10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2021

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

		I.R.S. Employer
Commission File Number	Exact name of registrant as specified in its charter	Identification Number
001-3375	DOMINION ENERGY SOUTH CAROLINA, INC.	57-0248695
	South Carolina
	(State or other jurisdiction of incorporation or organization)
	400 OTARRE PARKWAY
	CAYCE, South Carolina	29033
	(Address of principal executive offices)	(Zip Code)
	(803) 217-9000
	(Registrants’ telephone number)

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Series A Nonvoting Preferred Shares

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

Yes  ☐    No  ☒  

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

Yes  ☐    No  ☒

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

Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," “non-accelerated filer,” "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐ Accelerated filer ☐ non-accelerated filer ☒ Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. Yes ☐  No ☒

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act).

Yes ☐  No ☒

At February 11, 2022, Dominion Energy South Carolina, Inc. had 40,296,147 shares of common stock outstanding, all of which were held by SCANA Corporation, a wholly-owned subsidiary of Dominion Energy, Inc.

DOMINION ENERGY SOUTH CAROLINA, INC. MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND (b) OF FORM 10-K AND IS FILING THIS FORM 10-K UNDER THE REDUCED DISCLOSURE FORMAT.

Dominion Energy South Carolina, Inc.

Item Number		Page Number
	Glossary of Terms	3
Part I
Item 1.	Business	5
Item 1A.	Risk Factors	7
Item 1B.	Unresolved Staff Comments	12
Item 2.	Properties	12
Item 3.	Legal Proceedings	13
Item 4.	Mine Safety Disclosures	13
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	14
Item 6.	[Reserved]	14
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	18
Item 8.	Financial Statements and Supplementary Data	20
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	64
Item 9A.	Controls and Procedures	64
Item 9B.	Other Information	64
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	64
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	65
Item 11.	Executive Compensation	65
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	65
Item 13.	Certain Relationships and Related Transactions, and Director Independence	65
Item 14.	Principal Accounting Fees and Services	65
Part IV
Item 15.	Exhibits and Financial Statement Schedules	66
Item 16.	Form 10-K Summary	67

Glossary of Terms

The following abbreviations or acronyms used in this Form 10-K are defined below:

Abbreviation or Acronym	Definition
2015 Task Order	Retail services agreement between DESC and the DOE, which includes a FERC jurisdictional lease of the DOE transmission facilities at the Savannah River Site
2017 Tax Reform Act	An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (previously known as The Tax Cuts and Jobs Act) enacted on December 22, 2017
ACE Rule	Affordable Clean Energy Rule
AFUDC	Allowance for funds used during construction
AOCI	Accumulated other comprehensive income (loss)
ARO	Asset retirement obligation
BACT	Best available control technology
bcf	Billion cubic feet
BLRA	South Carolina Base Load Review Act
CAA	Clean Air Act
CCR	Coal combustion residual
CEO	Chief Executive Officer
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund
CFO	Chief Financial Officer
CO2	Carbon dioxide
CUA	Capacity Use Area
CWA	Clean Water Act
DECG	Carolina Gas Transmission, LLC (formerly known as Dominion Energy Carolina Gas Transmission, LLC), a subsidiary of Berkshire Hathaway Energy Company effective November 2020 (previously a subsidiary of Dominion Energy)
DES	Dominion Energy Services, Inc.
DESC	The legal entity, Dominion Energy South Carolina, Inc., one or more of its consolidated entities or operating segment, or the entirety of Dominion Energy South Carolina, Inc. and its consolidated entities
DESS	Dominion Energy Southeast Services, Inc.
Dodd-Frank Act	The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOE	U.S. Department of Energy
Dominion Energy	The legal entity, Dominion Energy, Inc., one or more of its consolidated subsidiaries (other than DESC) or operating segments, or the entirety of Dominion Energy, Inc. and its consolidated subsidiaries
Dominion Energy South Carolina	Dominion Energy South Carolina operating segment
DSM	Demand-side management
ELG Rule	Effluent limitations guidelines for the steam electric power generating category
EMANI	European Mutual Association for Nuclear Insurance
EPA	U.S. Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ERISA FASB	Employment Retirement Income Security Act of 1974 Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FILOT	Fee in lieu of taxes
Fuel Company	South Carolina Fuel Company, Inc.
GAAP	U.S. generally accepted accounting principles
GENCO	South Carolina Generating Company, Inc.
GHG	Greenhouse gas
IRS	Internal Revenue Service
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MGD	Million gallons per day
MGP	Manufactured gas plant
MW	Megawatt
NAV	Net asset value
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Corporation
NND Project	V.C. Summer Units 2 and 3 nuclear development project under which DESC and Santee Cooper undertook to construct two Westinghouse AP1000 Advanced Passive Safety nuclear units in Jenkinsville, South Carolina
NOX	Nitrogen oxide
NRC	U.S. Nuclear Regulatory Commission
Order 1000	Order issued by FERC adopting requirements for electric transmission planning, cost allocation and development
ORS	South Carolina Office of Regulatory Staff

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PGA	Purchased gas adjustment
PHMSA	U.S. Pipeline Hazardous Materials Safety Administration
Price-Anderson	Price-Anderson Amendments Act of 1988
PSD	Prevention of significant deterioration
Questar Gas	Questar Gas Company, a wholly-owned subsidiary of Dominion Energy
RICO	Racketeer Influenced and Corrupt Organizations Act
ROE	Return on equity
RSA	Natural Gas Rate Stabilization Act
Santee Cooper	South Carolina Public Service Authority
SCANA	The legal entity, SCANA Corporation, one or more of its consolidated subsidiaries (other than DESC) or the entirety of SCANA Corporation and its consolidated subsidiaries
SCANA Combination	Dominion Energy's acquisition of SCANA completed on January 1, 2019 pursuant to the terms of the SCANA Merger Agreement
SCANA Merger Agreement	Agreement and plan of merger entered on January 2, 2018 between Dominion Energy and SCANA
SCANA Merger Approval Order	Final order issued by the South Carolina Commission on December 21, 2018 setting forth its approval of the SCANA Combination
SCDHEC	South Carolina Department of Health and Environmental Control
SCDOR	South Carolina Department of Revenue
Scope 1 emissions	Emissions that are produced directly by an entity’s own operations
Scope 2 emissions	Emissions from electricity a company consumes but does not generate from its own facilities
Scope 3 emissions	Emissions generated downstream of company operations by customers and upstream by suppliers
SEC	U.S. Securities and Exchange Commission
SEMI	SCANA Energy Marketing, LLC (formerly known as SCANA Energy Marketing, Inc.), a subsidiary of SCANA through December 2019, and effective December 2019, a subsidiary of Wrangler Retail Gas Holdings, LLC, a partnership between Dominion Energy and Interstate Gas Supply Inc.
SO2	Sulfur dioxide
South Carolina Commission	Public Service Commission of South Carolina
Southern	The legal entity, The Southern Company, one or more of its consolidated subsidiaries, or the entirety of The Southern Company and its consolidated subsidiaries
Summer	V.C. Summer nuclear power station
Toshiba	Toshiba Corporation, parent company of Westinghouse
Toshiba Settlement	Settlement Agreement dated as of July 27, 2017, by and among Toshiba, DESC and Santee Cooper
VIE	Variable interest entity
Virginia Power	The legal entity, Virginia Electric and Power Company, a wholly-owned subsidiary of Dominion Energy, one or more of its consolidated subsidiaries or operating segment, or the entirety of Virginia Electric and Power Company and its consolidated subsidiaries
WECTEC	WECTEC Global Project Services, Inc., a wholly-owned subsidiary of Westinghouse
Westinghouse	Westinghouse Electric Company LLC
WNA	Weather normalization adjustment

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Part I

Item 1. Business

GENERAL

DESC, a public utility headquartered in Cayce, South Carolina, is a South Carolina corporation organized in 1924. DESC is a wholly-owned subsidiary of SCANA, which is a wholly-owned subsidiary of Dominion Energy. DESC conducts business under the name “Dominion Energy South Carolina.” At December 31, 2021, DESC had approximately 2,400 employees, of which approximately 720 were subject to collective bargaining agreements.

DESC is engaged in the generation, transmission and distribution of electricity to approximately 772,000 customers in the central, southern and southwestern portions of South Carolina. Additionally, DESC distributes natural gas to approximately 419,000 residential, commercial and industrial customers in South Carolina. DESC’s business experiences seasonal fluctuations, with generally higher sales of electricity during the summer and winter months because of air conditioning and heating requirements, and generally higher sales of natural gas during the winter months due to heating requirements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold exclusively to DESC, pursuant to a FERC-approved power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Fuel Company acquires, owns and provides financing for DESC's nuclear fuel, certain fossil fuels and emission and other environmental allowances.

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 ORS for enforcement of federal and state pipeline safety requirements in its service territories.

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 a return on invested capital. 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 also submits annual filings to the South Carolina Commission for rider recovery related to its DSM program and pension costs. The DSM rider includes recovery of any net lost revenues and for a shared savings incentive.

Pursuant to the SCANA Merger Approval Order, DESC is recovering capital costs and a return on capital cost rate base related to the NND Project over a 20-year period through a capital cost rider. The capital cost rider also provides for the return to retail electric customers of certain amounts associated with the NND Project. Revenue from the capital cost rider component of retail electric rates will continue to decline over the 20-year period as capital cost rate base is reduced.

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 RSA, 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

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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.

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.

Federal Energy Regulatory Commission

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. 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, DESC has FERC approved tariffs to sell wholesale power at capped rates based on its respective embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside DESC’s service territory. Any such sales are voluntary.

DESC is subject to FERC’s Standards of Conduct that govern conduct between transmission function employees of interstate gas and electric transmission providers and the marketing function employees of its 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 affiliates undue preferences.

DESC is also subject to FERC’s affiliate restrictions that (1) prohibit power sales between nonregulated plants and utility plants without first receiving FERC authorization, (2) require the nonregulated and utility plants to conduct their wholesale power sales operations separately, and (3) prohibit utilities from sharing market information with nonregulated plant operating personnel. The rules are designed to prohibit utilities from giving the nonregulated 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 $1.4 million per day, per violation and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.

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.

In February 2021, DESC and the other members of the Southeast Energy Exchange Market submitted the Southeast Energy Exchange Market Agreement to FERC for authorization. This agreement sets forth the framework and rules for establishing and maintaining a new electronic trading platform designed to enhance the existing bilateral market in the Southeast utilizing zero-charge transmission service. That transmission service, in turn, will be voluntarily provided by participating transmission service providers, including DESC. In October 2021, the Southeast Energy Exchange Market Agreement became effective by operation of law as a result of a split FERC vote. The members expect the Southeast Energy Exchange Market platform to be operational in the third quarter of 2022.

WHERE YOU CAN FIND MORE INFORMATION

DESC files its annual, quarterly and current reports and other information with the SEC. Its SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov.

DESC makes its SEC filings available, including the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, available free of charge 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 is not incorporated by reference in this report.

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Item 1A. Risk Factors

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

Regulatory, Legislative and Legal Risks

The rates that DESC can charge are subject to regulatory review. Revenue provided by DESC’s operations is based primarily on rates approved by state regulatory agencies. The profitability of DESC’s business is dependent on its ability, through the rates that it is permitted to charge, to recover costs and earn a reasonable rate of return on its capital investment.

DESC’s retail electric base rates for services to customers 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 return on invested capital. If retail electric earnings exceed the returns established by the South Carolina Commission, retail electric rates may be subject to review and possible reduction by the South Carolina Commission, which may decrease DESC’s future earnings. If the South Carolina Commission does not allow recovery through base rates, on a timely basis, of costs incurred in providing service, DESC’s future earnings could be negatively impacted.

Under certain circumstances, the South Carolina Commission may impose a moratorium on increases to retail base rates for a specified period of time, which could delay recovery of costs incurred in providing service. Additionally, governmental officials, stakeholders and advocacy groups may challenge these regulatory reviews. Such challenges may lengthen the time, complexity and costs associated with such regulatory reviews.

DESC has been and may continue to be or become subject to legal proceedings and governmental investigations and examinations. DESC has been subject to numerous federal and state legal proceedings and governmental investigations relating to the decision of SCANA and DESC to abandon construction at the NND Project. DESC has spent, and continues to spend, substantial amounts of time and money defending these lawsuits and proceedings and on related investigations. In addition, juries have demonstrated a willingness to grant large awards in certain cases, including personal injury claims. Accordingly, actual costs incurred may differ materially from insured or reserved amounts and may not be recoverable, in whole or in part, by insurance or in rates from our customers. The outcome of these legal proceedings, investigations and examinations, including settlements, may adversely affect DESC’s financial condition or results of operation.

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

Environmental Risks

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

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

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

Compliance with federal and/or state requirements imposing limitations on GHG emissions or  efficiency improvements, as well as Dominion Energy’s commitment to achieve net zero carbon and methane emissions by 2050, may result in significant compliance costs, could result in certain of DESC’s electric generation units or natural gas facilities being uneconomical to maintain or operate and may depend upon technological advancements which may be beyond DESC’s control. In February 2020, Dominion Energy announced its commitment to achieve net zero carbon and methane Scope 1 emissions by 2050. In February 2022, Dominion Energy expanded this commitment to cover Scope 2 emissions and material categories of Scope 3 emissions. To help Dominion Energy meet this commitment, DESC may need to construct new electric generation facilities, including renewable facilities such as solar. DESC will also need to depend on technological improvements not currently in commercial development. Additionally, actions taken in furtherance of Dominion Energy’s net zero commitment may impact existing generation facilities, including as a result of fuel switching and/or the retirement of high-emitting generation facilities and their potential replacement with lower-emitting generation facilities. Further, the ability to realize this commitment may require DESC to be able to obtain significant financing. The federal government or South Carolina may also enact legislation or regulations relating to climate change matters such as the reduction of GHG emissions and renewable energy portfolio standards, similar to the Virginia Clean Economy Act of 2020.

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

These efforts will require regulatory approvals for the siting and construction of such new facilities and a determination by the South Carolina Commission that costs related to the construction are prudent. Given these and other uncertainties associated with the implementation of Dominion Energy’s net zero commitment, DESC cannot estimate the aggregate effect of future actions taken in furtherance of this commitment on its results of operations or financial condition or on its customers. However, such actions could render additional existing generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect DESC’s results of operations, financial performance or liquidity.

Construction Risks

DESC’s infrastructure build and expansion plans often require regulatory approval, including environmental permits, before commencing construction and completing projects. DESC may not complete facility construction, electric transmission line, conversion or other infrastructure projects that it commences, or it may complete projects on materially different terms, costs or timing than initially estimated or anticipated, and it may not be able to achieve the intended benefits of any such project, if completed. Commencing construction on announced and future projects may require approvals from applicable state and federal agencies, and such approvals could include mitigation costs which may be material to DESC. Projects may not be able to be completed on time or in accordance with our estimated costs as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, concerns raised during stakeholder engagement, a decline in the credit strength of counterparties or vendors, inflation, or other factors beyond DESC’s control. Even if facility construction, electric transmission line, conversion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of DESC following completion of the projects may not meet expectations. Start-up and operational issues can arise in connection with the commencement of commercial operations at our facilities. Such issues may include failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, DESC may not be able to timely and effectively integrate the projects into its operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect DESC’s ability to realize the anticipated benefits from the facility construction, electric transmission line, conversion and other infrastructure projects.

Operational Risks

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

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

A successful cyber attack through third-party or insider action on the systems that control DESC’s electric generation and electric or gas transmission or distribution assets could severely disrupt business operations, preventing DESC from serving customers or collecting revenues. The breach of certain business systems could affect DESC’s ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to DESC’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data at DESC or one of its vendors could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. If a significant breach were to occur, the reputation of DESC also could be adversely affected. While DESC maintains property and casualty insurance, along with other contractual provisions, that may cover certain damage caused by potential cyber incidents, all damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could materially and adversely affect DESC’s business, financial condition and results of operations.

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

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

In addition, there are many risks associated with DESC’s operations and the transportation, storage and distribution of natural gas, including nuclear accidents, fires, explosions, uncontrolled release of natural gas and other environmental hazards, pole strikes, electric contact cases, the collision of third party equipment with pipelines and avian and other wildlife impacts. Such incidents could result in loss of human life or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or business interruptions and associated public or employee safety impacts, loss of revenues, increased liabilities, heightened regulatory scrutiny and reputational risk. Further, the location of pipelines and storage facilities, or generation, transmission, substations and distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.

DESC’s financial results can be adversely affected by various factors driving supply and demand for electricity and gas and related services. Technological advances required by federal laws mandate new levels of energy efficiency in end-use devices, including lighting, furnaces and electric heat pumps and could lead to declines in per capita energy consumption. Additionally, certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Consumer demand for our services may also be impacted by any price increases, including those driven from factors beyond our control such as inflation or increased prices in natural gas.  Further, DESC’s business model is premised upon the cost efficiency of the production, transmission and distribution of large-scale centralized utility generation. However, advances in distributed generation technologies, such as solar cells, gas microturbines, battery storage and fuel cells, may make these alternative generation methods competitive with large-scale utility generation, and change how customers acquire or use our services. The widescale implementation of alternative generation methods could negatively impact the reliability of DESC’s electric grid and/or result in significant costs to enhance the grid.  DESC has an exclusive franchise to serve retail electric customers in its South Carolina service territory. If regulatory conditions change, DESC’s exclusive franchise may erode.

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

DESC may be materially adversely affected by negative publicity or the inability of Dominion Energy to meet its stated commitments. From time to time, political and public sentiment may result in a significant amount of adverse press coverage and

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other adverse public statements affecting DESC. Additionally, any failure by Dominion Energy to realize its commitments to achieve net zero carbon and methane emissions by 2050, increase workforce diversity, enhance the customer experience or other long-term goals could lead to adverse press coverage and other adverse public statements affecting DESC. The ability to comply with some or all of Dominion Energy’s voluntary commitments may be outside of DESC’s control. For example, Dominion Energy is dependent on the actions of third parties to meet the expanded commitment regarding Scope 2 emissions and Scope 3 emissions. If downstream customers or upstream suppliers do not sufficiently reduce their GHG emissions, Dominion Energy may not achieve its net zero emissions goal. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims as well as adverse outcomes.

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

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

Instability in financial markets as a result of terrorism, war, intentional acts, pandemic, credit crises, recession or other factors could result in a significant decline in the U.S. economy and/or increase the cost or limit the availability of insurance or adversely impact DESC’s ability to access capital on acceptable terms.

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

Nuclear Generation Risks

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

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

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Financial, Economic and Market Risks

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

An inability to obtain needed capital or financing on satisfactory terms, or at all, could have an adverse effect on DESC’s operations and ability to generate cash flow. DESC is dependent on certain financing arrangements with Dominion Energy for any borrowings necessary to meet its working capital and other financial needs. If Dominion Energy’s funding resources were to become unavailable to Dominion Energy, DESC’s access to funding would also be in jeopardy. In the future, an inability to obtain additional financing from other sources on acceptable terms could negatively affect its financial condition, cash flows, anticipated financial results or impair its ability to generate additional cash flows. The ability to obtain bank financing or to access the capital markets for future debt offerings may be limited by the financial condition of DESC at the time of any such financing or offering or other debt agreements in place at the time, adverse market conditions or other contingencies and uncertainties that are beyond our control.

DESC also relies on a credit facility with banks to meet short-term funding needs. Banks may be unable or unwilling to extend credit in the future. From time to time, DESC may use interest-rate derivatives to fix the rate on a portion of its variable-rate debt. A downgrade of credit ratings could increase the interest cost of debt and decrease future availability of capital from banks and other sources. While management believes it is important to maintain investment-grade credit ratings to conduct DESC’s businesses, DESC may not be able to keep investment-grade ratings.

Market performance, interest rates and other changes may decrease the value of DESC’s decommissioning trust fund and benefit plan assets or increase DESC’s liabilities, which could then require significant additional funding. The performance of the capital markets affects the value of the assets that are held in trust to satisfy future obligations to decommission DESC’s nuclear plant and under DESC’s pension plan. DESC has significant obligations in these areas and holds significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates.

With respect to the decommissioning trust fund, a decline in the market value of these assets may increase the funding requirements of the obligations to decommission DESC’s nuclear plant or require additional NRC-approved funding assurance.

