than $1 billion from 2019 through 2023 to expand its renewable generation fleet.

The Contracted

Generation 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.

19

Dominion Energy’s merchant generation fleet includes numerous renewable generation facilities, including solar generation and wind facilities in operation or development in nine states, including Virginia. The output of these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. Variability in earnings provided by these assets relates to changes in irradiance levels and wind speeds due to changes in weather. See Notes 3 and 10 to the Consolidated Financial Statements for additional information regarding certain solar projects.

Competition

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

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

Regulation

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

Regulation, Future Issues and Other Matters

in Item 7, MD&A and Notes 13 and 23 to the Consolidated Financial Statements for more information.

Properties

For a listing of facilities, see Item 2. Properties.

Dominion Energy plans to acquire or construct certain solar facilities in the

Mid-Atlantic.

See Note 10 to the Consolidated Financial Statements for more information.

Investments

See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Fowler Ridge.

Sources of Energy Supply

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

ISO-NE

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

Future Cash

Payments for Contractual Obligations and Planned Capital Expenditures

in Item 7. MD&A.

Nuclear Fuel

—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.

Seasonality

Sales of electricity for Contracted Generation typically vary seasonally as a result of the weather.

Nuclear Decommissioning

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

60-year

window.

As part of Dominion Energy’s acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Any funds remaining in Kewaunee’s trust after decommissioning is completed are required to be refunded to Wisconsin ratepayers. Dominion Energy believes that the amounts currently available in the decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Dominion Energy will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. The most recent site-specific studies completed for Millstone and for Kewaunee were performed in 2019 and 2018, respectively.

20

The estimated decommissioning costs, funds in trust and current license expiration dates for Millstone and Kewaunee are shown in the following table:

		NRC license expiration year				Most recent cost estimate (2019 dollars) (1)				Funds in trusts at December 31, 2019				2019 contributions to trusts
(dollars in millions)
Millstone
Unit 1 (2)			N/A			$	450				$ 622				$ —
Unit 2			2035				653				828				—
Unit 3 (3)			2045				741				813				—
Kewaunee
Unit 1 (4)			N/A				573				834				—
Total						$	2,417				$3,097				$ —

(1)	The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on Dominion Energy’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Dominion Energy’s nuclear decommissioning AROs.

(2)	Unit 1 permanently ceased operations in 1998, before Dominion Energy’s acquisition of Millstone.

(3)	Millstone Unit 3 is jointly owned by Dominion Energy Nuclear Connecticut, Inc., with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain. Decommissioning cost is shown at Dominion Energy’s ownership percentage. At December 31, 2019, the minority owners held $49 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.

(4)	Permanently ceased operations in 2013.

Also see Notes 14 and 23 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively, and Note 9 to the Consolidated Financial Statements for information about nuclear decommissioning trust investments.

Corporate and Other

Corporate and Other Segment-Virginia Power and Dominion Energy Gas

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

Corporate and Other Segment-Dominion Energy

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

Regulation

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

State Regulations

Electric

Virginia Power and DESC’s electric utility retail services are subject to regulation by the Virginia and North Carolina Commissions and the South Carolina Commission, respectively.

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

Electric Regulation in Virginia

The Regulation Act provides for a

cost-of-service

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

12-month

test periods beginning January 1, 2017 and ending December 31, 2020.

In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized ROE that might have been refunded to customers and served as the basis for a reduction in future rates, may be reduced by Virginia Commission-approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include as a customer credit reinvestment offset. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that Virginia Power may seek to recover the costs of such projects through a rate adjustment clause if not the subject of a customer credit reinvestment offset. Any costs that are the subject of a customer credit reinvestment offset may not be recovered in base rates for the service life of the projects and may not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized ROE, base rates are subject to reduction prospectively and customer refunds would be due unless the total customer credit reinvestment offset elected by the utility equals or exceeds the amount of earnings in excess of the 70 basis points. In the 2021 review, any such rate reduction is limited to $50 million.

21

See

Future Issues and Other Matters

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

Electric Regulation in North Carolina

Virginia Power’s retail electric base rates in North Carolina are regulated on a

cost-of-service/rate-of

-return

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

Virginia Power’s transmission service rates in North Carolina are regulated by the North Carolina Commission as part of Virginia Power’s bundled retail service to North Carolina customers. See Note 13 to the Consolidated Financial Statements for additional information.

Electric Regulation in South Carolina

DESC’s retail electric base rates in South Carolina are regulated on a

cost-of-service/rate-of

-return

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.