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

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

The use of derivative instruments could result in financial losses and liquidity constraints. DESC may use derivative instruments, including futures, swaps, forwards and options, to manage financial market risks. DESC could be required to provide cash collateral or recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities and financial contracts or if a counterparty fails to perform under a contract.

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

Exposure to counterparty performance may adversely affect DESC’s financial results of operations. DESC is exposed to credit risks of its counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. Defaults or failure to perform by customers, suppliers, contractors, joint venture partners, financial institutions or other third parties may adversely affect DESC’s financial results.

Public health crises and epidemics or pandemics, such as COVID-19, could adversely affect DESC’s business, results of operations, financial condition, liquidity and/or cash flows.  The effects of the continued outbreak of the COVID-19 pandemic and related government responses could include extended disruptions to supply chains and capital markets, reduced labor availability and

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productivity and a prolonged reduction in economic activity. The effects could also have a variety of adverse impacts on DESC, including reduced demand for energy, particularly from commercial and industrial customers, impairment of long-lived assets and diminished ability of Dominion Energy or DESC to access funds from financial institutions and capital markets.  There remains uncertainty regarding the extent and duration of measures to try to contain the virus, such as travel bans and restrictions, quarantines, shelter-in-place orders and shutdowns. Such restrictions may cause operational interruptions and delays in construction projects, which, in the case of renewable energy projects, could delay the expected in-service dates of these projects and financial statement impact of the investment tax credits associated with these projects. For the duration of the outbreak of COVID-19, voluntary suspension, or potential legislative or government action, such as legislation similar to that enacted in Virginia in November 2020, may limit DESC’s ability to collect on overdue accounts or disconnect services for non-payment, which may cause a decrease in DESC’s results of operations and cash flows.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

DESC has approximately 3,800 miles and 18,700 miles of electric transmission and distribution lines, respectively, exclusive of service level lines, in South Carolina. The grants for most of DESC’s electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying property titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, DESC owns 458 substations.

DESC’s natural gas system includes approximately 19,200 miles of distribution mains and related service facilities, which are supported by approximately 400 miles of transmission pipeline.

DESC owns two LNG facilities, one located near Charleston, South Carolina, and the other in Salley, South Carolina. The Charleston facility can store the liquefied equivalent of approximately 1.0 bcf of natural gas, can regasify approximately 6% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day. The Salley facility can store the liquefied equivalent of approximately 0.9 bcf of natural gas and can regasify approximately 10% of its storage capacity per day. The Salley facility has no liquefying capabilities.

DESC’s bond indenture, which secures its first mortgage bonds, constitutes a direct mortgage lien on substantially all of its electric utility property.

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The following table lists DESC’s generating units and capability as of December 31, 2021.

Plant	Location	Net Summer Capability (MW)			Percentage Net Summer Capability
Gas
Jasper (CC)(1)	Hardeeville, SC		863
Columbia Energy Center (CC)(1)	Gaston, SC		519
Urquhart (CC)(1)	Beech Island, SC		458
McMeekin	Irmo, SC		250
Hagood (CT)(1)	Charleston, SC		126
Urquhart Unit 3	Beech Island, SC		95
Urquhart (CT)(1)	Beech Island, SC		87
Parr (CT)(1)(2)	Jenkinsville, SC		47
Coit (CT)(1)(2)	Columbia, SC		26
Williams (CT)(1)(2)	Goose Creek, SC		16
Total Gas(3)			2,487			40	%
Coal
Williams	Goose Creek, SC		605
Cope(4)	Cope, SC		415
Wateree(5)	Eastover, SC		342
Total Coal			1,362			22
Hydro
Fairfield	Jenkinsville, SC		576
Saluda	Irmo, SC		190
Other	Various		18
Total Hydro			784			13
Nuclear
Summer	Jenkinsville, SC		651	(6)		11
			5,284
Power Purchase Agreements			898	(7)		14
Total Utility Generation			6,182			100	%

Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.

(1) Capable of burning fuel oil as a secondary source.

(2) Expected to be retired by the end of 2025.

(3) Excludes the Hardeeville gas combustion turbine which currently does not have any net summer capability and is expected to be retired by the end of 2025.

(4) Capable of burning natural gas as a secondary source.

(5) Excludes Wateree Unit 2 (342 MW) that is temporarily unavailable and it is expected to be returned to service in 2022.

(6) Excludes 33.3% undivided interest owned by Santee Cooper.

(7) Includes 189 MW from agreements with certain solar facilities within Dominion Energy.

Item 3. Legal Proceedings

From time to time, DESC is party to various legal, environmental or other regulatory proceedings, including in the ordinary course of business. SEC regulations require disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that DESC reasonably believes will exceed a specified threshold. Pursuant to the SEC regulations, DESC uses a threshold of $1 million for such proceedings. See Notes 3 and 12 to the Consolidated Financial Statements, which information is incorporated herein by reference, for discussion of certain legal, environmental and other regulatory proceedings to which DESC is a party.

Item 4. Mine Safety Disclosures

Not Applicable.

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Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

There is no established public trading market for DESC’s common stock, all of which is owned by SCANA. DESC may pay cash dividends in 2022 but is neither required to nor restricted, except as described in Note 5 to the Consolidated Financial Statements, from making such payments.

Item 6. [Reserved]

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

MD&A discusses DESC’s results of operations and general financial condition. MD&A should be read in conjunction with Item 1. Business and the Financial Statements in Item 8. Financial Statements and Supplementary Data. DESC meets the conditions to file under the reduced disclosure format, and therefore has omitted certain sections of MD&A.

CONTENTS OF MD&A

MD&A consists of the following information:

• Forward-Looking Statements

• Results of Operations

• Analysis of Operations

FORWARD-LOOKING STATEMENTS

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

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

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

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

• The impact of extraordinary external events, such as the current pandemic health event resulting from COVID-19, and their collateral consequences, including extended disruption of economic activity in our markets and global supply chains;

• Federal, state and local legislative and regulatory developments, including changes in or interpretations of federal and state tax laws and regulations;

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

• Changes to regulated rates collected;

• Changes in future levels of domestic and international natural gas production, supply or consumption;

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

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

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

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

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

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

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

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

• Changes in operating, maintenance and construction costs;

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

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• Additional competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies;

• Competition in the development, construction and ownership of certain electric transmission facilities in connection with Order 1000;

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

• Changes in demand for services, including industrial, commercial and residential growth or decline in service areas, changes in supplies of natural gas delivered, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;

• Adverse outcomes in litigation matters or regulatory proceedings, including matters related to the NND Project;

• Counterparty credit and performance risk;

• Fluctuations in the value of investments held in nuclear decommissioning and benefit plan trusts;

• Fluctuations in energy-related commodity prices and the effect these could have on DESC’s liquidity position and the underlying value of its assets;

• Fluctuations in interest rates;

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

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

• Political and economic conditions, including inflation and deflation;

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

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

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

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

RESULTS OF OPERATIONS

Presented below is a summary of DESC’s results:

Year Ended December 31,	2021		$ Change			2020
(millions)
Net income	$	229	$	(79	)	$	308

Overview

2021 VS. 2020

Net income decreased 26%, primarily due to charges associated with the settlement of the South Carolina electric base rate case.

Analysis of Consolidated Operations

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

Year Ended December 31,	2021			$ Change			2020
(millions)
Operating revenues	$	3,146		$	407		$	2,739
Fuel used in electric generation		646			199			447
Purchased power		116			30			86
Gas purchased for resale		285			104			181
Other operations and maintenance		606			36			570
Impairment of assets and other charges		320			209			111
Depreciation and amortization		486			12			474
Other taxes		255			16			239
Other expense, net		(2	)		21			(23	)
Interest charges		192			(37	)		229
Income tax expense		9			(62	)		71

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An analysis of DESC’s results of operations follows:

2021 VS. 2020

Operating revenue increased 15% primarily reflecting:

• A $345 million increase in the fuel cost component included in utility rates as a result of an increase in commodity costs and purchased power costs associated with sales to electric utility customers ($241 million) and gas utility customers ($104 million);

• A $27 million increase in sales to electric utility retail customers associated with economic and other usage factors

• A $26 million increase in sales to electric utility retail customers associated with growth;

• A $11 million increase in non-fuel base rates associated with the settlement of the South Carolina electric base rate case;

• A $8 million increase in sales to gas utility customers associated with growth; and

• A $6 million increase associated with increased infrastructure cost recovery under the RSA; partially offset by

• A $8 million decrease in sales to electric utility retail customers from a decrease in cooling degree days during the cooling season ($14 million) partially offset by an increase in heating degree days during the heating season ($6 million).

Fuel used in electric generation increased 45%, primarily due to increased fuel costs associated with electric utility customers, which are offset in operating revenue and do not impact net income.

Purchased power increased 35%, primarily due to an increase in costs associated with electric utility customers ($46 million), which are offset in operating revenue and do not impact net income, partially offset by a decrease in capacity expense ($9 million).

Gas purchased for resale increased 57%, primarily due to an increase in costs associated with gas utility customers, which are offset in operating revenue and do not impact net income.

Other operations and maintenance increased 6%, primarily due to an increase in salaries, wages and benefits and administrative expenses ($39 million), an increase in outside services ($7 million) and an increase in costs associated with the settlement of the South Carolina electric base rate case ($7 million), partially offset by lower bad debt expense, primarily due to the effects of COVID-19 in 2020 ($7 million).

Impairment of assets and other charges increased $209 million, primarily due to charges associated with the settlement of the South Carolina electric base rate case ($249 million), partially offset by a decrease in charges associated with litigation ($27 million) and the absence of an impairment charge of certain nonutility property ($12 million).

Other expense decreased 91%, primarily due to lower non-service costs related to pension and other postretirement benefits ($14 million), a benefit from the reversal of penalty expense associated with the effective settlement of uncertain tax positions ($7 million) and the absence of a pension settlement charge ($6 million), partially offset by charges associated with the settlement of the South Carolina electric base rate case ($18 million).

Interest charges decreased 16%, primarily due to a benefit associated with the effective settlement of uncertain tax positions ($28 million), lower money pool interest ($8 million) and lower amortization on losses of reacquired debt associated with the settlement of the South Carolina electric base rate case ($8 million).

Income tax expense decreased 87%, primarily due to lower pre-tax income ($35 million) and a benefit associated with the effective settlement of uncertain tax positions ($38 million), partially offset by the absence of changes in excess deferred income tax amortization associated with the gain on the sale of SEMI’s assets ($7 million).

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs of Item 7. MD&A. The reader’s attention is directed to those paragraphs and Item 1A. Risk Factors for discussion of various risks and uncertainties that may impact DESC.

MARKET RISK SENSITIVE INSTRUMENTS AND RISK MANAGEMENT

DESC’s financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in interest rates and commodity prices as described below. Interest rate risk is generally related to DESC’s outstanding debt and future issuances of debt. In addition, DESC is exposed to investment price risk through various portfolios of equity and debt securities.

The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% change in interest rates.

Commodity Price Risk

To manage price risk, DESC holds commodity-based derivative instruments held for non-trading purposes associated with the purchases of electricity.

The derivatives used to manage commodity price risk are executed within established policies and procedures and include instruments such as physical forwards that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices of commodity-based derivative instruments is determined based on models that consider the market prices of commodities in future periods, as well as the time value factors of the derivative instruments. Prices are principally determined based on observable market prices.

A hypothetical 10% decrease in commodity prices would have resulted in a decrease of $85 million in the fair value of DESC’s commodity-based derivative instruments as of December 31, 2021. As of December 31, 2020, DESC did not hold commodity-based derivative instruments held for non-trading purposes.

The impact of a change in energy commodity prices on DESC’s commodity-based derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled.

Interest Rate Risk

DESC manages its interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. For variable rate debt outstanding, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at December 31, 2021 or December 31, 2020.

DESC also uses interest rate derivatives, including forward-starting swaps and interest rate swaps to manage interest rate risk. As of December 31, 2021, DESC had $71 million in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $3 million in the fair value of DESC’s interest rate derivatives at December 31, 2021. As of December 31, 2020, DESC had $71 million in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $1 million in the fair value of DESC’s interest rate derivatives at December 31, 2020.

The impact of a change in interest rates on DESC’s interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.

Investment Price Risk

DESC is subject to investment price risk due to securities held as investments in nuclear decommissioning trust funds which primarily hold insurance contracts that are reported in the Consolidated Balance Sheets at fair value.

DESC recognized net investment gains (including investment income) on nuclear decommissioning trust investments of $18 million and $24 million for the years ended December 31, 2021 and 2020, respectively.

DESC participates in the SCANA sponsored pension plan that holds investments in trusts to fund employee benefit payments. DESC’s pension plan assets experienced aggregate actual returns of $62 million and $84 million in 2021 and 2020, respectively, versus expected returns of $48 million and $45 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. A hypothetical 0.25% decrease in the assumed long-term rates of return on

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DESC’s plan assets would result in an increase in net periodic cost of $2 million at both December 31, 2021 and 2020, for pension benefits.

Risk Management Policies

DESC has established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion Energy has established an independent function at the corporate level to monitor compliance with the credit and commodity risk management policies of all subsidiaries, including DESC. Dominion Energy maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion Energy also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and DESC’s December 31, 2021 provision for credit losses, management believes that it is unlikely that a material adverse effect on DESC’s financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

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Item 8. Financial Statements and Supplementary Data

	Page Number
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)	21
Consolidated Balance Sheets at December 31, 2021 and 2020	23
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2021, 2020 and 2019	25
Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019	26
Consolidated Statements of Changes in Common Equity at December 31, 2021, 2020 and 2019 and for the years then ended	27
Notes to Consolidated Financial Statements	28

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Dominion Energy South Carolina, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Dominion Energy South Carolina, Inc. (an indirect, wholly-owned subsidiary of Dominion Energy, Inc.) and affiliates (“DESC”) at December 31, 2021 and 2020, the related consolidated statements of comprehensive income (loss), changes in common equity, and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of DESC at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

The consolidated financial statements are the responsibility of DESC's management. Our responsibility is to express an opinion on DESC's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to DESC in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. DESC is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of DESC’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Assets and Liabilities – Impact of Rate Regulation on the Consolidated Financial Statements —Refer to Notes 2 and 3 to the Consolidated Financial Statements

Critical Audit Matter Description

DESC, through its regulated electric and gas operations, is subject to rate regulation by the Public Service Commission of South Carolina (the “South Carolina Commission”) and FERC, which has jurisdiction with respect to the rates of utility companies in the territory DESC serves. Management has determined DESC meets the requirements under accounting principles generally accepted in the United States of America to apply the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures such as utility plant, net; regulatory assets; regulatory liabilities; operating revenue and operating expenses, collectively, the “financial statement impacts of rate regulation”.

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

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about the financial statement impacts of rate regulation. Management judgments include assessing the likelihood of (1) recovery of its regulatory assets through future rates and (2) whether a regulatory liability is due to customers. Given that

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management’s accounting judgments are based on assumptions about the outcome of future decisions by the South Carolina Commission, auditing these judgments required specialized knowledge of the accounting for rate regulation and the rate setting process due its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable included the following, among others:

• We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) recovery of regulatory assets through future rates, and (2) whether a regulatory liability is due to customers. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may impact the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable.

• We evaluated DESC’s disclosures related to the consolidated financial statement impact of rate regulation.

• We read and evaluated orders issued by the South Carolina Commission, as well as relevant regulatory statutes, interpretations, procedural memorandums, filings made by interveners, existing laws and other publicly available information to assess whether this external information was properly considered by management in concluding upon the financial statement impacts of rate regulation.

• We considered the likelihood of (1) recovery of regulatory assets through future rates and (2) whether a regulatory liability is due to customers based on precedents established by the South Carolina Commission’s previous orders and the DESC’s past experience with the South Carolina Commission.

• For regulatory matters in process, we inspected associated documents and testimony filed with the South Carolina Commission for any evidence that might contradict management’s assertions.

• We read and analyzed the minutes of the Board of Directors of Dominion Energy, Inc. and the Board of Directors of DESC, for discussions of changes in legal, regulatory, or business factors which could impact management’s conclusions with respect to the financial statement impacts of rate regulation.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 24, 2022

We have served as DESC’s auditor since 1945.

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Dominion Energy South Carolina, Inc.

Consolidated Balance Sheets

At December 31,	2021			2020
(millions)
ASSETS
Utility plant in service	$	14,200		$	13,680
Accumulated depreciation and amortization		(5,192	)		(5,027	)
Construction work in progress		481			460
Nuclear fuel, net of accumulated amortization		216			221
Utility plant, net ($729 and $730 related to VIEs)		9,705			9,334
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation		42			39
Assets held in trust, nuclear decommissioning		256			238
Nonutility property and investments, net		298			277
Current Assets:
Cash and cash equivalents		30			5
Receivables:
Customer, net of allowance for uncollectible accounts of $5 and $10		358			365
Affiliated and related party		16			16
Other		152			64
Inventories (at average cost):
Fuel		60			68
Gas storage		25			14
Materials and supplies		186			176
Prepayments		70			75
Regulatory assets		361			229
Other current assets		57			27
Total current assets ($77 and $103 related to VIEs)		1,315			1,039
Deferred Debits and Other Assets:
Regulatory assets		3,323			3,726
Affiliated receivables		66			—
Other		220			103
Total deferred debits and other assets ($31 and $35 related to VIEs)		3,609			3,829
Total assets	$	14,927		$	14,479

See Notes to Consolidated Financial Statements.

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At December 31,	2021			2020
(millions)
CAPITALIZATION AND LIABILITIES
Common Stock - no par value, 40.3 million shares outstanding	$	4,016		$	4,017
Retained earnings		335			277
Accumulated other comprehensive loss		(1	)		(2	)
Total common equity		4,350			4,292
Noncontrolling interest		175			192
Total Equity		4,525			4,484
Long-term debt, net		3,724			3,327
Affiliated long-term debt		230			230
Finance leases		10			15
Total long-term debt		3,964			3,572
Total capitalization		8,489			8,056
Current Liabilities:
Securities due within one year		5			39
Accounts payable		232			178
Affiliated and related party payables		458			457
Customer deposits and customer prepayments		73			70
Taxes accrued		222			215
Interest accrued		73			95
Regulatory liabilities		245			283
Reserves for litigation and regulatory proceedings		211			208
Other		144			40
Total current liabilities		1,663			1,585
Deferred Credits and Other Liabilities:
Deferred income taxes and investment tax credits		975			858
Asset retirement obligations		599			597
Pension and other postretirement benefits		164			172
Regulatory liabilities		2,936			3,005
Affiliated liabilities		—			13
Other		101			193
Total deferred credits and other liabilities		4,775			4,838
Commitments and Contingencies (see Note 12)
Total capitalization and liabilities	$	14,927		$	14,479

See Notes to Consolidated Financial Statements.

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Dominion Energy South Carolina, Inc.

Consolidated Statements of Comprehensive Income (Loss)

Year Ended December 31,	2021			2020			2019
(millions)
Operating Revenue(1)	$	3,146		$	2,739		$	1,929
Operating Expenses:
Fuel used in electric generation(1)		646			447			573
Purchased power(1)		116			86			54
Gas purchased for resale(1)		285			181			216
Other operations and maintenance		417			357			388
Other operations and maintenance – affiliated suppliers		189			213			244
Impairment of assets and other charges		320			111			695
Depreciation and amortization		486			474			450
Other taxes(1)		255			239			250
Total operating expenses		2,714			2,108			2,870
Operating income (loss)		432			631			(941	)
Other expense, net		(2	)		(23	)		(33	)
Interest charges, net of allowance for funds used during    construction of $3, $5 and $5(1)		192			229			260
Income (loss) before income tax expense (benefit)		238			379			(1,234	)
Income tax expense (benefit)		9			71			(12	)
Net Income (Loss)		229			308			(1,222	)
Other Comprehensive Income:
Deferred cost of employee benefit plans, net of tax of $-, $- and $-		1			1			1
Total Comprehensive Income (Loss)		230			309			(1,221	)
Comprehensive Income Attributable to Noncontrolling Interest		21			12			18
Comprehensive Income (Loss) Available (Attributable) to Common Shareholder	$	209		$	297		$	(1,239	)

(1)   See Note 16 for amounts attributable to affiliates.

See Notes to Consolidated Financial Statements.

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Dominion Energy South Carolina, Inc.

Consolidated Statements of Cash Flows

Year Ended December 31,	2021			2020			2019
(millions)
Operating Activities
Net income (loss)	$	229		$	308		$	(1,222	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairment of assets and other charges		311			(14	)		576
Provision for refunds to electric customers		—			—			800
Gain on sale of assets		—			—			(7	)
Deferred income taxes, net		117			229			(379	)
Depreciation and amortization		486			474			464
Amortization of nuclear fuel		34			41			53
Other adjustments		14			25			(4	)
Changes in certain assets and liabilities:
Receivables		(79	)		(8	)		(36	)
Receivables – affiliated and related party		(15	)		4			1
Inventories		(13	)		14			(76	)
Prepayments		13			15			(9	)
Regulatory assets		(152	)		21			(20	)
Regulatory liabilities		(109	)		(193	)		265
Accounts payable		44			(19	)		(54	)
Accounts payable – affiliated and related party		(59	)		52			(15	)
Revenue subject to refund		—			—			(73	)
Interest accrued		(22	)		—			—
Unrecognized tax benefits		—			—			52
Taxes accrued		7			(3	)		(10	)
Pension and other postretirement benefits		(8	)		(31	)		(27	)
Other assets and liabilities		(79	)		97			169
Net cash provided by operating activities		719			1,012			448
Investing Activities
Property additions and construction expenditures		(758	)		(742	)		(497	)
Proceeds from (purchases of) investments and sales of assets		7			(12	)		39
Purchase of investments		(9	)		15			(54	)
Purchase of investments – affiliate		—			(1	)		—
Short-term investments - affiliated		15			—			—
Investment in affiliate, net		—			(7	)		344
Other		(5	)		—			—
Net cash used in investing activities		(750	)		(747	)		(168	)
Financing Activities
Proceeds from issuance of debt		397			—			—
Proceeds from issuance of affiliated debt		—			—			230
Repayment of long-term debt, including redemption premiums		(34	)		—			(1,890	)
Dividend to parent		(188	)		(38	)		(30	)
Short-term borrowings, net		—			—			(73	)
Short-term borrowings – affiliated, net		60			(219	)		292
Contribution from parent		—			—			838
Return of capital to parent		(150	)		—			(20	)
Other		(5	)		(7	)		—
Net cash provided by (used in) financing activities		80			(264	)		(653	)
Net increase (decrease) in cash, restricted cash and equivalents		49			1			(373	)
Cash, restricted cash and equivalents at beginning of period(1)		5			4			377
Cash, restricted cash and equivalents at end of period(1)	$	54		$	5		$	4
Supplemental Cash Flow Information
Cash for:
Interest paid (net of capitalized interest of $3, $5 and $5)		175			176			220
Income taxes paid		16			—			13
Income taxes received		—			220			—
Noncash investing and financing activities:(2)
Accrued construction expenditures		110			48			120
Leases(3)		—			3			12
Contributed capital		149			322			1

(1)   Includes $24 million of restricted cash for the year ended December 31, 2021. For the years ended December 31, 2020 and 2019 there were no restricted cash and equivalent balances.

(2)   See Note 2 for noncash investing and financing activities related to the adoption of a new accounting standard for leasing arrangements. See Note 5 for noncash financing activities related to capital contributions associated with the settlement of litigation. See Note 12 for noncash investing activities related to the property, plant and equipment conveyed to satisfy litigation.

(3)   Includes $3 million and $4 million of financing leases entered into during the years ended December 31, 2020 and 2019, respectively, and $8 million of operating leases entered into during the year ended December 31, 2019.

See Notes to Consolidated Financial Statements.

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Dominion Energy South Carolina, Inc.

Consolidated Statements of Changes in Common Equity

	Common Stock
(millions)	Shares		Amount			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interest			Total Equity
December 31, 2018		40	$	2,860		$	1,279		$	(3	)	$	179		$	4,315
Cumulative-effect of change in    accounting principle							1			(1	)					—
Total comprehensive income (loss)    available (attributable) to common    shareholder							(1,240	)		1			18			(1,221	)
Capital contribution from parent			835										3			838
Capital contribution returned to parent													(20	)		(20	)
Dividend to parent							(20	)								(20	)
December 31, 2019		40		3,695			20			(3	)		180			3,892
Total comprehensive income    available to common shareholder							295			1			12			308
Capital contribution from parent			322													322
Dividend to parent							(38	)								(38	)
December 31, 2020		40		4,017			277			(2	)		192			4,484
Total comprehensive income    available to common shareholder							208			1			21			230
Capital contribution from parent				149												149
Return of capital to parent				(150	)											(150	)
Dividend to parent							(150	)					(38	)		(188	)
December 31, 2021		40	$	4,016		$	335		$	(1	)	$	175		$	4,525

See Notes to Consolidated Financial Statements.

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Dominion Energy South Carolina, Inc.

Notes to Consolidated Financial Statements

1.  NATURE OF OPERATIONS

DESC is a wholly-owned subsidiary of SCANA, which is a wholly-owned subsidiary of Dominion Energy.

DESC is engaged in the generation, transmission and distribution of electricity in the central, southern and southwestern portions of South Carolina. Additionally, DESC distributes natural gas to residential, commercial and industrial customers in South Carolina.

DESC manages its daily operations through one primary operating segment: Dominion Energy South Carolina. 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.

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

DESC makes certain estimates and assumptions in preparing its Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues, expenses and cash flows for the periods presented. Actual results may differ from those estimates.

DESC’s Consolidated Financial Statements include, after eliminating intercompany balances and transactions, the accounts of DESC, GENCO and Fuel Company. DESC has concluded that GENCO and Fuel Company are VIEs due to the members lacking the characteristics of a controlling financial interest. DESC is the primary beneficiary of GENCO and Fuel Company and therefore is required to consolidate the VIEs. The equity interests in GENCO and Fuel Company are held solely by SCANA, DESC’s parent. As a result, GENCO and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in the Consolidated Financial Statements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold exclusively to DESC, pursuant to a FERC approved power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Fuel Company acquires, owns and provides financing for DESC's nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 6.

Additionally, effective January 2021, DESC purchases shared services from DES, an affiliated VIE that provides accounting, legal, finance and certain administrative and technical services to all Dominion Energy subsidiaries, including DESC. DESC previously purchased such services from DESS, an affiliated VIE, that had provided such services to all SCANA subsidiaries. DESC has determined that it is not the primary beneficiary of DES as it does not have either the power to direct the activities that most significantly impact its economic performance or an obligation to absorb losses and benefits which could be significant to it. See Note 16 for amounts attributable to affiliates.

DESC reports certain contracts and instruments at fair value. See Note 9 for further information on fair value measurements.

DESC maintains pension and other postretirement benefit plans. See Note 11 for further information on these plans.

Certain amounts in the 2020 and 2019 Consolidated Financial Statements and Notes have been reclassified to conform to the 2021 presentation for comparative purposes; however, such reclassifications did not affect DESC’s net income, total assets, liabilities, equity or cash flows. Effective in the second quarter of 2021, DESC updated its Statements of Cash Flows to present net charges for allowance for credit risk and write-offs of accounts receivables within other adjustments to reconcile net income to net cash provided by operating activities from the previous presentation within changes in accounts receivable. All prior period information has been conformed to this presentation, which does not result in a change to net cash provided by operating activities.

Utility Plant

Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFUDC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense.

AFUDC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFUDC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. DESC calculated AFUDC using average composite rates of 2.6%, 2.6% and 4.3% for 2021, 2020 and 2019, respectively. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. DESC capitalizes interest on nuclear fuel in process at the actual interest cost incurred.

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For property subject to cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from utility plant-in-service when it becomes probable it will be abandoned and recorded as a regulatory asset for amounts expected to be collected through future rates.

Provisions for depreciation and amortization are recorded using the straight-line method based on the estimated service lives of the various classes of property, and in most cases, include provisions for future cost of removal. The composite weighted average depreciation rates for utility plant by function were as follows:

	2021(1)			2020
Generation		2.46	%		2.50	%
Transmission		2.56	%		2.56	%
Distribution		2.48	%		2.42	%
Storage		2.85	%		2.75	%
General and other		2.27	%		3.17	%

(1) Rates include the impact of a change in depreciation rates approved in connection with the settlement of the electric base rate case, which resulted in a decrease to depreciation expense of $6 million and an expected annual decrease of $12 million.

DESC records nuclear fuel amortization using the units-of-production method, which is included in fuel used in electric generation and recovered through the fuel cost component of retail electric rates.

Major Maintenance

Planned major maintenance costs related to certain fossil fuel turbine generator equipment, nuclear refueling outages and cyclical tree trimming and vegetation management are collected in rates and accrued in periods other than when incurred in accordance with approval by the South Carolina Commission for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred.

Effective September 2021, DESC is authorized to collect $25 million annually through electric rates to offset certain turbine generator maintenance expenditures. Prior to September 2021, DESC was authorized to collect $18 million annually. For the years ended December 31, 2021 and 2020, DESC incurred $20 million and $19 million, respectively, for turbine generator maintenance.

Nuclear refueling outages are scheduled 18 months apart. As approved by the South Carolina Commission, DESC accrues $17 million annually for its portion of the nuclear refueling outages, that are scheduled to occur from the fall of 2021 through the fall of 2027 as well as unrecovered balances from the previous accrual cycle. Refueling outage costs incurred for which DESC was responsible totaled $24 million in 2021 and $23 million in 2020.

Effective September 2021, DESC implemented a tree trimming and vegetation management accrual where costs associated with cyclical tree trimming and vegetation management are accrued over the five-year operating cycle DESC seeks to maintain for such activities. As approved by the South Carolina Commission, DESC accrues $28 million annually. In 2021, DESC accrued $9 million during the period the accrual was effective and incurred costs totaling $9 million.  

Asset Retirement Obligations

DESC recognizes AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. Periodically, DESC assesses its AROs to determine if circumstances indicate that estimates of the amounts or timing of future cash flows associated with retirement activities have changed. AROs are adjusted when significant changes in the amounts or timing of future cash flows are identified. DESC reports accretion of AROs and depreciation on asset retirement costs as an adjustment to regulatory assets. 

Nuclear Decommissioning

Based on a decommissioning cost study completed in 2020, DESC’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $764 million, stated in 2021 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.

Under DESC’s method of funding decommissioning costs, DESC transfers to an external trust fund the amounts collected through rates ($3 million in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. The asset balance held in trust reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer on an after-tax basis.

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Cash, Restricted Cash and Equivalents

Cash, restricted cash and equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Restricted Cash and Equivalents

Beginning in 2021, DESC holds restricted cash and equivalent balances that consists of federal assistance funds to be used towards customer bill assistance.

The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within DESC’s Consolidated Balance Sheets to the corresponding amounts reported within DESC’s Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019:

	Cash, Restricted Cash and Equivalents at End/Beginning of Year
	December 31, 2021		December 31, 2020		December 31, 2019		December 31, 2018
(millions)
Cash and cash equivalents	$	30	$	5	$	4	$	377
Restricted cash and equivalents(1)		24		—		—		—
Cash, restricted cash and equivalents shown in the    Consolidated Statements of Cash Flows	$	54	$	5	$	4	$	377

(1) At December 31 2020, 2019 and 2018 there were no restricted cash and equivalent balances.

Receivables

Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described in Note 4. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $139 million and $156 million at December 31, 2021 and 2020, respectively.

DESC sells electricity and natural gas and provides distribution and transmission services to customers in South Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of DESC’s customer base, which includes a large number of residential, commercial and industrial customers. Credit risk associated with accounts receivable is limited due to the large number of customers. DESC’s exposure to potential concentrations of credit risk results primarily from amounts due from Santee Cooper related to the jointly owned nuclear generating facility at Summer. Such receivables represented approximately 6% of DESC’s accounts receivable balance at December 31, 2021.

Inventories

Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the South Carolina Commission.

Income Taxes

A consolidated federal income tax return is filed for Dominion Energy and its subsidiaries, including DESC. In addition, where applicable, combined income tax returns for Dominion Energy, including DESC, are filed in various states including South Carolina; otherwise, separate state income tax returns are filed.

DESC participates in an intercompany tax sharing agreement with Dominion Energy. Current income taxes are based on taxable income or loss and credits determined on a separate company basis.

Under the agreements, if a subsidiary incurs a tax loss or earns a credit, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or credit or to the extent the tax loss or credit is absorbed by the taxable income of other Dominion Energy consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax asset until realized.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. DESC establishes a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. DESC did not have any valuation allowances recorded for the periods presented. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

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DESC recognizes positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2021, DESC had $62 million of unrecognized tax benefits.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the Consolidated Balance Sheets and current payables are included in taxes accrued on the Consolidated Balance Sheets.

DESC recognizes interest on underpayments and overpayments of income taxes in interest expense and interest income, respectively. Penalties are also recognized in other expenses.

In 2021, DESC reflected a $21 million benefit in interest expense associated with the effective settlement of uncertain tax positions.  Interest expense for DESC was $7 million in 2020 and $18 million in 2019. Interest income for DESC was less than $1 million in both 2021 and 2020 and $2 million in 2019. In 2021, DESC recognized a $7 million benefit from the reversal of penalty expenses associated with the effective settlement of uncertain tax positions.  DESC recorded penalty expenses of $4 million in 2020 and $7 million in 2019.

At December 31, 2021, DESC had an income tax-related affiliated receivable of $24 million from Dominion Energy. This balance is expected to be received from Dominion Energy.

At December 31, 2020, DESC had an income tax-related affiliated payable of $31 million to Dominion Energy. This balance was paid to Dominion Energy in 2021.

At DESC investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.

Regulatory Assets and Liabilities

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

DESC evaluates whether or not recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on:

• Orders issued by regulatory commissions, legislation and judicial actions;

• Past experience; and

• Discussions with applicable regulatory authorities and legal counsel.

Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. See Notes 3 to the Consolidated Financial Statements for additional information.

Derivative Instruments

DESC is exposed to the impact of market fluctuations in the price of electricity and natural gas it markets and purchases, as well as interest rate risk in its business operations. DESC uses derivative instruments such as physical forwards and swaps to manage commodity and/or interest rate risks of its business operations.

All derivatives, except those for which an exception applies, are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions are reported as derivative assets. Derivative contracts representing unrealized losses are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance. See Note 9 for further information about fair value measurements and associated valuation methods for derivatives.

DESC does not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. DESC had margin assets of $11 million and $17 million associated with cash collateral at December 31, 2021 and 2020, respectively. DESC had no margin liabilities associated with cash collateral at December 31, 2021 and 2020. See Note 8 for further information about derivatives.

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To manage price and interest rate risk, DESC holds derivative instruments that are not designated as hedges for accounting purposes. However, to the extent DESC does not hold offsetting position for such derivatives, it believes these instruments represent economic hedges that mitigate its exposure to fluctuations in commodity prices or interest rates. All income statement activity, including amounts realized upon settlement, is presented in operating expenses and interest charges based on the nature of the underlying risk.

Changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings. All income statement activity, including amounts realized upon settlement, is presented in operating expenses and interest charges based on the nature of the underlying risk.

DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS

In accordance with accounting guidance pertaining to derivatives and hedge accounting, DESC designates a portion of their derivative instruments as cash flow hedges for accounting purposes. For derivative instruments that are accounted for as cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.

Cash Flow Hedges- DESC uses interest rate swaps to hedge its exposure to variable interest rates on long-term debt. For transactions in which DESC is hedging the variability of cash flows, changes in the fair value of the derivatives are reported in regulatory assets or liabilities. Any derivative gains or losses reported in regulatory assets or liabilities are reclassified to earnings when the forecasted item is included in earnings. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Pursuant to regulatory orders, interest rate derivatives entered into by DESC after October 2013 were not designated for accounting purposes as cash flow hedges, and fair value changes and settlement amounts related to them have been recorded as regulatory assets and liabilities. Settlement losses on swaps generally have been amortized over the lives of subsequent debt issuances, and gains have been amortized to interest charges or have been applied as otherwise directed by the South Carolina Commission.

Debt Issuance Costs

DESC defers and amortizes debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as a reduction in long-term debt in the Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest charges. As permitted by regulatory authorities, gains or losses resulting from the refinancing or redemption of debt that are probable of recovery through future rates are deferred and amortized.

Environmental

An environmental assessment program is maintained to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred.

Statement of Operations Presentation

Revenues and expenses arising from regulated businesses are presented within Operating Income (Loss), and all other activities are presented within Other Expense, net.

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered, or contracts settled and includes amounts yet to be billed to customers. DESC collects sales, consumption, consumer utility taxes and sales taxes; however, these amounts are excluded from revenue and are recorded as liabilities until they are remitted to the respective taxing authority.

The primary types of sales and service activities reported as operating revenue for DESC are as follows:

Revenue from Contracts with Customers

• Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

• Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services; and

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• Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities.

Other Revenue

• Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

DESC records refunds to customers as required by the South Carolina Commission as a reduction to regulated electric sales or regulated gas sales, as applicable. Revenues from electric and gas sales are recognized over time, as the customers of DESC consume gas and electricity as it is delivered. Sales of products and services typically transfer control and are recognized as revenue upon delivery of the product or service. The customer is able to direct the use of, and obtain substantially all of the benefits from, the product at the time the product is delivered. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. Payment for most sales and services varies by contract type, but is typically due within a month of billing.

DESC customers subject to an electric fuel cost recovery component or a PGA are billed based on a fuel or cost of gas factor calculated in accordance with cost recovery procedures approved by the South Carolina Commission and subject to adjustment periodically. Any difference between actual costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost recovery factors.

Certain amounts deferred for the WNA arise under specific arrangements with regulators rather than customers and are accounted for as an alternative revenue program. This alternative revenue is included within Other operating revenues, separate from revenue arising from contracts with customers, in the month such adjustments are deferred within regulatory accounts. As permitted, DESC has elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues.

Performance obligations which have not been satisfied by DESC relate primarily to demand or standby service for natural gas. Demand or standby charges for natural gas arise when an industrial customer reserves capacity on assets controlled by the service provider and may use that capacity to move natural gas it has acquired from other suppliers. For all periods presented, the amount of revenue recognized by DESC for these charges is equal to the amount of consideration DESC has a right to invoice and corresponds directly to the value transferred to the customer.

Leases

DESC leases certain assets including vehicles, real estate, office equipment and other assets under both operating and finance leases. For operating leases, rent expense is recognized on a straight-line basis over the term of the lease agreement, subject to regulatory framework. Rent expense associated with operating leases, short-term leases and variable leases is primarily recorded in other operations and maintenance expense in the Consolidated Statements of Comprehensive Income (Loss). Amortization expense and interest charges associated with finance leases are deferred within regulatory assets in the Consolidated Balance Sheets and amortized into the Consolidated Statements of Comprehensive Income (Loss).

Certain leases include one or more options to renew, with renewal terms that can extend the lease from one to 70 years. The exercise of renewal options is solely at DESC's discretion and is included in the lease term if the option is reasonably certain to be exercised. A right-of-use asset and corresponding lease liability for leases with original lease terms of one year or less are not included in the Consolidated Balance Sheets, unless such leases contain renewal options that DESC is reasonably certain will be exercised.

The determination of the discount rate utilized has a significant impact on the calculation of the present value of the lease liability included in the Consolidated Balance Sheets. For DESC’s leased assets, the discount rate implicit in the lease is generally unable to be determined from a lessee perspective. As such, DESC uses internally-developed incremental borrowing rates as a discount rate in the calculation of the present value of the lease liability. The incremental borrowing rates are determined based on an analysis of DESC's publicly available secured borrowing rates over various lengths of time that most closely corresponds to DESC's lease maturities.

New Accounting Standards

LEASES

In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases classified as operating leases, while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.

The guidance became effective for DESC's interim and annual reporting periods beginning January 1, 2019. DESC adopted this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. DESC applied the practical expedients, which required no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no evaluation of existing or expired land easements that were not previously accounted for as leases. In connection with the adoption of this revised accounting guidance, DESC recorded

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$19 million of offsetting right-of-use assets and liabilities for operating leases in effect at the adoption date. See Note 13 for additional information.