DESC offers to its retail electric customers several DSM programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. DESC submits annual filings to the South Carolina Commission related to these programs. As actual DSM program costs are incurred, they are deferred as regulatory assets and recovered through a rider approved by the South Carolina Commission. The rider also provides for recovery of any net lost revenues and for a shared savings incentive.

In connection with the SCANA Combination, DESC agreed not to file a general rate case with the South Carolina Commission with a requested rate effective date earlier than January 2021. Rate adjustments are permitted prior to 2021 for fuel and environmental costs, DSM costs and other rates routinely adjusted on an annual or biennial basis.

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

Gas

Questar Gas and Wexpro’s natural gas development, production, transportation, and distribution services, including the rates it may charge its customers, are regulated by the state commissions of Utah, Wyoming and Idaho. East Ohio’s natural gas distribution services, including the rates it may charge its customers, are regulated by the Ohio Commission. Hope’s natural gas distribution services are regulated by the West Virginia Commission. DESC and PSNC’s natural gas distribution services are regulated by the South Carolina Commission and North Carolina Commission, respectively.

Gas Regulation in Utah, Wyoming and Idaho

Questar Gas is subject to regulation of rates and other aspects of its business by the Utah, Wyoming and Idaho Commissions. The Idaho Commission has contracted with the Utah Commission for rate oversight of Questar Gas’ operations in a small area of southeastern Idaho. When necessary, Questar Gas seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the

cost-of-service

by rate class. Base rates for Questar Gas are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. 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.

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

The Utah and Wyoming Commissions have also approved several stand-alone cost recovery mechanisms to recover specified costs and a return for infrastructure projects between general base rate cases.

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

Gas Regulation in Ohio

East Ohio is subject to regulation of rates and other aspects of its business by the Ohio Commission. When necessary, East Ohio seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the

cost-of-service

by rate class. A straight-fixed-variable rate design, in which the majority of operating costs are recovered through a monthly charge rather than a volumetric charge, is utilized to establish rates for a majority of East Ohio’s customers pursuant to a 2008 rate case settlement.

In addition to general base rate increases, East Ohio makes routine filings with the Ohio Commission to reflect changes in the costs of gas purchased for operational balancing on its system. These purchased gas costs are subject to rate recovery through a

22

mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The rider filings cover unrecovered gas costs plus prospective annual demand costs. Increases or decreases in gas cost rider rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

The Ohio Commission has also approved several stand-alone cost recovery mechanisms to recover specified costs and a return for infrastructure projects between general base rate cases. See Note 13 to the Consolidated Financial Statements for additional information.

Gas Regulation in West Virginia

Hope is subject to regulation of rates and other aspects of its business by the West Virginia Commission. When necessary, Hope seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the

cost-of-service

by rate class. Base rates for Hope are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges.

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

The West Virginia Commission has also approved a stand-alone cost recovery mechanism to recover specified costs and a return for infrastructure projects between general base rate cases. See Note 13 to the Consolidated Financial Statements for additional information.

Gas Regulation in North Carolina

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

cost-of-service

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.

In addition to general rate increases, PSNC makes routine separate filings with the North Carolina Commission to reflect changes in the costs of purchased gas. PSNC’s purchased gas adjustment allows it to recover from customers all prudently incurred gas costs, including transportation costs, and certain related uncollectible expenses. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas recovery filings are made periodically to reflect prospective costs and recovery. Approved increases or decreases in

gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

The North Carolina Commission has also approved a stand-alone cost recovery mechanism to recover specified costs and a return for infrastructure projects between general base rate cases.

In connection with the SCANA Combination, PSNC agreed not to file a general rate case with the North Carolina Commission with a requested rate effective date earlier than November 2021 other than for rate adjustments as described above.

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

Gas Regulation in South Carolina

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

cost-of-service

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.

In addition, DESC’s natural gas tariffs include a purchased gas adjustment that provides for the recovery of prudently incurred gas costs, including transportation costs. DESC is authorized to adjust its purchased gas rates monthly and makes routine filings with the South Carolina Commission to provide notification of changes in these rates. Costs that are under or over recovered are deferred as regulatory assets or liabilities, respectively, and considered in subsequent purchased gas adjustments. The purchased gas adjustment filings generally cover a prospective twelve-month period. Increases or decreases in purchased gas costs can result in corresponding changes in purchased gas adjustment rates and the revenue generated by those rates. The South Carolina Commission reviews DESC’s gas purchasing policies and practices, including its administration of the purchased gas adjustment, annually.