TAX REFORM

In February 2018, the FASB issued revised accounting guidance to provide clarification on the application of the 2017 Tax Reform Act for balances recorded within AOCI. The revised guidance provides for stranded amounts within AOCI from the impacts of the 2017 Tax Reform Act to be reclassified to retained earnings. DESC adopted this guidance for interim and annual reporting periods beginning January 1, 2019 on a prospective basis. In connection with the adoption of this guidance, DESC reclassified a benefit of $1 million from AOCI to retained earnings. The amounts reclassified reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of DESC’s AOCI.

3.  RATE AND OTHER REGULATORY MATTERS

Regulatory Matters Involving Potential Loss Contingencies

As a result of issues generated in the ordinary course of business, DESC is involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for DESC to estimate a range of possible loss. For regulatory matters that DESC cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that DESC is able to estimate a range of possible loss. For regulatory matters that DESC is able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent DESC’s maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on DESC’s financial position, liquidity or results of operations.

FERC

In June 2019, DESC submitted the 2015 Task Order as a stand-alone rate schedule, which governs DESC’s provision of retail service to the DOE at the Savannah River Site. The 2015 Task Order also includes provisions that govern the operations and maintenance of certain transmission facilities, which DESC had determined to be services that are likely subject to FERC’s jurisdiction. DESC requested that FERC accept the 2015 Task Order for filing to become effective in August 2019 and accept the refund analysis included in the filing for amounts collected under the 2015 Task Order as well as under two prior task orders commencing in 1995 and each covering ten-year periods. During the second quarter of 2019, DESC recorded a $6 million ($4 million after-tax) charge primarily within interest charges in DESC’s Consolidated Statements of Comprehensive Income (Loss). In August 2019, DESC submitted a motion to withdraw the 2015 Task Order filing and related refund analysis as requested by FERC staff. As a result, DESC recorded a $10 million ($7 million after-tax) benefit, primarily within interest charges in DESC’s Consolidated Statements of Comprehensive Income (Loss) during the third quarter of 2019, to remove previously recorded reserves.

2017 Tax Reform Act

DESC’s provision of electric transmission service is pursuant to a FERC approved formula rate. In December 2019, FERC issued an order requiring transmission providers with transmission formula rates to account for the impacts of the 2017 Tax Reform Act on rates charged to customers. The order requires companies to include a mechanism to decrease or increase their income tax allowances to account for the 2017 Tax Reform Act and any other future changes in tax law, and to submit annual information reflecting the amortization of these excess deferred income taxes. DESC submitted a proposed update to its formula rate to FERC in May 2020. This matter is pending.

Other Regulatory Matters

South Carolina Electric Base Rate Case

In August 2020, DESC filed its retail electric base rate case and schedules with the South Carolina Commission. DESC proposed a non-fuel, base rate increase of $178 million, or 7.75% based on an adjusted test year data, effective on or after the first billing cycle of March 2021. The base rate increase was proposed to recover the significant investment in assets and operating resources required to serve an expanding customer base, maintain the safety, reliability and efficiency of DESC’s system and meet increasingly stringent reliability, security and environmental requirements for the benefit of South Carolina customers.  DESC presented an earned ROE of 5.90% based upon a fully-adjusted test period. The proposed rates would provide for an earned ROE equal to the current authorized earned ROE of 10.25% established in the previous rate case in 2012.  In January 2021, the South Carolina Commission approved a proposal made by the South Carolina Office of Regulatory Staff, and agreed to by DESC and other intervenors, to stay the base rate case due to the current economic conditions and to allow the parties more time to negotiate a settlement with a final order to be issued no later than August 2021.

In July 2021, DESC, the South Carolina Office of Regulatory Staff and other parties of record filed a comprehensive settlement agreement with the South Carolina Commission for approval. The comprehensive settlement agreement provides for a non-fuel, base rate increase of $62 million (resulting in a net increase of $36 million after considering an accelerated amortization of certain excess deferred income taxes) commencing with bills issued on September 1, 2021 and an authorized earned ROE of 9.50%. Additionally, DESC has agreed to commit up to $15 million to forgive retail electric customer balances that were more than 60 days past due as of May 31, 2021, and provide $15 million for energy efficiency upgrades and critical health and safety repairs to customer homes. Pursuant to the comprehensive settlement agreement, DESC would not file a retail electric base rate case prior to July 1, 2023, such that new rates would not be effective prior to January 1, 2024, absent unforeseen extraordinary economic or financial conditions that

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may include changes in corporate tax rates. In July 2021, the South Carolina Commission voted to approve the comprehensive settlement agreement and issued its final order in August 2021.

In connection with this matter, DESC recorded charges of $249 million ($187 million after-tax) reflected within impairment of assets and other charges, including $237 million of regulatory assets associated with DESC’s purchases of its first mortgage bonds during 2019 that are no longer probable of recovery under the settlement agreement, and $18 million ($14 million after-tax) reflected within other income in its Consolidated Statements of Income for the year ended December 31, 2021.

Electric – Cost of Fuel

DESC’s retail electric rates include a cost of fuel component approved by the South Carolina Commission which may be adjusted periodically to reflect changes in the price of fuel purchased by DESC.

In February 2021, DESC filed with the South Carolina Commission a proposal to increase the total fuel cost component of retail electric rates. DESC’s proposed adjustment would increase annual base fuel component recoveries by approximately $36 million and is designed to recover DESC’s current base fuel costs, net of the existing over-collected balance, over the 12-month period beginning with the first billing cycle of May 2021. In addition, DESC proposed a decrease to its variable environmental component and an increase to its distributed energy resource component. In April 2021, the South Carolina Commission approved the filing.

In February 2022, DESC filed with the South Carolina Commission a proposal to increase the total fuel cost component of retail electric rates. DESC’s proposed adjustment is designed to recover DESC’s current base fuel costs, including its existing under-collected balance, over the 12-month period beginning with the first billing cycle of May 2022. DESC also proposed to apply $66 million representing the net balance of funds associated with the monetization of the bankruptcy settlement with Toshiba Corporation following the satisfaction of liens against NND Project property recorded in regulatory liabilities, as a reduction to its under-collected base fuel cost balance. In addition, DESC proposed an increase to its variable environmental and avoided capacity cost component. The net effect is a proposed annual increase of $143 million. This matter is pending.

Electric – Other

DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2021, DESC filed an application with the South Carolina Commission seeking approval to recover $48 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. In April 2021, the South Carolina Commission approved the filing. In connection with the approval of the comprehensive settlement agreement in the South Carolina base rate case discussed above, the net lost revenue component of the DSM rider was adjusted resulting in a recovery of $43 million commencing with bills issued on September 1, 2021.

In January 2022, DESC filed an application with the South Carolina Commission seeking approval to recover $60 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. This matter is pending.

DESC utilizes a pension costs rider approved by the South Carolina Commission which is designed to allow recovery of projected pension costs, including under-collected balances or net of over-collected balances, as applicable. The rider is typically reviewed for adjustment every 12 months with any resulting increase or decrease going into effect beginning with the first billing cycle in May. In February 2021, DESC requested that the South Carolina Commission approve an adjustment to this rider to decrease annual revenue by less than $1 million. In April 2021, the South Carolina Commission approved the filing. In February 2022, DESC requested that the South Carolina Commission approve an adjustment to this rider to decrease annual revenue by $12 million. This matter is pending.

Natural Gas Rates

In June 2021, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 2021 with a total revenue requirement of $426 million. This represents a $9 million overall annual increase to its natural gas rates under the terms of the RSA effective with the first billing cycle of November 2021. In October 2021, the South Carolina Commission issued an order approving a total revenue requirement of $424 million effective with the first billing cycle of November 2021. This represents a $7 million overall annual increase to DESC’s natural gas rates.

In November 2021, DESC filed an application with the South Carolina Commission seeking approval to create DSM programs for DESC's residential and commercial natural gas customers and a new rider to retail gas rates for the recovery of the associated program costs and a shared savings incentive of 9.9%. The application also includes a notice of intent that DESC would seek to recover the net lost revenues resulting from the proposed DSM programs through the annual RSA proceeding. This matter is pending.

DESC's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. DESC’s gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the South Carolina Commission.

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Regulatory Assets and Regulatory Liabilities

Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises. As a result, DESC has recorded regulatory assets and regulatory liabilities which are summarized in the following table. Except for NND Project costs and certain other unrecovered plant costs, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

At December 31,	2021		2020
(millions)
Regulatory assets:
NND Project costs(1)	$	138		138
Deferred employee benefit plan costs(2)		8		9
Other unrecovered plant(3)		16		14
DSM programs(4)		23		29
AROs(5)		2		2
Cost of fuel and purchased gas under-collections(6)		126		1
Other		48		36
Regulatory assets - current		361		229
NND Project costs(1)		2,226		2,364
AROs(5)		311		309
Cost of reacquired debt(7)		10		243
Deferred employee benefit plan costs(2)		106		159
Deferred losses on interest rate derivatives(8)		295		308
Other unrecovered plant(3)		57		61
DSM programs(4)		45		46
Environmental remediation costs(9)		30		20
Deferred storm damage costs(10)		38		45
Deferred transmission operating costs(11)		77		63
Other(12)		128		108
Regulatory assets - noncurrent		3,323		3,726
Total regulatory assets	$	3,684	$	3,955
Regulatory liabilities:
Monetization of guaranty settlement(13)	$	67		67
Income taxes refundable through future rates(14)		42		21
Reserve for refunds to electric utility customers(15)		113		128
Cost of fuel and purchased gas over-collections(6)		—		58
Derivatives(16)		18		—
Other		5		9
Regulatory liabilities - current		245		283
Monetization of guaranty settlement(13)		831		903
Income taxes refundable through future rates(14)		903		919
Asset removal costs(17)		570		564
Deferred gains on interest rate derivatives(8)		67		69
Reserve for refunds to electric utility customers(15)		425		540
Derivatives(16)		131		—
Other		9		10
Regulatory liabilities - noncurrent		2,936		3,005
Total regulatory liabilities	$	3,181	$	3,288

(1) Reflects expenditures associated with the NND Project, which pursuant to the SCANA Merger Approval Order, will be recovered from electric service customers over a 20-year period ending in 2039. See Note 12 for more information.

(2) Employee benefit plan costs have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific South Carolina Commission regulatory orders. DESC expects to recover deferred pension costs through utility rates over periods through 2044. DESC expects to recover other deferred benefit costs through utility rates, primarily over average service periods of participating employees up to 11 years.

(3) Represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. DESC is amortizing these amounts through cost of service rates following depreciation amounts that were designed to recover the retired units cost over their previous estimated remaining useful lives, which has been estimated to be through 2025. Based on current projections of remaining decommissioning costs, projected recovery is expected to extend through 2029. In addition, amounts include unrecovered costs of existing meters and equipment retired from service prior to being fully depreciated as part of the Advanced Metering Infrastructure project, which are being recovered through rates through 2028. This amount also includes certain inventory and preliminary survey and investigation charges being amortized over five years related to the transition or conversion from coal to gas fired generation at certain facilities. Unamortized amounts are included in rate base and are earning a current return.

(4) Represents deferred costs associated with electric demand reduction programs, and such deferred costs are currently being recovered over three years through an approved rate rider.

(5) Represents deferred depreciation and accretion expense related to legal obligations associated with the future retirement of generation, transmission and distribution properties. The AROs primarily relate to DESC’s electric generating facilities, including Summer, and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 105 years.

(6) Represents amounts under- or over-collected from customers pursuant to the cost of fuel components approved by the South Carolina Commission.

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(7) In 2021, DESC recorded a charge of $237 million ($178 million after-tax) in impairment of assets and other charges, reflected in the Corporate and Other segment, to write-off the balance of a regulatory asset that is no longer probable of recovery under the settlement agreement approved in DESC’s retail electric base rate case. See South Carolina Electric Base Rate Case discussed above for more information.

(8) Represents (i) the changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043.The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065.

(9) Reflects amounts associated with the assessment and clean-up of sites currently or formerly owned by DESC. Such remediation costs are expected to be recovered over periods of up to 22 years. See Note 12 for more information.

(10) Represents storm restoration costs for which DESC expects to receive future recovery through customer rates over approximately 10 years pursuant to the settlement agreement approved in DESC’s retail electric base rate case. Unamortized amounts are included in rate base and are earning a current return.

(11) Includes deferred depreciation and property taxes associated with certain transmission assets for which DESC expects recovery from customers through future rates over approximately 42 years pursuant to the settlement agreement approved in DESC’s retail electric base rate case. Unamortized amounts are included in rate base and earning a current return. See Note 12 for more information.

(12) Various other regulatory assets are expected to be recovered through rates over varying periods through 2047.

(13) Represents proceeds related to the monetization of the Toshiba Settlement. In accordance with the SCANA Merger Approval Order, this balance, net of amounts that may be required to satisfy liens, will be refunded to electric customers over a 20-year period ending in 2039. See Note 12 for more information.

(14) Includes (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the 2017 Tax Reform Act (certain of which are protected under normalization rules and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over prescribed periods as instructed by regulators) and (ii) deferred income taxes arising from investment tax credits, offset by (iii) deferred income taxes that arise from utility operations that have not been included in customer rates (a portion of which relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to 85 years). See Note 7 for more information.

(15) Reflects amounts previously collected from retail electric customers of DESC for the NND Project to be credited to customers over an estimated 11-year period effective February 2019 in connection with the SCANA Merger Approval Order. See Note 12 for more information.

(16) For jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

(17) Represents estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.

Regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under GAAP for regulated operations. The South Carolina Commission or the FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by one of these regulatory agencies, including deferred transmission operating costs that are the subject of regulatory proceedings as discussed in Note 12. While such costs are not currently being recovered, management believes that they would be allowable under existing rate-making concepts embodied in rate orders or applicable state law and expects to recover these costs through rates in future periods.

4.  OPERATING REVENUE

DESC’s operating revenue consists of the following:

Year Ended December 31,	2021				2020
(millions)	Electric		Gas		Electric		Gas
Customer class:
Residential	$	1,211	$	245	$	1,127	$	201
Commercial		834		133		746		103
Industrial		424		103		341		65
Other		157		25		123		18
Revenues from contracts with customers		2,626		506		2,337		387
Other revenues		13		1		15		—
Total Operating Revenues	$	2,639	$	507	$	2,352	$	387

Contract liabilities represent the obligation to transfer goods or services to a customer for which consideration has already been received from the customer. DESC had contract liability balances of $8 million and $5 million at December 31, 2021 and 2020, respectively. For the years ended December 31, 2021 and 2020, DESC recognized revenue of $4 million and $6 million, respectively, from the beginning contract liability balances as DESC fulfilled its obligations to provide service to its customers. Contract liabilities are recorded in customer deposits and customer prepayments in the Consolidated Balance Sheets.

Contract Costs

Costs to obtain contracts are generally expensed when incurred. In limited instances, DESC provides economic development grants intended to support economic growth within DESC’s electric service territory and defers such grants as regulatory assets on the Consolidated Balance Sheets. Whenever these grants are contingent on a customer entering into a long-term electric supply contract with DESC, they are considered costs to obtain that underlying contract. Such costs that exceed certain thresholds are deferred and amortized on a straight-line basis over the term of the related service contract, which generally ranges from ten to 15 years.

Balances and activity related to contract costs deferred as regulatory assets were as follows:

	Regulatory Assets
(millions)	2021			2020
Beginning balance, January 1	$	12		$	13
Amortization		(1	)		(1	)
Ending balance, December 31	$	11		$	12

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5.  EQUITY

For all periods presented, DESC's authorized shares of common stock, no par value, were 50 million, of which 40.3 million were issued and outstanding, and DESC's authorized shares of preferred stock, no par value, were 20 million, of which 1,000 shares were issued and outstanding. All outstanding shares of common and preferred stock are held by SCANA.

In 2021, Dominion Energy issued $104 million of shares of Dominion Energy common stock to satisfy DESC’s obligation under a settlement agreement for the FILOT litigation discussed in Note 12. Additionally, in 2021, Dominion Energy issued $45 million of shares of Dominion Energy common stock to satisfy DESC’s obligation for the initial payment under a settlement agreement with the SCDOR discussed in Note 12. In connection with these transactions, DESC recorded equity contributions from Dominion Energy.

In 2021, DESC returned $150 million of capital previously contributed from SCANA which had been funded by Dominion Energy.

In 2020, Dominion Energy issued $322 million of shares of Dominion Energy common stock in accordance with the settlement agreement associated with the Santee Cooper Ratepayer Case, as discussed in Note 12. In connection with this transaction, DESC recorded an equity contribution from Dominion Energy.

In 2019, DESC received equity contributions of $835 million from SCANA which were funded by Dominion Energy. DESC primarily used these funds to redeem long-term debt and to repay intercompany credit agreement borrowings from Dominion Energy. See Note 6.

DESC’s bond indenture under which it issues first mortgage bonds contains provisions that could limit the payment of cash dividends on its common stock. DESC's bond indenture permits the payment of dividends on DESC's common stock only either (1) out of its Surplus (as defined in the bond indenture) or (2) in case there is no Surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, pursuant to the SCANA Merger Approval Order, the amount of any DESC dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry.

At December 31, 2021, DESC’s retained earnings exceed the balance established by the Federal Power Act as a reserve on earnings attributable to hydroelectric generation plants. As a result, DESC is permitted to pay dividends without additional regulatory approval provided that such amounts would not bring the retained earnings balance below the established threshold.

6.  LONG-TERM AND SHORT-TERM DEBT

Long-term debt by type with related weighted-average coupon rates and maturities at December 31, 2021 and 2020 is as follows:

At December 31,	2021 Weighted- average Coupon(1)			2021			2020
(millions, except percentages)
DESC:
First Mortgage Bonds, 2.30% to 6.625%, due 2021 to 2065		5.09	%	$	3,634		$	3,267
Tax-Exempt Financings:(2)
Variable rate due 2038		0.14	%		35			35
3.625% and 4.00%, due 2028 and 2033		3.90	%		54			54
Other		3.65	%		1			1
GENCO:
Tax-Exempt Financing, variable rate due 2038		0.14	%		33			33
Affiliated note, 3.05% due 2024		3.05	%		230			230
Total principal					3,987			3,620
Securities due within one year					—			(33	)
Unamortized discount, premium and debt issuance costs, net					(33	)		(30	)
Finance leases					10			15
Total long-term debt				$	3,964		$	3,572

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2021.

(2) Industrial revenue bonds totaling $68 million are secured by letters of credit that expire, subject to renewal, in the fourth quarter of 2022.

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Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2021, were as follows:

(millions, except percentages)	2022		2023		2024			2025		2026		Thereafter			Total
First Mortgage Bonds	$	—	$	—	$	—		$	—	$	—	$	3,634		$	3,634
Tax-Exempt Financings		—		—		—			—		—		122			122
Other		—		—		230			—		—		1			231
Total	$	—	$	—	$	230		$	—	$	—	$	3,757		$	3,987
Weighted-average coupon						3.05	%						4.99	%

Substantially all of DESC’s electric utility plant is pledged as collateral in connection with long-term debt.

DESC is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice the annual interest requirements on all outstanding Bonds and Bonds to be issued (Bond Ratio). For the year ended December 31, 2021, the Bond Ratio was approximately 6.

Long-Term Debt – Affiliate

In May 2019, GENCO issued a $230 million 3.05% promissory note due to Dominion Energy that matures in May 2024. The issuance by GENCO was approved by the South Carolina Commission. Proceeds from the issuance were used to redeem GENCO’s 5.49% senior secured notes due in 2024 at the remaining principal outstanding of $33 million plus accrued interest, repay money pool borrowings and to return $20 million of contributed equity capital to SCANA.

Short-Term Debt

DESC's short-term financing is supported through its access as co-borrower to Dominion Energy’s $6.0 billion joint revolving credit facility, which can be used for working capital, as support for the combined commercial paper programs of DESC, Dominion Energy, Virginia Power and Questar Gas, and for other general corporate purposes.

DESC's share of commercial paper and letters of credit outstanding under its joint credit facility with Dominion Energy, were as follows:

(millions)	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit
At December 31, 2021
Joint revolving credit facility(1)	$	1,000	$	—	$	—
At December 31, 2020
Joint revolving credit facility(1)	$	1,000	$	—	$	—

(1) A maximum of $1.0 billion of the facility is available to DESC, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. A sub-limit for DESC is set within the facility limit but can be changed at the option of the co-borrowers multiple times per year. At December 31, 2021, the sub-limit for DESC was $500 million. If DESC has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term borrowings from DESC's parent or from Dominion Energy. This credit facility matures in June 2026, with the potential to be extended by the borrowers to June 2028. The credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.0 billion (or the sub-limit, whichever is less) of letters of credit.  

In January 2021, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization. In March 2021, FERC granted DESC authority through March 2023 to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act) in amounts not to exceed $2.2 billion outstanding with maturity dates of one year or less. In addition, in March 2021, FERC granted GENCO authority through March 2023 to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less.

DESC is obligated with respect to an aggregate of $68 million of industrial revenue bonds which are secured by letters of credit. These letters of credit expire, subject to renewal, in the fourth quarter of 2022.

DESC has FERC approval to enter into an inter-company credit agreement with Dominion Energy under which DESC may have short-term borrowings outstanding up to $900 million. At December 31, 2021 and 2020, DESC had borrowings outstanding under this credit agreement totaling $415 million and $149 million, respectively, which are recorded in affiliated and related party payables in DESC’s Consolidated Balance Sheets. For the twelve months ended December 31, 2021 and 2020, DESC recorded interest charges of less than $1 million and $7 million, respectively.

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Fuel Company and GENCO participated in a SCANA utility money pool until January 2021, when that utility money pool was closed. Money pool borrowings and investments bore interest at short-term market rates. For the years ended December 31, 2021 and 2020, DESC recorded interest income from money pool transactions of less than $1 million and $2 million, respectively, and for the same periods DESC recorded interest expense from money pool transactions of less than $1 million and $2 million, respectively. At December 31, 2020, DESC had outstanding money pool borrowings due to an affiliate of $206 million and investments due from an affiliate of $15 million. On its Consolidated Balance Sheets, DESC includes money pool borrowings within affiliated and related party payables and money pool investments within affiliated and related party receivables.

7.  INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. DESC is routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

As indicated in Note 2, DESC’s operations, including accounting for income taxes, are subject to regulatory accounting treatment. For regulated operations, many of the changes in deferred taxes represent amounts probable of collection from or refund to customers, and were recorded as either an increase to a regulatory asset or liability. See Note 3 for more information and current year developments.

Details of income tax expense for continuing operations including noncontrolling interests were as follows:

Year Ended December 31,	2021			2020			2019
(millions)
Current:
Federal	$	(52	)	$	(139	)	$	—
State		(39	)		3			34
Total current expense (benefit)		(91	)		(136	)		34
Deferred:
Federal
Taxes before operating loss carryforwards, investment tax credits and tax reform		61			158			(90	)
Tax utilization expense of operating loss carryforwards		34			33			102
State		7			17			(57	)
Total deferred expense (benefit)		102			208			(45	)
Investment tax credit-amortization		(2	)		(1	)		(1	)
Total income tax expense (benefit)	$	9		$	71		$	(12	)

Subsequent to the SCANA Combination, DESC’s annual utilization of its net operating losses are restricted by the tax law, however in certain circumstances the utilization may be increased if SCANA recognizes built-in gains on certain sales of assets. In December 2019, SCANA recognized a gain on the sale of SEMI’s assets to Dominion Energy, which increased the amount of DESC’s 2019 net operating loss utilization by approximately $79 million.

For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to DESC’s effective income tax rate as follows:

Year Ended December 31,	2021			2020			2019
U.S. statutory rate		21.0	%		21.0	%		21.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		5.6			4.2			3.9
AFUDC - equity		(0.4	)		(0.1	)		—
Amortization of federal investment tax credits		(0.6	)		(0.4	)		0.1
Production tax credits		—			—			0.4
Reversal of excess deferred income taxes		(8.1	)		(6.0	)		(1.4	)
NND Project impairment		—			—			(2.4	)
Write-off of regulatory asset		—			—			(15.8	)
Changes in unrecognized tax benefits		(15.8	)		—			(5.1	)
Prior period adjustments		1.6			—			—
Other		0.5			0.1			0.2
Effective tax rate		3.8	%		18.8	%		0.9	%

At DESC, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, which in some cases will be 35%. DESC has recorded an estimate of the portion of excess deferred income tax amortization in 2021, and changes in estimates of amounts probable of collection from or return to customers because of actions by our regulators. The reversal of these excess deferred income taxes will impact the effective tax rate, and rates charged to customers. See Note 3 for current year developments.

In December 2021, unrecognized tax benefits related to several state uncertain tax positions were effectively settled through negotiations with the taxing authority.  Management believed it was reasonably possible these unrecognized tax benefits could

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decrease through settlement negotiations or payments during 2021, however no income tax benefits could be recognized unless or until the positions were effectively settled.  Resolution of these uncertain tax positions decreased income tax expense by $38 million.

In connection with the SCANA Combination, Dominion Energy committed to forgo, or limit, the recovery of certain income tax-related regulatory assets associated with the NND Project. DESC’s effective tax rate reflects deferred income tax expense of $194 million in satisfaction of this commitment. In addition, DESC recorded deferred income tax expense of $30 million with a corresponding increase to regulatory liabilities by $40 million and deferred tax assets by $10 million related to adjustments of amounts probable of return to customers on the nuclear project.

DESC’s deferred income taxes consist of the following:

At December 31,	2021			2020
(millions)
Deferred income taxes:
Total deferred income tax assets	$	1,015		$	1,101
Total deferred income tax liabilities		1,974			1,941
Total net deferred income tax liabilities	$	959		$	840
Total deferred income taxes:
Depreciation method and plant basis differences	$	1,139		$	1,098
Excess deferred income taxes		(228	)		(233	)
Unrecovered nuclear plant cost		508			529
DESC rate refund		(113	)		(140	)
Toshiba settlement		(189	)		(204	)
Nuclear decommissioning		(54	)		(51	)
Deferred state income taxes		226			208
Federal benefit of deferred state income taxes		(47	)		(44	)
Deferred fuel, purchased energy and gas costs		27			(12	)
Pension benefits		35			39
Other postretirement benefits		(35	)		(37	)
Loss and credit carryforwards		(343	)		(382	)
Other		33			69
Total net deferred income tax liabilities	$	959		$	840
Deferred Investment Tax Credits-Regulated Operations		16			18
Total Deferred Taxes and Deferred Investment Tax Credits	$	975		$	858

At December 31, 2021, DESC had the following deductible loss and credit carryforwards:

(millions)	Deductible Amount		Deferred Tax Asset		Expiration Period
Federal losses	$	890	$	187	2037
Federal production and other credits		—		29	2035-2041
State losses		2,617		131	2037-2040
State investment and other credits		—		27	2026-2031
Total	$	3,507	$	374

A reconciliation of changes in DESC’s unrecognized tax benefits follows:

(millions)	2021			2020		2019
Balance at January 1	$	138		$	132	$	106
Increases-prior period positions		6			5		76
Decreases-prior period positions		(57	)		—		(53	)
Increases-current period positions		1			1		3
Settlements with tax authorities		(26	)		—		—
Balance at December 31	$	62		$	138	$	132

Throughout 2019, the evaluation of federal and state income tax positions taken in DESC’s tax returns prior to the SCANA Combination increased unrecognized tax benefits by $79 million and increased income tax expense by $67 million. In the fourth quarter of 2019, DESC also remeasured its beginning unrecognized tax benefits by $53 million. These changes were offset by a $45 million reduction in credit carryforward deferred tax assets and a $7 million increase to accrued taxes resulting in a $1 million benefit to income tax expense.

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. If recognized, all the unrecognized tax benefits would impact the effective tax rate.

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The statute is closed for IRS examination of years prior to 2013. The IRS is currently examining DESC’s federal returns from 2013 through 2017. DESC is no longer subject to state and local income tax examinations by tax authorities for years prior to 2018.

It is reasonably possible that these unrecognized tax benefits may decrease by $13 million within the next twelve months. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could increase by less than $1 million. Otherwise, with regard to 2021 and prior years, DESC cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2022.

DESC is also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if DESC utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are generally subject to examination.

8.  DERIVATIVE FINANCIAL INSTRUMENTS

See Note 2 for DESC’s accounting policies, objectives, and strategies for using derivative instruments. See Note 9 for further information about fair value measurements and associated valuation methods for derivatives.

Derivative assets and liabilities are presented gross on DESC’s Consolidated Balance Sheets. DESC’s derivative contracts include over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter contracts contain contractual rights of setoff through master netting arrangements and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency, or other conditions.

In general, most over-the-counter transactions are subject to collateral requirements. Types of collateral for over-the-counter contracts include cash, letters of credit, and, in some cases, other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities.

Certain of DESC’s derivative instruments contain credit-related contingent provisions. These provisions require DESC to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying the instruments that are in a liability position and not fully collateralized with cash were fully triggered as of December 31, 2021 and 2020, DESC would have been required to post $8 million and $10 million, respectively, of additional collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. DESC had posted $11 million and $1 million, respectively, of collateral at December 31, 2021 and 2020 related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of December 31, 2021 and 2020 was $19 million and $11 million, respectively, which does not include the impact of any offsetting asset positions.

The table below presents derivative balances by type of financial instrument, if the gross amounts recognized in the Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid. DESC’s commodity derivative assets are not subject to a master netting agreement or similar arrangement.

	December 31, 2021								December 31, 2020
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
(millions)	Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
Interest rate contracts:
Over-the-counter	$	19	$	—	$	11	$	8	$	27	$	—	$	17	$	10
Total derivatives	$	19	$	—	$	11	$	8	$	27	$	—	$	17	$	10

Volumes

The following table presents the volume of derivative activity at December 31, 2021. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions.

	Current		Noncurrent
Electricity (MWh in millions):
Fixed price		2		23
Interest rate(1) (in millions)	$	—	$	71

(1)   Maturity is determined based on final settlement period.

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Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of derivatives and where they are presented in the Consolidated Balance Sheets:

(millions)	Fair Value - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
At December 31, 2021
Current Assets
Commodity	$	—	$	18	$	18
Total current derivative assets (1)		—		18		18
Noncurrent Assets
Commodity		—		130		130
Total noncurrent derivative assets (2)		—		130		130
Total derivative assets	$	—	$	148	$	148
Current Liabilities
Interest rate	$	1	$	1	$	2
Total current derivative liabilities(3)		1		1		2
Noncurrent Liabilities
Interest rate		11		6		17
Total noncurrent derivative liabilities(4)		11		6		17
Total derivative liabilities	$	12	$	7	$	19
At December 31, 2020
Current Liabilities
Interest rate	$	1	$	1	$	2
Total current derivative liabilities(3)		1		1		2
Noncurrent Liabilities
Interest rate		15		10		25
Total noncurrent derivative liabilities(4)		15		10		25
Total derivative liabilities	$	16	$	11	$	27

(1)   Current derivative assets are presented in other current assets in DESC’s Consolidated Balance Sheets.

(2) Noncurrent derivative assets are presented in other deferred debits and other assets in DESC’s Consolidated Balance Sheets.

(3)   Current derivative liabilities are presented in other current liabilities in DESC’s Consolidated Balance Sheets.

(4)  Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in DESC’s Consolidated Balance Sheets.

The following tables present the gains and losses on derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Comprehensive Income (Loss):

Derivatives in Cash Flow Hedging Relationships

(millions)	Increase (Decrease) in Derivatives Subject to Regulatory Treatment(1)
Year Ended December 31, 2021
Derivative type and location of gains (losses):
Interest rate	$	9
Total	$	9
Year Ended December 31, 2020
Derivative type and location of gains (losses):
Interest rate	$	1
Total	$	1
Year Ended December 31, 2019
Derivative type and location of gains (losses):
Interest rate	$	1
Total	$	1

(1)   Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/ liabilities have no associated effect in the Consolidated Statements of Comprehensive Income (Loss).

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Derivatives Not designated as Hedging Instruments

(millions)	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2021			2020			2019
Derivative type and location of gains (losses):
Commodity contracts:
Purchased power	$	8			—			—
Interest rate contracts:
Interest charges		(2	)		(1	)		(1	)
Total	$	6		$	(1	)	$	(1	)

(1)   Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in the Consolidated Statements of Comprehensive Income (Loss).

9.  FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of DESC’s own nonperformance risk on its liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). DESC applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments. DESC applies credit adjustments to its derivative fair values in accordance with the requirements described above.

Inputs and Assumptions

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including industry publications, and to a lesser extent, broker quotes. When evaluating pricing information provided by Designated Contract Market settlement pricing, other pricing services, or brokers, DESC considers the ability to transact at the quoted price, i.e. if the quotes are based on an active market or an inactive market and to the extent which pricing models are used, if pricing is not readily available. If pricing information from external sources is not available, or if DESC believes that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases the unobservable inputs are developed and substantiated using historical information, available market data, third-party data and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships and changes in third-party sources.

The inputs and assumptions used in measuring fair value include the following:

For commodity derivative contracts:

• Forward commodity prices

• Transaction prices

• Volumes

• Commodity location

• Interest rates

• Credit quality of counterparties and DESC

• Credit enhancements

• Time value

For interest rate derivative contracts:

• Interest rate curves

• Credit quality of counterparties and DESC

• Notional value

• Credit enhancements

• Time value

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Levels

DESC utilizes the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

• Level 1-Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date.

• Level 2-Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include interest rate swaps.

• Level 3-Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for DESC consist of long-dated commodity derivatives.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

Level 3 Valuations

DESC enters into physical forwards contracts, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical forwards contracts. The discounted cash flow model for forwards calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. For Level 3 fair value measurements, certain forward market prices are considered unobservable.

The following table presents DESC’s quantitative information about Level 3 fair value measurements at December 31, 2021. The range and weighted average are presented in dollars for market price inputs.

	Fair Value (millions)		Valuation Techniques	Unobservable Input	Range	Weighted Average(1)
Assets
Physical forwards:
Electricity	$	148	Discounted cash flow	Market price (per MWh)(2)	28-74	43
Total assets	$	148

(1)   Averages weighted by volume.

(2)   Represents market prices beyond defined terms for Levels 1 and 2.

Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)

Nonrecurring Fair Value Measurement

During the third quarter of 2020, DESC determined that certain of its nonutility property was impaired and recorded a $12 million charge ($9 million after-tax) within impairments and other charges in its Consolidated Statements of Comprehensive Income (Loss) to adjust the property down to its estimated fair value of $6 million. The fair value determinations are considered Level 2 fair value measurements due to the use of real estate appraised values.

Recurring Fair Value Measurements

Fair value disclosures for assets held in DESC’s pension plan are presented in Note 11.

The following table presents DESC’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:

	Level 1		Level 2		Level 3		Total
(millions)
At December 31, 2021
Assets
Commodity	$	—	$	—	$	148	$	148
Total assets	$	—	$	—	$	148	$	148
Liabilities
Interest rate	$	—	$	19	$	—	$	19
Total liabilities	$	—	$	19	$	—	$	19
At December 31, 2020
Liabilities
Interest rate	$	—	$	27	$	—	$	27
Total liabilities	$	—	$	27	$	—	$	27

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The following table presents the net change in DESC's assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category. There were no net changes in assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category for the year ended December 31, 2020.

	2021
(millions)
Balance at January 1,	$	—
Total realized and unrealized gains (losses):
Included in earnings:
Purchased power		8
Included in regulatory assets/liabilities		148
Settlements		(8	)
Balance at December 31,	$	148

There are no unrealized gains and losses included in earnings in the Level 3 fair value category related to assets/liabilities still held at the reporting date for the year ended December 31, 2021.

Fair Value of Financial Instruments

Substantially all of DESC’s financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of financial instruments classified within current assets and current liabilities are representative of fair value because of the short-term nature of these instruments. For financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:

At December 31,	2021				2020
(millions)	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
Long-term debt(2)	$	3,724	$	4,831	$	3,360	$	4,748
Affiliated long-term debt		230		230		230		230

(1)   Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2)   Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs and discount or premium.

10.  ASSET RETIREMENT OBLIGATIONS

A liability for the present value of an ARO is recognized when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.

The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to DESC’s regulated utility operations. As of December 31, 2021, DESC has recorded AROs of $287 million for nuclear plant decommissioning. In addition, DESC has recorded AROs of $312 million for other conditional obligations primarily related to other generation and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of precision, particularly since such payments will be made many years in the future.

A reconciliation of the beginning and ending aggregate carrying amount of AROs is as follows:

(millions)	2021			2020
Beginning balance	$	597		$	489
Liabilities settled		—			(4	)
Accretion expense		25			23
Revisions in estimated cash flows(1)		(23	)		89
Ending balance	$	599		$	597

(1)   The decrease in 2021 is due to the remeasurement of gas pipeline AROs. The increase in 2020 reflects revisions from the nuclear decommissioning cost study.

11.  EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN

Pension and Other Postretirement Benefit Plans

SCANA sponsors a noncontributory defined benefit pension plan covering regular, full-time employees hired before January 1, 2014. DESC participates in SCANA's pension plan. SCANA’s policy has been to fund the plan as permitted by applicable federal income tax regulations, as determined by an independent actuary.

The pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and all eligible employees hired subsequently. Under the cash balance formula, benefits accumulate as a result of compensation credits

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and interest credits. Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment. Benefits under the cash balance formula continued to accrue through December 31, 2020, after which no benefits accrue except for those participants under the cash balance formula who continue to earn interest credits. Benefits under the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued. Once the benefits under SCANA's pension plan no longer accrue, eligible participants will accrue benefits under a cash balance formula within the Dominion Energy Pension Plan, a qualified defined benefit pension plan sponsored by Dominion Energy.

In addition to pension benefits, SCANA provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. DESC participates in these programs. Retirees hired before January 1, 2011 share in a portion of their medical care cost, while employees hired subsequently are responsible for the full cost of retiree medical benefits elected by them. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.

The same benefit formula applies to all SCANA subsidiaries participating in the parent sponsored plans and, with regard to the pension plan, there are no legally separate asset pools. The postretirement benefit plans are accounted for as multiple employer plans.

Voluntary Retirement Program

In March 2019, Dominion Energy announced a voluntary retirement program to employees, including employees of DESC, that meet certain age and service requirements. In 2019, upon the determinations made concerning the number of employees that elected to participate in the program, DESC recorded a charge of $63 million ($47 million after-tax), of which $51 million was included within other operations and maintenance expense, $3 million within other taxes and $9 million within other income (expense), net. In addition, as a result of the voluntary retirement program, DESC recorded pension plan settlement losses of $16 million within other income (expense), net in 2019.

In the second quarter of 2019, DESC remeasured its pension and other postretirement benefit plans as a result of the voluntary retirement program. The remeasurement resulted in an increase in the pension benefit obligation of $16 million and an increase in the accumulated postretirement benefit obligation of $10 million. In addition, the remeasurement resulted in an increase in the fair value of pension plan assets of $27 million. The impact of the remeasurement on net periodic benefit cost was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 4.07% for the pension plan and 4.08% for the other postretirement benefit plan. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2018.

In the third quarter of 2019, DESC remeasured a pension plan as a result of a settlement from the voluntary retirement program. The settlement and related remeasurement resulted in an increase in the pension benefit obligation of $25 million and an increase in the fair value of the pension plan assets of $35 million for DESC. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 3.57%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2018.

Changes in Benefit Obligations

The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below.

	Pension Benefits						Other Postretirement Benefits
(millions)	2021			2020			2021			2020
Benefit obligation, January 1	$	742		$	727		$	184		$	214
Service cost		9			12			1			3
Interest cost		20			24			6			8
Plan participants’ contributions		—			—			—			2
Actuarial (gain) loss		(28	)		41			(8	)		(31	)
Benefits paid		(41	)		(22	)		(12	)		(13	)
Settlements		—			(40	)		—			—
Curtailment		—			—			—			—
Amounts funded to parent		—			—			—			1
Benefit obligation, December 31	$	702		$	742		$	171		$	184

The accumulated benefit obligation for pension benefits for DESC was $697 million at the end of 2021 and $732 million at the end of 2020. The accumulated pension benefit obligation differs from the projected pension benefit obligation above in that it reflects no assumptions about future compensation levels.