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

Status of Competitive Retail Gas Services

Ohio has considered legislation regarding a competitive deregulation of natural gas sales at the retail level.

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

month-end

settlement and passing that gas cost to customers under the Standard Service

23

Offer program. Starting in April 2009, East Ohio buys natural gas under the Standard Service Offer program for customers not eligible to participate in the Energy Choice program and certain transitional customers only and places Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which is designated on the customers’ bills.

In January 2013, the Ohio Commission granted East Ohio’s motion to fully exit the merchant function for its nonresidential customers, beginning in April 2013, which requires those customers to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2019, approximately 1.1 million of East Ohio’s 1.2 million customers were participating in the Energy Choice program. Subject to the Ohio Commission’s approval, East Ohio may eventually exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. East Ohio continues to be the provider of last resort in the event of default by a supplier. Large industrial customers in Ohio also source their own natural gas supplies.

Federal Regulations

Federal Energy Regulatory Commission

Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and sells electricity to wholesale purchasers in Virginia and North Carolina. Dominion Energy’s merchant generators sell electricity in the PJM, CAISO and

ISO-NE

wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California, South Carolina and Utah, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. 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.

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

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

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

non-monetary

penalties, depending upon the nature and severity of the violation.

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

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

In October 2011, FERC issued an order approving the settlement of DESC’s formula rate that updates transmission rates on an annual basis, including its ROE. The formula rate is designed to recover the expected revenue requirement for the calendar year and is updated annually based on actual costs. This FERC accepted formula rate enables DESC to earn a return on its investment in electric transmission infrastructure.

Gas

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

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

24

Dominion Energy and Dominion Energy Gas operate in compliance with FERC standards of conduct, which prohibit the sharing of certain

non-public

transmission information or customer specific data by its interstate gas transmission and storage companies with

non-transmission

function employees. Pursuant to these standards of conduct, Dominion Energy and Dominion Energy Gas also make certain informational postings available on Dominion Energy’s website.

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

Safety Regulations

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

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

Environmental Regulations

Each of the Companies’ operating segments 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

Environmental Matters

in

Future Issues and Other Matters

in Item 7. MD&A. Additional information can also be found in Item 3. Legal Proceedings and Note 23 to the Consolidated Financial Statements.

Global Climate Change

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

Environmental Strategy

below

, Environmental Matters

in

Future Issues and Other Matters

in Item 7. MD&A and Note 23 to the Consolidated Financial Statements for information on climate change legislation and regulation.

Air

The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. Regulated emissions include, but are not limited to, carbon, methane, VOC, NO

X

, other GHGs, mercury, other toxic metals, hydrogen chloride, SO

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

Water

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

non-tidal

wetlands. In these instances, Dominion Energy must obtain authorization from the appropriate federal, state and local agencies prior to impacting wetlands. The authorizing agency may impose significant direct or indirect mitigation costs to compensate for such impacts to wetlands.

Waste and Chemical Management

Dominion Energy is subject to various federal and state laws and implementing regulations governing the management, storage, treatment, reuse and disposal of waste materials and hazardous substances, including the Resource Conservation and Recovery Act of 1976, CERCLA, the Emergency Planning and Community

Right-to-Know

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

25

facilities. Produced water is either hauled for disposal, evaporated or injected into company and third-party owned underground injection wells. Wells drilled in

tight-gas-sand

and shale reservoirs require hydraulic-fracture stimulation to achieve economic production rates and recoverable reserves. The majority of Wexpro’s current and future production and reserve potential is derived from reservoirs that require hydraulic-fracture stimulation to be commercially viable. Currently, all well construction activities, including hydraulic-fracture stimulation and management and disposal of hydraulic fracturing fluids, are regulated by federal and state agencies that review and approve all aspects of

gas-

and

oil-well

design and operation.

Protected Species

The ESA and analogous state laws prohibit activities that can result in harm to specific species of plants and animals, as well as impacts to the habitat on which those species depend. In addition to ESA programs, the Migratory Bird Treaty Act of 1918 and Bald and Golden Eagle Protection Act establish broader prohibitions on harm to protected birds. Many of the Companies’ facilities are subject to requirements of the ESA, Migratory Bird Treaty Act of 1918 and Bald and Golden Eagle Protection Act. The ESA and Bald and Golden Eagle Protection Act require potentially lengthy coordination with the state and federal agencies to ensure potentially affected species are protected. Ultimately, the suite of species protections may restrict company activities to certain times of year, project modifications may be necessary to avoid harm, or a permit may be needed for unavoidable taking of the species. The authorizing agency may impose mitigation requirements and costs to compensate for harm of a protected species or habitat loss. These requirements and time of year restrictions can result in adverse impacts on project plans and schedules such that the Companies’ businesses may be materially affected.