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Significant assumptions used to determine the above benefit obligations are as follows:

	Pension Benefits						Other Postretirement Benefits
	2021			2020			2021			2020
Annual discount rate used to determine benefit obligation		3.06	%		2.73	%		3.11	%		2.80	%
Assumed annual rate of future salary increases for projected    benefit obligation		3.71	%		4.52	%	N/A			N/A
Crediting interest rate for cash balance plans		1.81	%		1.93	%	N/A			N/A

DESC’s pension benefit obligations include a gain of $29 million in 2021 resulting primarily from an increase in the discount rate and a completed experience study and a $43 million loss in 2020 resulting from a decrease in the discount rate. Actuarial gains recognized during 2021 in DESC’s other postretirement benefit obligations include a $8 million gain resulting from an increase in the discount rate. Actuarial gains recognized during 2020 in Dominion Energy’s other postretirement benefit obligations include a $51 million gain as a result from a completed experience study and other healthcare-related assumption changes and were partially offset by a $19 million loss resulting from a decrease in the discount rate.  

A 6.25% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2021. The rate was assumed to decrease gradually to 5.0% in 2026 and to remain at that level thereafter.

Funded Status

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021			2020
(millions)
Fair value of plan assets	$	768	$	747	$	—		$	—
Benefit obligation		702		742		171			184
Funded status	$	66	$	5	$	(171	)	$	(184	)

Amounts recognized on the consolidated balance sheets were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021			2020
(millions)
Noncurrent assets	$	66	$	5	$	—		$	—
Current liability		—		—		(10	)		(11	)
Noncurrent liability		—		—		(161	)		(173	)

Amounts recognized in accumulated other comprehensive loss were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021		2020
(millions)
Net actuarial loss	$	1	$	4	$	—	$	—

Amounts recognized in regulatory assets were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021			2020
(millions)
Net actuarial (gain) loss	$	70	$	114	$	(5	)	$	1

In connection with the joint ownership of Summer, costs related to pensions attributable to Santee Cooper as of both December 31, 2021 and 2020 totaled $14 million and $19 million and were recorded within deferred debits. Costs related to other postretirement benefits attributable to Santee Cooper as of December 31, 2021 and 2020 totaled $12 million both years, and was recorded within deferred debits.

Changes in Fair Value of Plan Assets

Pension Benefits
(millions)	2021			2020
Fair value of plan assets, January 1	$	747		$	725
Actual return (loss) on plan assets		62			84
Benefits paid		(41	)		(22	)
Settlements		—			(40	)
Fair value of plan assets, December 31	$	768		$	747

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Investment Policies and Strategies

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

DESC’s overall objective for investing its pension plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are diversified among asset classes, securities, active and passive investment strategies and investment advisors. The strategic target asset allocations for DESC’s pension fund is: 45% global equities, 53% fixed income and 2% cash. Global equities include investments in U.S. and non-U.S. companies, developed and emerging markets and small and large cap companies. The split between U.S. and non-U.S. companies is roughly 60% U.S./40% Non-U.S. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. Equity and fixed income investments are in individual securities as well as mutual funds.  

DESC also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies.

For 2022, the expected long-term rate of return on assets will be 7.00%. DESC determines the expected long-term rates of return on plan assets for its pension plans by using a combination of:

• Expected inflation and risk-free interest rate assumptions;

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

• Expected future risk premiums, asset classes’ volatilities and correlations;

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

• Investment allocation of plan assets.

Fair Value Measurements

Assets held by the pension plan are measured at fair value and are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2021 and 2020, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

At December 31,	2021								2020
(millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	—	$	1	$	—	$	1	$	10	$	—	$	—	$	10
Corporate debt instruments		—		332		—		332		—		315		—		315
Government and other debt instruments		—		67		—		67		—		35		—		35
Total recorded at fair value	$	—	$	400	$	—	$	400	$	10	$	350	$	—	$	360
Assets recorded at NAV(1)
Common/collective trust funds								387								387
Total recorded at NAV							$	387							$	387
Total investments(2)							$	787							$	747

(1) These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient are not required to be categorized in the fair value hierarchy.

(2) Excludes net assets related to pending sales of securities of $4 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $25 million at December 31, 2021.

For purposes of calculating NAV, portfolio securities and other assets for which market quotes are readily available are valued at market value. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. U.S. Treasury securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt instruments and government and other debt instruments are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. In addition, corporate debt instruments include investments in open-end mutual funds registered with the SEC that invest in corporate debt instruments. Common collective trust assets and limited partnerships are valued at NAV, which has been determined based on the unit values of the trust funds. Unit values are determined by the organization sponsoring such trust funds by dividing the trust funds’ net assets at fair value by the units outstanding at each valuation date. Joint venture interests are invested in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges

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and not traded on a daily basis. The valuation of such multi-strategy hedge fund of funds is estimated based on the NAV of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may influence their fair value.

Expected Cash Flows

Total benefits expected to be paid from the pension plan or company assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows:

Expected Benefit Payments

(millions)	Pension Benefits		Other Postretirement Benefits
2022	$	46	$	11
2023		44		11
2024		46		11
2025		45		11
2026		43		11
2027 - 2031		201		57

Pension Plan Contributions

Under its funding policies, DESC evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, DESC determines the amount of contributions for the current year, if any, at that time. DESC made no contributions to the pension trust in 2021, 2020 or 2019. DESC does not expect to contribute to its qualified pension plan in 2022.

Net Periodic Benefit Cost

Net periodic benefit cost is recorded utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables.

Components of Net Periodic Benefit Cost

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2021			2020			2019			2021		2020		2019
(millions)
Service cost	$	9		$	12		$	15		$	1	$	3	$	3
Interest cost		20			24			28			6		8		9
Expected return on assets		(48	)		(45	)		(40	)		—		—		—
Prior service cost amortization		—			—			—			—		—		—
Amortization of actuarial losses		6			6			11			—		—		—
Settlement loss		—			7			16			—		—		—
Curtailment		—			—			6			—		—		3
Net periodic benefit cost	$	(13	)	$	4		$	36		$	7	$	11	$	15

In connection with regulatory orders, DESC recovers current pension costs through a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. For retail electric operations, current pension expense is recognized based on amounts collected through a rate rider, and differences between actual pension expense and amounts recognized pursuant to the rider are deferred as a regulatory asset (for under-collections) or regulatory liability (for over-collections) as applicable. In addition, DESC amortizes certain previously deferred pension costs. See Note 3.

Other changes in plan assets and benefit obligations recognized in other comprehensive income (net of tax) were as follows:

	Pension Benefits								Other Postretirement Benefits
Year Ended December 31,	2021			2020		2019			2021		2020			2019
(millions)
Current year actuarial (gain) loss	$	(3	)	$	2	$	(1	)	$	—	$	(2	)	$	1
Total recognized in other comprehensive income	$	(3	)	$	2	$	(1	)	$	—	$	(2	)	$	1

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Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows:

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2021			2020			2019			2021			2020			2019
(millions)
Current year actuarial (gain) loss	$	(39	)	$	1		$	(51	)	$	(6	)	$	(27	)	$	20
Amortization of actuarial losses		(5	)		(6	)		(11	)		—			(1	)		—
Settlement loss		—			(6	)		(16	)		—			—			—
Total recognized in regulatory assets	$	(44	)	$	(11	)	$	(78	)	$	(6	)	$	(28	)	$	20

Significant assumptions used in determining net periodic benefit cost:

	Pension Benefits			Other Postretirement Benefits
Year Ended December 31,	2021	2020	2019	2021	2020	2019
Discount rate	2.73%	3.47%	3.57/4.38%	2.80%	2.80%	4.08/4.41%
Expected return on plan assets	7.00%	7.00%	7.00%	n/a	n/a	n/a
Rate of compensation increase	4.52%	3.00%	3.00%	n/a	n/a	n/a
Crediting interest rate for cash balance plans	1.93%	2.67%	2.77/3.58%	n/a	n/a	n/a
Health care cost trend rate				6.25%	6.25%	6.60%
Ultimate health care cost trend rate				5.00%	5.00%	5.00%
Year achieved				2025-2026	2025-2026	2023

Participation in Dominion Energy Defined Benefit Plans

As discussed above, effective January 2021, DESC employees who had been receiving a cash balance formula became covered by the Dominion Energy Pension Plan. In addition, DESC employees hired in 2021 prior to July 2021 are covered by the Dominion Energy Pension Plan. As a participating employer, DESC is subject to Dominion Energy’s funding policy, which is to contribute annually an amount that is in accordance with ERISA. DESC made no contributions to the Dominion Energy Pension Plan during 2021. While DESC has not been notified by Dominion Energy of any required contributions to be made in 2022, it anticipates that it may have to contribute less than $1 million as a result of a contribution made by Dominion Energy in December 2021. DESC’s net periodic pension cost related to this plan was $3 million in 2021. Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in DESC’s Consolidated Statements of Income. The funded status of various Dominion Energy subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating Dominion Energy subsidiaries. At December 31, 2021, DESC’s pension and other postretirement benefits obligation includes $3 million for amounts due to Dominion Energy related to this plan.

Dominion Energy holds investments in trusts to fund employee benefit payments for the pension plan in which DESC’s employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that DESC will provide to Dominion Energy for its share of employee benefit plan contributions.

401(k) Retirement Savings Plan

Effective January 2021, DESC participates in a defined contribution savings plan sponsored by Dominion Energy.  Previously, DESC had participated in a defined contribution plan sponsored by SCANA, which was merged into the Dominion Energy plan in December 2020. DESC recognized employer matching contributions of $11 million in 2021 and $14 million in both 2020 and 2019.

12.  COMMITMENTS AND CONTINGENCIES

As a result of issues generated in the ordinary course of business, DESC is involved in legal proceedings before various courts and is periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that it is not possible for DESC to estimate a range of possible loss. For such matters that DESC cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that DESC is able to estimate a range of possible loss. For legal proceedings and governmental examinations that DESC is able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. DESC maintains various insurance programs, including general liability insurance coverage which provides coverage for personal injury or wrongful death cases. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent DESC’s maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on DESC’s financial position, liquidity or results of operations.

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Environmental Matters

DESC is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

From a regulatory perspective, DESC continually monitors and evaluates its current and projected emission levels and strives to comply with all state and federal regulations regarding those emissions. DESC participates in the SO₂ and NO_X emission allowance programs with respect to coal plant emissions and also has constructed additional pollution control equipment at its coal-fired electric generating plants. These actions are expected to address many of the rules and regulations discussed herein.

Air

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

Ozone Standards

The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018 with states required to develop plans to address the new standard. In December 2021, the EPA approved the implementation plan developed for South Carolina. DESC does not expect compliance to have a material impact on its results of operations or cash flows.

ACE Rule

In July 2019, the EPA published the final rule informally referred to as the ACE Rule, as a replacement for the Clean Power Plan. The ACE Rule regulated GHG emissions from existing coal-fired power plants pursuant to Section 111(d) of the CAA and required states to develop plans by July 2022 establishing unit-specific performance standards for existing coal-fired power plants. In January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE Rule and remanded it to the EPA. This decision would take effect upon issuance of the court’s mandate. In March 2021, the court issued a partial mandate vacating and remanding all parts of the ACE Rule except for the portion of the ACE Rule that repealed the Clean Power Plan. In October 2021, the U.S. Supreme Court agreed to hear a challenge of the U.S. Court of Appeals for the D.C. Circuit’s decision on the ACE Rule. While the EPA has stated its intention to replace the ACE Rule, it is unknown at this time if or how the EPA will issue a replacement for the ACE Rule and how that replacement will affect DESC’s operations, financial condition and/or cash flows.

Carbon Regulations

In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and exceed a significant emissions rate of 75,000 tons per year of CO2 equivalent emissions. Until the EPA ultimately takes final action on this rulemaking, DESC cannot predict the impact to its results of operations, financial condition and/or cash flows.

In December 2018, the EPA proposed revised Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources. The proposed rule would amend the previous determination that the best system of emission reduction for newly constructed coal-fired steam generating units is no longer partial carbon capture and storage. Instead, the proposed revised best system of emission reduction for this source category is the most efficient demonstrated steam cycle (e.g., supercritical steam conditions for large units and subcritical steam conditions for small units) in combination with best operating practices. In January 2021, the EPA published a final rule affirming that fossil fuel-fired electric generating units meet the requirement that a source category “significantly contribute” to endangering air pollution for the purposes of regulating GHG emissions from new, modified and reconstructed stationary sources. The January 2021 rule also established a threshold for the “significant contribution” threshold that would have meant that no other source category, such as oil and gas facilities, petroleum refineries, and boilers, would meet that requirement at this time. In April 2021, the U.S. Court of Appeals for the D.C. Circuit granted an unopposed motion by the EPA to vacate and remand the January 2021 rule. The proposed revision to the performance standards for coal-fired steam generating units remains pending. Until the EPA ultimately takes final action on this rulemaking, DESC cannot predict the impact to its results of operations, financial condition and/or cash flows.

Water

The CWA, as amended, 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. DESC must comply with applicable aspects of the CWA programs at its operating facilities.

Regulation 316(b)

In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations

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with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. DESC has five facilities that are subject to the final regulations. DESC is also working with the EPA and state regulatory agencies to assess the applicability of Section 316(b) to five hydroelectric facilities. DESC anticipates that it may have to install impingement control technologies at certain of these stations that have once-through cooling systems. DESC is currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technological, and cost benefit studies. DESC is conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications at certain facilities to ensure compliance with this rule. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

Effluent Limitations Guidelines

In September 2015, the EPA released a final rule to revise the ELG Rule. The final rule established updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. In April 2017, the EPA granted two separate petitions for reconsideration of the final ELG Rule and stayed future compliance dates in the rule. Also in April 2017, the U.S. Court of Appeals for the Fifth Circuit granted the EPA’s request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. In September 2017, the EPA signed a rule to postpone the earliest compliance dates for certain waste streams regulations in the final ELG Rule from November 2018 to November 2020; however, the latest date for compliance for these regulations was December 2023. In October 2020, the EPA released the final rule that extends the latest dates for compliance. Individual facilities’ compliance dates will vary based on circumstances and the determination by state regulators and may range from 2021 to 2028. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, as DESC expects that wastewater treatment technology retrofits and modifications to the bottom ash handling systems at the Williams and Wateree generating stations will be required, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

Capacity Use Area

In November 2019, a new CUA was established in the counties surrounding the Cope Generating Station (Western Capacity Use Area) under the South Carolina Groundwater Use and Reporting Regulation. Under the regulation any groundwater well in a CUA that withdraws above three million gallons per month must be permitted. The Cope Generating Station is located within this new Western Capacity Use Area. Cope has been using four deep groundwater wells for cooling water and other house loads since 1996. Prior to designation of the new Western Capacity Use Area, the wells at Cope Station were only required to be registered not permitted. As a result of this designation, Cope will need to restore the surface water equipment to operable status to reduce reliance on groundwater wells. This includes completion of 316(b) requirements, (including SCDHEC BACT determination and modification of the station national pollutant discharge elimination system permit) and extensive inspection, repair and/or replacement of the associated surface water withdrawal equipment which has been idle since 1996. While the impacts of this rule change are material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

Waste Management and Remediation

The operations of DESC are subject to a variety of state and federal laws and regulations governing the management and disposal of solid and hazardous waste, and release of hazardous substances associated with current and/or historical operations. The CERCLA, as amended, and similar state laws, may impose joint, several and strict liability for cleanup on potentially responsible parties who owned, operated or arranged for disposal at facilities affected by a release of hazardous substances. In addition, many states have created programs to incentivize voluntary remediation of sites where historical releases of hazardous substances are identified and property owners or responsible parties decide to initiate cleanups.

From time to time, DESC may be identified as a potentially responsible party in connection with the alleged release of hazardous substances or wastes at a site. Under applicable federal and state laws, DESC could be responsible for costs associated with the investigation or remediation of impacted sites, or subject to contribution claims by other responsible parties for their costs incurred at such sites. DESC also may identify, evaluate and remediate other potentially impacted sites under voluntary state programs. Remediation costs may be subject to reimbursement under DESC’s insurance policies, rate recovery mechanisms, or both. Except as described below, DESC does not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.

DESC has four decommissioned MGP sites in South Carolina that are in various states of investigation, remediation and monitoring under work plans approved by, or under review by, the SCDHEC or the EPA. DESC anticipates that activities at these sites will continue through 2025 at an estimated cost of $19 million. In addition, for one site, final approval of an updated work plan was received from the Army Corps of Engineers in December 2021, resulting in an additional $11 million of reserves and corresponding regulatory assets. DESC expects to recover costs arising from the remediation work at all four sites through rate recovery mechanisms and as of December 31, 2021, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $31 million and are included in regulatory assets.

Ash Pond and Landfill Closure Costs

In April 2015, the EPA enacted a final rule regulating CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store, CCRs. DESC currently has inactive and existing CCR ponds and CCR landfills

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subject to the final rule at 3 different facilities. This rule created a legal obligation for DESC to retrofit or close all of its inactive and existing ash ponds over a certain period of time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary.

In December 2016, legislation was enacted that creates a framework for EPA- approved state CCR permit programs. In August 2017, the EPA issued interim guidance outlining the framework for state CCR program approval. The EPA has enforcement authority until state programs are approved. The EPA and states with approved programs both will have authority to enforce CCR requirements under their respective rules and programs. In September 2017, the EPA agreed to reconsider portions of the CCR rule in response to two petitions for reconsideration. In March 2018, the EPA proposed certain changes to the CCR rule related to issues remanded as part of the pending litigation and other issues the EPA is reconsidering. Several of the proposed changes would allow states with approved CCR permit programs additional flexibility in implementing their programs. In July 2018, the EPA promulgated the first phase of changes to the CCR rule. In August 2018, the U.S. Court of Appeals for the D.C. Circuit issued its decision in the pending challenges of the CCR rule, vacating and remanding to the EPA three provisions of the rule. Until this matter is resolved and all phases of the CCR rule are promulgated, DESC is unable to precisely estimate potential incremental impacts or costs related to existing coal ash sites in connection with future implementation of the final CCR rule. While such amounts may be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts.

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SCANA Merger Approval Order

In accordance with the terms of the South Carolina Commission's SCANA Merger Approval Order, DESC adopted the Plan-B Levelized Customer Benefits Plan, effective February 2019, whereby the average bill for a DESC residential electric customer approximates that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the South Carolina Commission in August 2018. DESC also recorded a significant impairment charge in the fourth quarter of 2018, which charge resulted from its conclusion that NND Project capital costs exceeding the amount established in the SCANA Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed. In addition, in the first quarter of 2019, DESC recorded the following charges and liabilities which arose from or are related to provisions in the SCANA Merger Approval Order.

• A charge of $105 million ($79 million after-tax) included within the Corporate and Other segment related to certain assets that had been constructed in connection with the NND Project for which DESC committed to forgo recovery.

• A regulatory liability for refunds and restitution of amounts previously collected from retail electric customers of $1.0 billion ($756 million after-tax), recorded as a reduction in operating revenue, which will be credited to customers over an estimated 11 years effective February 2019. In addition, a previously existing regulatory liability of $1.0 billion will be credited to customers over 20 years ending 2039, which reflects amounts to be refunded to customers related to the monetization of guaranty settlement described in Note 3.

• A regulatory liability for refunds to natural gas customers totaling $2 million ($2 million after-tax).

• A tax charge of $194 million related to $258 million of regulatory assets for which DESC committed to forgo recovery.

Further, except for rate adjustments for fuel and environmental costs, DSM costs, and other rates routinely adjusted on an annual or biannual basis, DESC will freeze retail electric base rates at current levels until January 1, 2021. As discussed in Note 3, in April 2020, the South Carolina Commission issued an order vacating the portion of the SCANA Merger Approval Order requiring that new retail electric rates be implemented by January 1, 2021.

The South Carolina Commission order also approved the removal of DESC's investment in certain transmission assets that have not been abandoned from BLRA capital costs. The South Carolina Commission approved deferral of these operating costs related to the investment until recovery of the transmission capital costs and associated deferred operating costs was addressed in a future rate proceeding. These amounts were included in and approved as part of DESC’s electric base rate case filing discussed in Note 3.

Various parties filed petitions for rehearing or reconsideration of the SCANA Merger Approval Order. In January 2019, the South Carolina Commission issued an order (1) granting the request of various parties and finding that DESC was imprudent in its actions by not disclosing material information to the ORS and the South Carolina Commission with regard to costs incurred subsequent to March 2015 and (2) denying the petitions for rehearing or consideration as to other issues raised in the various petitions. The deadline to appeal the SCANA Merger Approval Order and the order on rehearing expired in April 2019, and no party has sought appeal.

Claims and Litigation

The following describes certain legal proceedings involving DESC relating primarily to events occurring before closing of the SCANA Combination. No reference to, or disclosure of, any proceeding, item or matter described below shall be construed as an admission or indication that such proceeding, item or matter is material. For certain of these matters, and unless otherwise noted therein, DESC is unable to estimate a reasonable range of possible loss and the related financial statement impacts, but for any such matter there could be a material impact to its results of operations, financial condition and/or cash flows. For the matters for which DESC is able to reasonably estimate a probable loss, the Consolidated Balance Sheets at December 31, 2021 and 2020 include reserves of $211 million and $208 million, respectively, and insurance receivables of $85 million and $8 million, respectively, included within other receivables. These balances at December 31, 2021 and 2020 include $85 million and $8 million, respectively, of offsetting reserves and insurance receivables related to personal injury or wrongful death cases which are currently pending. DESC’s Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2021, 2020 and 2019 include charges of $70 million ($53 million after-tax), $97 million ($73 million after-tax) and $590 million ($444 million after-tax), respectively, within impairment of assets and other charges, reflected in the Corporate and Other segment.

Ratepayer Class Actions

In May 2018, a consolidated complaint against DESC, SCANA and the State of South Carolina was filed in the State Court of Common Pleas in Hampton County, South Carolina (the DESC Ratepayer Case). The plaintiffs alleged, among other things, that DESC was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the NND Project, and that DESC committed unfair trade practices and violated state anti-trust laws. In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement. The court entered an order granting final approval of the settlement in June 2019, which became effective in July 2019. The settlement agreement, contingent upon the closing of the SCANA Combination, provided that SCANA and DESC establish an escrow account and proceeds from the escrow account would be distributed to the plaintiffs, after payment of certain taxes, attorneys' fees and other expenses and administrative costs. The escrow account would include (1) up to $2.0 billion, net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the escrow account in favor of class members over a period of time established by the South Carolina Commission in its order related to matters before the South Carolina Commission related to the NND Project, (2) a cash payment of $115 million and (3) the transfer of certain DESC-owned real estate or sales proceeds from the sale of such properties, which counsel for the plaintiffs estimated to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and DESC funded the cash payment portion of the

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escrow account. In July 2019, DESC transferred $117 million representing the cash payment, plus accrued interest, to the plaintiffs. Through August 2020, property, plant and equipment with a net recorded value of $22 million had been transferred to the plaintiffs in coordination with the court-appointed real estate trustee to satisfy the settlement agreement. In September 2020, the court entered an order approving a final resolution of the transfer of real estate or sales proceeds with a cash contribution of $38.5 million by DESC and the conveyance of property, plant and equipment with a net recorded value of $3 million, which was completed by DESC in October 2020. In December 2021, the court approved a motion for and DESC completed the repurchase of $8 million of property, plant and equipment previously transferred to the plaintiffs.

In September 2017, a purported class action was filed by Santee Cooper ratepayers against Santee Cooper, DESC, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the State Court of Common Pleas in Hampton County, South Carolina (the Santee Cooper Ratepayer Case). The allegations were substantially similar to those in the DESC Ratepayer Case. In March 2020, the parties executed a settlement agreement relating to this matter as well as the Luquire Case and the Glibowski Case described below. The settlement agreement provided that Dominion Energy and Santee Cooper establish a fund for the benefit of class members in the amount of $520 million, of which Dominion Energy’s portion was $320 million of shares of Dominion Energy common stock. In July 2020, the court issued a final approval of the settlement agreement. In September 2020, Dominion Energy issued $322 million of shares of Dominion Energy common stock to satisfy its obligation under the settlement agreement, including interest charges.

In July 2019, a similar purported class action was filed by certain Santee Cooper ratepayers against DESC, SCANA, Dominion Energy and former directors and officers of SCANA in the State Court of Common Pleas in Orangeburg, South Carolina (the Luquire Case). In August 2019, DESC, SCANA and Dominion Energy were voluntarily dismissed from the case. The claims were similar to the Santee Cooper Ratepayer Case. In March 2020, the parties executed a settlement agreement as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Glibowski Case. This case was dismissed as part of the Santee Cooper Ratepayer Case settlement described above.

RICO Class Action

In January 2018, a purported class action was filed, and subsequently amended, against SCANA, DESC and certain former executive officers in the U.S. District Court for the District of South Carolina (the Glibowski Case). The plaintiff alleged, among other things, that SCANA, DESC and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. In March 2020, the parties executed a settlement agreement as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Luquire Case. This case was dismissed as part of the Santee Cooper Ratepayer Case settlement described above.

SCANA Shareholder Litigation

In February 2018, a purported class action was filed against Dominion Energy and certain former directors of SCANA and DESC in the State Court of Common Pleas in Richland County, South Carolina (the Metzler Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina and filed a Motion to Dismiss in March 2018. In September 2019, the U.S. District Court for the District of South Carolina granted the plaintiffs’ motion to consolidate the Metzler Lawsuit with another lawsuit regarding the SCANA Merger Agreement to which DESC is not a party. In October 2019, the plaintiffs filed an amended complaint against certain former directors and executive officers of SCANA and DESC, which stated substantially similar allegations to those in the initial lawsuits as well as an inseparable fraud claim. In November 2019, the defendants filed a motion to dismiss. In April 2020, the U.S. District Court for the District of South Carolina denied the motion to dismiss. In May 2020, SCANA filed a motion to intervene, which was denied in August 2020. In September 2020, SCANA filed a notice of appeal with the U.S. Court of Appeals for the Fourth Circuit. In June 2021, the parties reached an agreement in principle to settle this case, along with a related case to which DESC was not a party, subject to court approval, with no financial impact to DESC.

Employment Class Actions and Indemnification

In August 2017, a case was filed in the U.S. District Court for the District of South Carolina on behalf of persons who were formerly employed at the NND Project. In July 2018, the court certified this case as a class action. In February 2019, certain of these plaintiffs filed an additional case, which case has been dismissed and the plaintiffs have joined the case filed in August 2017. The plaintiffs allege, among other things, that SCANA, DESC, Fluor Corporation and Fluor Enterprises, Inc. violated the Worker Adjustment and Retraining Notification Act in connection with the decision to stop construction at the NND Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment and are seeking damages, which could be as much as $100 million for 100% of the NND Project. In January 2021, the U.S. District Court for the District of South Carolina granted summary judgment in favor of SCANA, DESC, Fluor Corporation and Fluor Enterprises, Inc. In February 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fourth Circuit. In November 2021, the U.S. Court of Appeals for the Fourth Circuit affirmed the lower court ruling.

In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against DESC and Santee Cooper. The plaintiffs make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants' alleged failure and refusal to defend and indemnify the Fluor defendants in the aforementioned case. This case is pending.

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FILOT Litigation and Related Matters

In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against DESC in the State Court of Common Pleas in Fairfield County, South Carolina, making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of implied duty of good faith and fair dealing and unfair trade practices related to DESC’s termination of the FILOT agreement between DESC and Fairfield County related to the NND Project. The plaintiff sought a temporary and permanent injunction to prevent DESC from terminating the FILOT agreement. The plaintiff withdrew the motion for temporary injunction in December 2017. In July 2021, the parties executed a settlement agreement requiring DESC to pay $99 million, which could be satisfied in either cash or shares of Dominion Energy common stock. Also in July 2021, the State Court of Common Pleas in Fairfield County, South Carolina approved the settlement. In July 2021, Dominion Energy issued 1.4 million shares of Dominion Energy common stock to satisfy DESC’s obligation under the settlement agreement.

Governmental Proceedings and Investigations

In June 2018, DESC received a notice of proposed assessment of approximately $410 million, excluding interest, from the SCDOR following its audit of DESC’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NND Project, is based on the SCDOR’s position that DESC’s sales and use tax exemption for the NND Project does not apply because the facility will not become operational. In December 2020, the parties reached an agreement in principle in the amount of $165 million to resolve this matter. In June 2021, the parties executed a settlement agreement which allows DESC to fund the settlement amount through a combination of cash, shares of Dominion Energy common stock or real estate with an initial payment of at least $43 million in shares of Dominion Energy common stock. In August 2021, Dominion Energy issued 0.6 million shares of its common stock to satisfy DESC’s obligation for the initial payment under the settlement agreement.

In September and October 2017, SCANA was served with subpoenas issued by the U.S. Attorney’s Office for the District of South Carolina and the Staff of the SEC’s Division of Enforcement seeking documents related to the NND Project. In February 2020, the SEC filed a complaint against SCANA, two of its former executive officers and DESC in the U.S. District Court for the District of South Carolina alleging that the defendants violated federal securities laws by making false and misleading statements about the NND Project. In April 2020, SCANA and DESC reached an agreement in principle with the Staff of the SEC’s Division of Enforcement to settle, without admitting or denying the allegations in the complaint. In December 2020, the U.S. District Court for the District of South Carolina issued an order approving the settlement which required SCANA to pay a civil monetary penalty totaling $25 million, and SCANA and DESC to pay disgorgement and prejudgment interest totaling $112.5 million, which disgorgement and prejudgment interest amount were deemed satisfied by the settlements in the SCANA Securities Class Action and the DESC Ratepayer Case. SCANA paid the civil penalty in December 2020. The SEC civil action against two former executive officers of SCANA remains pending and is currently subject to a stay granted by the court in June 2020 at the request of the U.S. Attorney’s Office for the District of South Carolina.

In addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and DESC. Dominion Energy is cooperating fully with the investigations by the U.S. Attorney’s Office and the South Carolina Law Enforcement Division, including responding to additional subpoenas and document requests. Dominion Energy has also entered into a cooperation agreement with the U.S. Attorney’s Office and the South Carolina Attorney General’s Office. The cooperation agreement provides that in consideration of its full cooperation with these investigations to the satisfaction of both agencies, neither such agency will criminally prosecute or bring any civil action against Dominion Energy or any of its current, previous, or future direct or indirect subsidiaries related to the NND Project. A former executive officer of SCANA entered a plea agreement with the U.S. Attorney’s Office and the South Carolina Attorney General’s Office in June 2020 and entered a guilty plea with the U.S. District Court for the District of South Carolina in July 2020. Another former executive officer of SCANA entered a plea agreement with the U.S. Attorney's Office and the South Carolina Attorney General's Office in November 2020 and entered guilty pleas in the U.S. District Court for the District of South Carolina and in South Carolina state court in February 2021. As a result of the pleas, Dominion Energy has terminated indemnity for these former executive officers related to these two cases.

Abandoned NND Project

DESC, for itself and as agent for Santee Cooper, entered into an engineering, construction and procurement contract with Westinghouse and WECTEC in 2008 for the design and construction of the NND Project, of which DESC’s ownership share is 55%. Various difficulties were encountered in connection with the project. The ability of Westinghouse and WECTEC to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters preceded the filing for bankruptcy protection by Westinghouse and WECTEC in March 2017, and were the subject of comprehensive analyses performed by SCANA and Santee Cooper.

Based on the results of SCANA’s analysis, and in light of Santee Cooper's decision to suspend construction on the NND Project, in July 2017, SCANA determined to stop the construction of the units and to pursue recovery of costs incurred in connection with the construction under the abandonment provisions of the Base Load Review Act or through other means. This decision by SCANA became the focus of numerous legislative, regulatory and legal proceedings. Some of these proceedings are described above.

In September 2017, DESC, for itself and as agent for Santee Cooper, filed with the U.S. Bankruptcy Court for the Southern District of New York Proofs of Claim for unliquidated damages against each of Westinghouse and WECTEC. These Proofs of Claim were based

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upon the anticipatory repudiation and material breach by Westinghouse and WECTEC of the contract, and assert against Westinghouse and WECTEC any and all claims that are based thereon or that may be related thereto.

Westinghouse’s reorganization plan was confirmed by the U.S. Bankruptcy Court for the Southern District of New York and became effective in August 2018. In connection with the effectiveness of the reorganization plan, the contract associated with the NND Project was deemed rejected. DESC contested approximately $285 million of filed liens in Fairfield County, South Carolina. Most of these asserted liens were claims that relate to work performed by Westinghouse subcontractors before the Westinghouse bankruptcy, although some of them were claims arising from work performed after the Westinghouse bankruptcy.

DESC and Santee Cooper were responsible for amounts owed to Westinghouse for valid work performed by Westinghouse subcontractors on the NND Project after the Westinghouse bankruptcy filing until termination of the interim assessment agreement. In December 2019, DESC and Santee Cooper entered into a confidential settlement agreement with W Wind Down Co LLC resolving claims relating to the interim assessment agreement.

Further, some Westinghouse subcontractors that made claims against Westinghouse in the bankruptcy proceeding also filed claims against DESC and Santee Cooper in South Carolina state court for damages. Many of these claimants asserted construction liens against the NND Project site. In December 2021, settlements were reached to resolve all remaining claims made by Westinghouse subcontractors. All amounts for which Dominion Energy was ultimately responsible were funded utilizing, and did not exceed, the portion of the Toshiba Settlement allocated for such balances within the SCANA Merger Approval Order recorded in regulatory liabilities on DESC’s Consolidated Balance Sheets.

Nuclear Insurance

Under Price-Anderson, DESC (for itself and on behalf of Santee-Cooper) maintains agreements of indemnity with the U.S. Nuclear Regulatory Commission that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Summer. Price-Anderson provides funds up to $13.5 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $450 million by American Nuclear Insurers with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is liable for up to $138 million per reactor owned for each nuclear incident occurring at any reactor in the U.S., provided that not more than $21 million of the liability per reactor would be assessed per year. DESC’s maximum assessment, based on its two-thirds ownership of Summer, would be $92 million per incident, but not more than $14 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

DESC currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Summer for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.33 billion resulting from an event of a non-nuclear origin. The NEIL policies in aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. The NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, DESC’s portion of the retrospective premium assessment would not exceed $24 million. DESC currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Summer for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, DESC's portion of the retrospective premium assessment would not exceed $2 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Summer exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that DESC's rates would not recover the cost of any purchased replacement power, DESC will retain the risk of loss as a self-insurer. DESC has no reason to anticipate a serious nuclear or other incident. However, if such an incident were to occur, it likely would have a material impact on DESC's results of operations, cash flows and financial position.

Spent Nuclear Fuel

The Nuclear Waste Policy Act of 1982 required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. DESC entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. By mutual agreement of the parties, damage award payments and settlement payments are made until the DOE has accepted the same amount of spent fuel from the facility as if it has fully performed its contractual obligations. In 2021, DESC received payment of $1 million for resolution of its share of claims incurred at Summer for the period of January 1, 2020 through December 31, 2020. In 2020, DESC received payment of $4 million for resolution of its share of claims incurred at Summer for the period of January 1, 2019 through December 31, 2019. As of December 31, 2021, the federal government has not accepted any spent fuel from Summer, and it remains unclear when the repository may become available. DESC has constructed an independent spent fuel storage installation to accommodate the spent nuclear fuel output for the life of Summer. DESC may evaluate other technology as it becomes available.

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Long-Term Purchase Agreements

At December 31, 2021, DESC had the following long-term commitments that are noncancelable or cancelable only under certain conditions, and that a third party that will provide the contracted goods or services has used to secure financing.

(millions)	2022		2023		2024		2025		2026		Thereafter		Total
Purchased electric capacity(1)	$	83	$	82	$	82	$	83	$	86	$	834	$	1,250

(1)   Includes affiliated amounts with certain solar facilities of $238 million.

Commitments represent estimated amounts payable for energy under power purchase contracts with qualifying facilities which expire at various dates through 2046. Energy payments are generally based on fixed dollar amounts per month and totaled $73 million in 2021, $64 million in 2020 and $37 million in 2019.

13. LEASES

At December 31, 2021 and 2020, DESC had the following lease assets and liabilities recorded in the Consolidated Balance Sheets:

At December 31,	2021		2020
(millions)
Lease assets:
Operating lease assets(1)	$	19	$	21
Finance lease assets(2)		13		20
Total lease assets	$	32	$	41
Lease liabilities:
Operating lease - current(3)	$	2	$	3
Operating lease - noncurrent(4)		17		18
Finance lease - current(5)		5		6
Finance lease - noncurrent		10		15
Total lease liabilities	$	34	$	42

(1)   Included in other deferred debits and other assets in the Consolidated Balance Sheets.

(2)   Included in utility plant, net, in the Consolidated Balance Sheets, net of $20 million and $24 million of accumulated amortization at December 31, 2021 and December 31, 2020, respectively.

(3)   Included in other current liabilities in the Consolidated Balance Sheets.

(4)   Included in other deferred credits and other liabilities in the Consolidated Balance Sheets.

(5)   Included in securities due within one year in the Consolidated Balance Sheets.

For the years ended December 31, 2021, 2020 and 2019, total lease cost consisted of the following:

Year Ended December 31,	2021		2020		2019
(millions)
Finance lease cost:
Amortization	$	6	$	8	$	7
Interest		1		1		1
Operating lease cost		4		4		4
Short-term lease cost		2		2		1
Total lease cost	$	13	$	15	$	13

For the years ended December 31, 2021, 2020 and 2019, cash paid for amounts included in the measurement of lease liabilities consisted of the following amounts, included in the Consolidated Statements of Cash Flows:

Year Ended December 31,	2021		2020		2019
(millions)
Operating cash flows from finance leases	$	1	$	1	$	1
Operating cash flows from operating leases		4		4		3
Financing cash flows from finance leases		6		8		7

At December 31, 2021 and 2020, the weighted average remaining lease term and weighted average discount rate for finance and operating leases were as follows:

At December 31,	2021			2020
Weighted average remaining lease term - finance leases	4 years			4 years
Weighted average remaining lease term - operating leases	20 years			19 years
Weighted average discount rate - finance leases		2.91	%		2.92	%
Weighted average discount rate - operating leases		3.97	%		3.95	%

59

Lease liabilities have the following scheduled maturities:

(millions)	Operating			Finance
2022	$	3		$	5
2023		2			4
2024		2			3
2025		1			1
2026		1			1
After 2026		21			1
Total undiscounted lease payments		30			15
Present value adjustment		(11	)		(1	)
Present value of lease liabilities	$	19		$	14

14.  OPERATING SEGMENTS

The Corporate and Other Segment 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.

In 2021, DESC reported after-tax net expenses of $212 million for specific items in the Corporate and Other segment, of which $208 million was attributable to its operating segment.

The net expense for specific items attributable to DESC’s operating segment in 2021 primarily related to $266 million ($199 million after-tax) of charges associated with the settlement of the South Carolina electric base rate case and a $70 million ($53 million after-tax) charge associated with litigation.

In 2020, DESC reported after-tax net expenses of $104 million for specific items in the Corporate and Other segment, all of which were attributable to its operating segment.

The net expense for specific items attributable to DESC’s operating segment in 2020 primarily related to $99 million ($74 million after-tax) of charges associated with litigation.

In 2019, DESC reported after-tax net expenses of $1.6 billion for specific items in the Corporate and Other segment, all of which were attributable to its operating segment.

The net expense for specific items attributable to DESC’s operating segment in 2019 primarily related to the impact of the following items:

• A $1.0 billion ($756 million after-tax) charge for refunds of amounts previously collected from retail electric customers for the NND Project;

• $590 million ($444 million after-tax) of charges associated with litigation;

• A $194 million tax charge for $258 million of income tax-related regulatory assets for which DESC committed to forgo recovery;

• A $114 million ($86 million after-tax) charge for utility plant primarily for which DESC committed to forgo recovery;

• $100 million ($76 million after-tax) of merger-related costs associated with the SCANA Combination, including a $79 million ($59 million after-tax) charge related to a voluntary retirement program; and 

• $66 million tax charges for changes in unrecognized tax benefits.