Other Regulations

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

Nuclear Regulatory Commission

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

From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining Dominion Energy and Virginia Power’s nuclear generating units. See Note 23 to the Consolidated Financial Statements for further information.

The NRC also requires Dominion Energy and Virginia Power to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and Dominion Energy and Virginia Power are required by the NRC to be financially prepared. For information on decommissioning trusts, see

Dominion Energy Virginia-Nuclear Decommissioning

,

Dominion Energy South Carolina-Nuclear Decommissioning,

and

Contracted Generation-Nuclear Decommissioning

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.

Environmental Strategy

The Companies’ environmental strategy is a component of the overall long-term strategic planning overseen by the CEO and Board of Directors, including oversight by the sustainability and corporate responsibility board committee which was formed in 2018. The Companies are committed to ongoing industry leadership, delivering safe, reliable, clean and affordable energy while fully complying with all applicable environmental laws and regulations. Additionally, the Companies seek to build partnerships and engage with local communities, stakeholders and customers on environmental issues important to them, including environmental justice considerations such as fair treatment, inclusive involvement and effective communication. The Companies believe in being transparent about their environmental commitments, policies, including the Environmental Justice Policy adopted in 2018, and initiatives which have been disclosed in a Sustainability & Corporate Responsibility Report, Climate Report and other reports included on Dominion Energy’s dedicated Environmental, Social and Governance website. The Companies are dedicated to meeting their customers’ growing energy needs with innovative, sustainable solutions. The Companies are pursuing initiatives intended to reduce the GHG footprint of their customers and energy end-users, including a school bus electrification program in Virginia and two renewable natural gas partnerships in the agricultural sector. It is the Companies’ belief that sustainable solutions should strive to balance the interdependent goals of environmental stewardship and economic effects. The integrated strategy to meet these objectives consists of three major elements:

•	Reduction of GHG emissions;

•	Energy infrastructure modernization, including natural gas and electric operations; and

•	Conservation and energy efficiency.

Reduction of GHG Emissions

The Companies’ integrated strategy has resulted in a reduction in GHG emissions and emission intensity. Dominion Energy has committed to cut methane emissions by 65% by 2030 and by 80% by 2040, in each case relative to 2010 emissions. Dominion Energy has further committed to achieve net zero carbon and methane emissions from its electric generation and natural gas infrastructure operations by 2050.

Over the past two decades, the Companies have made changes to the generation mix and to natural gas operations which have significantly improved environmental performance. For example,

26

Dominion Energy has reduced both its carbon emissions and its carbon intensity while generating electricity with an increasingly clean portfolio. From 2000 through 2018, Dominion Energy’s carbon intensity decreased by 53%. This strategy has also resulted in measurable reductions of other air pollutants such as NO

X

, SO

and mercury and reduced the amount of coal ash generated and the amount of water withdrawn. The principal components of the strategy include initiatives that address electric energy production and delivery, natural gas storage, transmission and delivery and energy management.

See

Operating Segments

for more information on certain of the projects described above.

Cleaner Generation

Renewable energy is an important component of a diverse and reliable energy mix. Dominion Energy has nearly 3,200 MW of solar generating capacity in operation or under development in nine states, including offtake agreements for Virginia Power’s utility customers. Dominion Energy continues to add utility-scale solar capacity and currently has the fourth largest utility-owned solar fleet in the U.S. Backed by nearly $2 billion of investment from 2018 through 2020, Dominion Energy has grown its solar fleet in Virginia and North Carolina to about 2,400 MW in service, in construction or under development.

The Coastal Virginia Offshore Wind Pilot project is a 12 MW offshore wind demonstration project that is currently under construction and will be commercially available before the end of 2020. The Coastal Virginia Offshore Wind Commercial project is a 2,640 MW offshore wind project that was announced in September 2019 with construction beginning in 2024 and an anticipated completion in 2026.

Preservation of the Companies’ existing carbon-free baseload nuclear generation is also an important component of Dominion Energy’s GHG emissions reduction strategy. Accordingly, Virginia Power has commenced the process to extend the operating licenses for its four nuclear units at Surry and North Anna.

See

Operating Segments

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

GHG Emissions

Since 2000, Dominion Energy and Virginia Power have tracked the emissions of their electric generation fleet, which employs a mix of fuel and renewable energy sources. Comparing annual year 2018 to annual year 2000, the entire electric generating fleet (based on ownership percentage) reduced its average CO

emissions rate per MWh of energy produced from electric generation by approximately 53%. Comparing annual year 2018 to annual year 2000, the regulated electric generating fleet (based on ownership percentage) reduced its average CO

emissions rate per MWh of energy produced from electric generation by approximately 39%. Dominion Energy and Virginia Power’s 2019 emission data is not yet available. Emissions data disclosed herein excludes the operations acquired in the SCANA Combination.

Dominion Energy also develops a comprehensive GHG inventory annually. For Dominion Energy and Virginia Power’s electric generation operations, direct CO

equivalent emissions (based on ownership percentage) were 27.8 million metric tons and 24.6 million metric tons, respectively, in 2018, compared to 30.1 million metric tons and 26.5 million metric tons,

respectively, in 2017. The corresponding carbon intensity rates for Dominion Energy’s electric generation operations were 0.276 metric tons CO

equivalent emissions per net MWh in 2018 and 0.295 metric tons CO

equivalent emissions per net MWh in 2017.

For regulated electric transmission and distribution operations, direct CO

equivalent emissions for 2018 were 39,900 metric tons, compared to 37,841 metric tons in 2017.

Dominion Energy’s natural gas companies have been reporting GHG emissions to the EPA since 2011 under the GHG Reporting Program. In January 2016, the GHG Reporting Program was expanded to also include GHG inputs and emissions associated with natural gas gathering and boosting sources and transmission pipeline blowdowns for facilities that exceed 25,000 metric tons per year of CO

equivalent emissions. The sources within these new facilities were not previously covered under the rule and the first reports for these new sources were submitted to the EPA by March 31, 2017.

Dominion Energy’s GHG inventory follows all methodologies specified in the EPA Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98 for calculating emissions. Total CO

equivalent emissions reported for Dominion Energy’s natural gas assets, as estimated in Dominion Energy’s corporate inventory, were 4.14 million metric tons in 2018. This estimate includes emissions reported under the GHG Reporting Program, as well as other emissions not required to be reported under the federal program. The 2018 corporate GHG inventory emission estimate includes Dominion Energy Questar Pipeline, Questar Gas and Wexpro Company for the entire calendar year. Dominion Energy’s 2018 methane emissions reported under Subpart W of the Greenhouse Gas Reporting Rule are as follows:

Subpart W Segment		Subpart W Total CH 4 Emissions (mcf CH 4 )
Distribution			1,839,577
Production			736,188
Transmission pipelines			403,164
Transmission compressor stations			219,011
Gathering and boosting			219,056
Storage			88,973
LNG import/export			4,331
Processing			1,880

Methane Emissions

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

industry-led

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.

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Dominion Energy and Dominion Energy Gas do not expect the costs related to these programs to have a material impact on their results of operations, financial condition and/or cash flows.

Energy Infrastructure Modernization

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

Operating Segments

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

Operating Segments

for additional information, including natural gas infrastructure projects.

Conservation and Energy Efficiency

Conservation and load management play a significant role in meeting the growing demand for electricity and natural gas, while also helping to reduce the environmental footprint of Dominion Energy’s customers. The Companies offer various energy efficiency programs in Virginia, North Carolina, Ohio, South Carolina, Utah and Wyoming designed to reduce energy consumption including programs such as:

•	Energy audits and assessments;

•	Incentives for customers to upgrade or install certain energy efficient measures and/or systems;

•	Weatherization assistance to help income-eligible customers reduce their energy usage;

•	Home energy planning, which provides homeowners with a step-by-step roadmap to efficiency improvements to reduce gas usage; and

•	Rebates for installing high-efficiency equipment.

Cybersecurity

In an effort to reduce the likelihood and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of data and systems, including oversight by the Board of Directors as well as the financial and risk oversight board committee. The Companies are subject to mandatory cybersecurity regulatory requirements, interface regularly with a wide range of external organizations and participate in classified briefings to maintain an

awareness of current cybersecurity threats and vulnerabilities. The Companies’ current security posture and regulatory compliance efforts are intended to address the evolving and changing cyber threats. See Item 1A. Risk Factors for additional information.