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The following table presents segment information pertaining to DESC’s operations:

Year Ended December 31,	Dominion Energy South Carolina		Corporate and Other			Consolidated Total
(millions)
2021
External revenue	$	3,146	$	—		$	3,146
Depreciation and amortization		486		—			486
Interest and related charges		215		(23	)		192
Income tax expense (benefit)		125		(116	)		9
Comprehensive income (loss) available (attributable) to    common shareholder		421		(212	)		209
Capital expenditures		758		—			758
Total assets (billions)		14.9		—			14.9
2020
External revenue	$	2,739	$	—		$	2,739
Depreciation and amortization		474		—			474
Interest and related charges		223		6			229
Income tax expense (benefit)		107		(36	)		71
Comprehensive income (loss) available (attributable) to    common shareholder		410		(113	)		297
Capital expenditures		742		—			742
Total assets (billions)		14.5		—			14.5
2019
External revenue	$	2,937	$	(1,008	)	$	1,929
Depreciation and amortization		452		(2	)		450
Interest and related charges		247		13			260
Income tax expense (benefit)		163		(175	)		(12	)
Comprehensive income (loss) available (attributable) to    common shareholder		408		(1,647	)		(1,239	)
Capital expenditures		497		—			497

15.  UTILITY PLANT AND NONUTILITY PROPERTY

Major classes of utility plant and other property and their respective balances at December 31, 2021 and 2020 were as follows:

At December 31,	2021		2020
(millions)
Gross utility plant:
Generation	$	6,053	$	5,921
Transmission		2,037		1,963
Distribution		5,191		4,909
Storage		76		74
General and other		601		563
Intangible		242		250
Construction work in progress		481		460
Nuclear fuel		603		575
Total gross utility plant	$	15,284	$	14,715
Gross nonutility property	$	44	$	45

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Jointly Owned Utility Plant

DESC jointly owns and is the operator of Summer. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. DESC’s share of the direct expenses of Summer is included in the corresponding operating expenses on its income statement. The units associated with the NND Project, net of impairment charges, have been reclassified from construction work in progress to a regulatory asset as a result of the decision to stop their construction. See additional discussion at Note 3. In May 2019, DESC and Santee Cooper entered into an agreement in which DESC agreed to purchase 11.7% of Santee Cooper’s ownership interest in the NND Project nuclear fuel, which will be used at Summer, for $8 million to true up the ownership percentage from the 55% ownership percentage that was applicable for the NND Project to the 66.7% ownership percentage applicable for Summer.

At December 31,	2021			2020
	Summer Unit 1			Summer Unit 1
Percent owned	66.7%			66.7%
Plant in service	$	1.6	billion	$	1.6	billion
Accumulated depreciation	$	725	million	$	702	million
Construction work in progress	$	76	million	$	62	million

Included within other receivables on the balance sheet were amounts due to DESC from Santee Cooper for its share of direct expenses. These amounts totaled $32 million at December 31, 2021 and $28 million at December 31, 2020.

Sale of Warranty Service Contract Assets

In May 2019, DESC entered into an agreement to sell certain warranty service contract assets for total consideration of $7 million. The transaction closed in August 2019, resulting in a $7 million ($5 million after-tax) gain recorded in other expense, net in DESC’s Consolidated Statements of Comprehensive Income (Loss). Pursuant to the agreement, upon closing DESC entered into a service agreement with the buyer under which the buyer will compensate DESC in connection with the right to use DESC’s brand in marketing materials and other services over a ten-year term.

16.  AFFILIATED AND RELATED PARTY TRANSACTIONS

DESC owns 40% of Canadys Refined Coal, LLC, which was involved in the manufacturing and sale of refined coal to reduce emissions at one of DESC’s generating facilities. DESC accounts for this investment using the equity method. Purchases and sales of the related coal are recorded as other income (expense), net in the Consolidated Statements of Comprehensive Income (Loss).

DESS, on behalf of itself and its parent company, provided the following services to DESC through December 2020, which were rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, DESS processed and paid invoices for DESC and was reimbursed. Effective January 2021, DES provides to DESC the services previously provided by DESS. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in other operations and maintenance – affiliated suppliers and other expense, net in the Consolidated Statements of Comprehensive Income (Loss).

DESC transacts with affiliates for certain quantities of electricity in the ordinary course of business. DESC also enters into certain commodity derivative contracts with affiliates. DESC uses these contracts, which are principally comprised of forward commodity purchases, to manage commodity price risks associated with purchases of electricity. See Note 8 for more information.

Year Ended December 31,	2021		2020		2019
(millions)
Purchases of coal from affiliate	$	—	$	—	$	121
Sales of coal to affiliate		—		—		120
Purchases of fuel used in electric generation from affiliate		—		—		43
Direct and allocated costs from DES and DESS(1)		226		294		297
Operating Revenues – Electric from sales to affiliate		4		4		4
Operating Revenues – Gas from sales to affiliate		1		1		1
Operating Expenses – Other taxes from affiliate		7		9		6
Purchases of electricity from solar affiliates		14		12		8
Demand and transportation charges from DECG - Fuel used in    electric generation		—		16		19
Demand and transportation charges from DECG - Gas purchased    for resale		—		36		44

(1)   Includes capitalized expenditures of $37 million, $81 million and $53 million for the years ended December 31, 2021, 2020 and 2019, respectively.

62

At December 31,	2021		2020
(millions)
Payable to DES and DESS		30		59
Payable to Public Service Company of North Carolina, Incorporated		—		5
Receivable from Public Service Company of North Carolina, Incorporated		60		—
Payable to solar affiliates		1		1
Receivable from nuclear affiliates		1		—
Payable to DEI		1		—
Derivative assets with affiliates(1)		28		—

(1)   Effective in the second quarter of 2021, contracts for the future purchase of certain quantities of electricity from solar affiliates no longer met the criteria for the normal purchase normal sale exception and are accounted for as derivative contracts.

Borrowings from an affiliate are described in Note 6. Certain disclosures regarding DESC’s participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 11.

17.  OTHER INCOME (EXPENSE), NET

Components of other income (expense), net are as follows:

Year Ended December 31,	2021			2020			2019
(millions)
Revenues from contracts with customers	$	—		$	1		$	4
Other income		11			13			19
Other expense		(18	)		(38	)		(57	)
Allowance for equity funds used during construction		5			1			1
Other expense, net	$	(2	)	$	(23	)	$	(33	)

 Non-service cost components of pension and other postretirement benefits are included in other expense.

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Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Senior management, including DESC’s CEO and CFO, evaluated the effectiveness of DESC’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, DESC’s CEO and CFO have concluded that DESC’s disclosure controls and procedures are effective. There were no changes in DESC’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, DESC’s internal control over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of DESC understands and accepts responsibility for DESC’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). DESC continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as DESC does throughout all aspects of its business.

DESC maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Board of Directors also serves as DESC’s Audit Committee and has periodic communications with the independent registered public accounting firm, the internal auditors and management concerning DESC’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act require DESC’s 2021 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, DESC tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2021, DESC makes the following assertions:

Management is responsible for establishing and maintaining effective internal control over financial reporting of DESC.

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Management evaluated DESC’s internal control over financial reporting as of December 31, 2021. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that DESC maintained effective internal control over financial reporting as of December 31, 2021.

This annual report does not include an attestation report of DESC’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by DESC’s independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.

February 24, 2022

Item 9B. Other Information

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

64

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Omitted pursuant to General Instructions I.(2)(c).

Item 11. Executive Compensation

Omitted pursuant to General Instructions I.(2)(c).

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Omitted pursuant to General Instructions I.(2)(c).

Item 13. Certain Relationships and Related Transactions, and Director Independence

Omitted pursuant to General Instructions I.(2)(c).

Item 14. Principal Accountant Fees and Services

The following table presents fees paid to Deloitte & Touche LLP for services related to DESC for the fiscal years ended December 31, 2021 and 2020.

Type of Fees	2021		2020
(millions)
Audit fees	$	1.54	$	1.54
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
Total Fees	$	1.54	$	1.54

Audit fees represent fees of Deloitte & Touche LLP for the audit of DESC’s annual consolidated financial statements, the review of financial statements included in DESC’s quarterly Form 10-Q reports, and the services that an independent auditor would customarily provide in connection with subsidiary audits, statutory requirements, regulatory filings, and similar engagements for the fiscal year, such as comfort letters, attest services, consents, and assistance with review of documents filed with the SEC.

Audit-related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of DESC’s consolidated financial statements or internal control over financial reporting. This category may include fees related to the performance of audits and attest services not required by statute or regulations, due diligence related to mergers, acquisitions, and investments, and accounting consultations about the application of GAAP to proposed transactions.

DESC’s Board of Directors has adopted the Dominion Energy Audit Committee pre-approval policy for its independent auditor’s services and fees and has delegated the execution of this policy to the Dominion Energy Audit Committee. In accordance with this delegation, each year the Dominion Energy Audit Committee pre-approved a schedule that details the services to be provided for the following year and an estimated charge for such services. At its December 2021 meeting, the Dominion Energy Audit Committee approved schedules of services and fees for 2022 inclusive of DESC. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the Dominion Energy Audit Committee or a delegated member of the Dominion Energy Audit Committee.

65

Part IV

Item 15. Exhibits and Financial Statement Schedules

(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.

1. Financial Statements

See Index on page 20.

2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.

3. Exhibits (incorporated by reference unless otherwise noted)

Exhibit
Number	Description
3.01	Amended and Restated Articles of Incorporation, effective April 29, 2019 (Exhibit 3.1, Form 8-K filed April 29, 2019, File No. 1-3375).
3.02	Amended and Restated Bylaws, effective April 29, 2019 (Exhibit 3.2, Form 8-K filed April 29, 2019, File No. 1-3375).
4.01	Articles of Exchange of South Carolina Electric & Gas Company and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438 and incorporated by reference herein). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
4.02	Indenture dated as of April 1, 1993 between Dominion Energy South Carolina, Inc. (formerly South Carolina Electric & Gas Company) and The Bank of New York Mellon Trust Company, N. A. (successor to NationsBank of Georgia, National Association), as trustee (Exhibit 4.1, Form S-3 Registration Statement filed January 12, 2021, File No. 333-252048).
4.03	First Supplemental Indenture dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
4.04	Second Supplemental Indenture dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
4.05	Third Supplemental Indenture dated as of September 1, 2013 (Exhibit 4.12, Amendment No. 1 to Form S-3 Registration Statement filed October 3, 2013, File No. 333-184426).
4.06	Description of Series A Nonvoting Preferred Shares (Exhibit 4.06, Form 10-K for the fiscal year ended December 31, 2019 filed February 28, 2020, File No. 1-03375).
10.01	Contract for AP1000 Fuel Fabrication and Related Services between Westinghouse Electric Company LLC and South Carolina Electric & Gas Company for V. C. Summer AP1000 Nuclear Plant Units 2 & 3 dated January 27, 2011 (portions of the exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended) (Exhibit 10.01, Form 10-Q/A for the quarter ended March 31, 2011 filed August 3, 2011, File No. 1-3375).
10.02	$6,000,000,000 Fifth Amended and Restated Revolving Credit Agreement, dated June 9, 2021, among Dominion Energy, Inc., Virginia Electric and Power Company, Questar Gas Company, Dominion Energy South Carolina, Inc., JP Morgan Chase Bank, N.A., as Administrative Agent, Mizuho Bank, Ltd., Bank of America, N.A., The Bank of Nova Scotia and Wells Fargo Bank, N.A., as Syndication Agents, J.P. Morgan Securities, LLC and Mizuho Bank, Ltd., as Co-Sustainability Structuring Agent, and other lenders named therein (Exhibit 10.1, Form 8-K filed June 10, 2021, File No. 1-3375).
10.03	DES Services Agreement, dated February 20, 2019, by and between South Carolina Electric & Gas Company and Dominion Energy Services, Inc. (Exhibit 10.04, Form 10-K for the fiscal year ended December 31, 2019 filed February 28, 2020, File No. 1-03375).
10.04	Settlement Agreement dated as of July 27, 2017, by and among Toshiba, South Carolina Electric & Gas Company and Santee Cooper (Exhibit 99.2, Form 8-K filed July 28, 2017, File No. 1-3375).
10.05	Trade Confirmation dated September 25, 2017, between South Carolina Electric & Gas Company, Santee Cooper and Citibank, N.A., and associated Assignment and Purchase Agreement, dated September 27, 2017, by and among South Carolina Electric & Gas Company, Santee Cooper and Citibank, N. A. (Exhibit 10.03, Form 10-Q for the quarter ended September 30, 2017 filed November 3, 2017, File No. 1-3375).
23	Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm for Dominion Energy South Carolina, Inc. (filed herewith).
31.a	Certification by Chief Executive Officer of Dominion Energy South Carolina, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.b	Certification by Chief Financial Officer of Dominion Energy South Carolina, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

66

Exhibit
Number	Description
32.a	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Energy South Carolina, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
101	The following financial statements from Dominion Energy South Carolina, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2021, filed on February 24, 2022, formatted in iXBRL (Inline eXtensible Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Comprehensive Income (Loss); (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Changes in Common Equity, and (v) the Notes to Consolidated Financial Statements.
104	Cover Page Interactive Data File (formatted in iXBRL (Inline eXtensible Reporting Language) and contained in Exhibit 101).

Item 16. Form 10-K Summary

None.

67

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		DOMINION ENERGY SOUTH CAROLINA, INC.
	BY:	/s/ Diane Leopold
		(Diane Leopold, Chief Executive Officer)
DATE: February 24, 2022

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 24^th day of February, 2022.

Signature	Title
/s/ Robert M. Blue	Director
Robert M. Blue
/s/ James R. Chapman	Director, Executive Vice President, Chief Financial Officer and Treasurer
James R. Chapman
/s/ Diane Leopold	Director and Chief Executive Officer
Diane Leopold
/s/ Michele L. Cardiff	Senior Vice President, Controller and Chief Accounting Officer
Michele L. Cardiff

68

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-252048 on Form S-3 of our report dated February 24, 2022, relating to the consolidated financial statements of Dominion Energy South Carolina, Inc. and affiliates, appearing in this Annual Report on Form 10-K of Dominion Energy South Carolina, Inc. for the year ended December 31, 2021.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 24, 2022

EX-31.A

Exhibit 31.a

I, Diane Leopold, certify that:

1. I have reviewed this report on Form 10-K of Dominion Energy South Carolina, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 24, 2022	/s/ Diane Leopold
	Diane Leopold Chief Executive Officer

EX-31.B

Exhibit 31.b

I, James R. Chapman, certify that:

1. I have reviewed this report on Form 10-K of Dominion Energy South Carolina, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 24, 2022	/s/ James R. Chapman
	James R. Chapman Executive Vice President, Chief Financial Officer and Treasurer

EX-32.A

Exhibit 32.a

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned officers of Dominion Energy South Carolina, Inc. (the “Company”), certify that:

1. the Annual Report on Form 10-K for the year ended December 31, 2021 (the “Report”), of the Company to which this certification is an exhibit fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of December 31, 2021, and for the period then ended.

/s/ Diane Leopold

Diane Leopold
Chief Executive Officer

February 24, 2022

/s/ James R. Chapman

James R. Chapman
Executive Vice President,
Chief Financial Officer and Treasurer
February 24, 2022

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Document and Entity Information - shares	12 Months Ended
	Dec. 31, 2021	Feb. 11, 2022
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2021
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Title of 12(g) Security	Series A Nonvoting Preferred Shares
Document Annual Report	true
Document Transition Report	false
Entity Interactive Data Current	Yes
Entity Incorporation, State or Country Code	SC
Entity Registrant Name	DOMINION ENERGY SOUTH CAROLINA, INC.
Entity Central Index Key	0000091882
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		40,296,147
Entity Current Reporting Status	Yes
Entity Shell Company	false
Entity File Number	001-3375
Entity Tax Identification Number	57-0248695
Entity Address, Address Line One	400 OTARRE PARKWAY
Entity Address, City or Town	CAYCE
Entity Address, State or Province	SC
Entity Address, Postal Zip Code	29033
City Area Code	803
Local Phone Number	217-9000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
ICFR Auditor Attestation Flag	false
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2021
Auditor Name	Deloitte & Touche LLP
Auditor Location	Richmond, Virginia
Auditor Firm ID	34

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
ASSETS
Utility plant in service	$ 14,200	$ 13,680
Accumulated depreciation and amortization	(5,192)	(5,027)
Construction work in progress	481	460
Nuclear fuel, net of accumulated amortization	216	221
Utility plant, net	9,705	9,334
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	42	39
Assets held in trust, nuclear decommissioning	256	238
Nonutility property and investments, net	298	277
Current Assets:
Cash and cash equivalents	30	5
Receivables, customer, net of allowance for uncollectible accounts	358	365
Receivables, affiliated and related party	16	16
Receivables, other	152	64
Inventories (at average cost):
Fuel	60	68
Gas storage	25	14
Materials and supplies	186	176
Prepayments	70	75
Regulatory assets	361	229
Other current assets	57	27
Total current assets	1,315	1,039
Deferred Debits and Other Assets:
Regulatory assets	3,323	3,726
Affiliated receivables	66	0
Other	220	103
Total deferred debits and other assets	3,609	3,829
Total assets	14,927	14,479
CAPITALIZATION AND LIABILITIES
Common Stock - no par value	4,016	4,017
Retained earnings	335	277
Accumulated other comprehensive income (loss)	(1)	(2)
Total common equity	4,350	4,292
Noncontrolling interest	175	192
Total Equity	4,525	4,484
Long-term debt, net	3,724	3,327
Affiliated long-term debt	230	230
Finance leases	10	15
Total long-term debt	3,964	3,572
Total capitalization	8,489	8,056
Current Liabilities:
Securities due within one year	5	39
Accounts payable	232	178
Affiliated and related party payables	458	457
Customer deposits and customer prepayments	73	70
Taxes accrued	222	215
Interest accrued	73	95
Regulatory liabilities	245	283
Reserves for litigation and regulatory proceedings	211	208
Other	144	40
Total current liabilities	1,663	1,585
Deferred Credits and Other Liabilities:
Deferred income taxes and investment tax credits	975	858
Asset retirement obligations	599	597
Pension and other postretirement benefits	164	172
Regulatory liabilities	2,936	3,005
Affiliated liabilities	0	13
Other	101	193
Total deferred credits and other liabilities	4,775	4,838
Commitments and Contingencies
Total capitalization and liabilities	$ 14,927	$ 14,479

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Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Utility plant, net	$ 9,705	$ 9,334
Receivables, customer, allowance for uncollectible accounts	5	10
Total current assets	1,315	1,039
Total deferred debits and other assets	$ 3,609	$ 3,829
Common stock, par value	$ 0	$ 0
Common stock, shares outstanding	40.3	40.3
Variable Interest Entity, Primary Beneficiary [Member]
Utility plant, net	$ 729	$ 730
Total current assets	77	103
Total deferred debits and other assets	$ 31	$ 35

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Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement [Abstract]
Operating Revenue	[1]	$ 3,146	$ 2,739	$ 1,929
Operating Expenses:
Fuel used in electric generation	[1]	646	447	573
Purchased power	[1]	116	86	54
Gas purchased for resale	[1]	285	181	216
Other operations and maintenance		417	357	388
Other operations and maintenance – affiliated suppliers		189	213	244
Impairment of assets and other charges		320	111	695
Depreciation and amortization		486	474	450
Other taxes	[1]	255	239	250
Total operating expenses		2,714	2,108	2,870
Operating income (loss)		432	631	(941)
Other expense, net		(2)	(23)	(33)
Interest charges, net of allowance for funds used during construction	[1]	192	229	260
Income (loss) before income tax expense (benefit)		238	379	(1,234)
Income tax expense (benefit)		9	71	(12)
Net Income (Loss)		229	308	(1,222)
Other Comprehensive Income:
Deferred cost of employee benefit plans, net of tax		1	1	1
Total Comprehensive Income (Loss)		230	309	(1,221)
Comprehensive Income Attributable to Noncontrolling Interest		21	12	18
Comprehensive Income (Loss) Available (Attributable) to Common Shareholder		$ 209	$ 297	$ (1,239)

[1] See Note 16 for amounts attributable to affiliates.

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Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement [Abstract]
Allowance for funds used during construction	$ 3	$ 5	$ 5
Deferred cost of employee benefit plans, tax	$ 0	$ 0	$ 0

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Consolidated Statements of Cash Flows - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Activities
Net income (loss)		$ 229	$ 308	$ (1,222)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairment of assets and other charges		311	(14)	576
Provision for refunds to electric customers		0	0	800
Gain on sale of assets		0	0	(7)
Deferred income taxes, net		117	229	(379)
Depreciation and amortization		486	474	464
Amortization of nuclear fuel		34	41	53
Other adjustments		14	25	(4)
Changes in certain assets and liabilities:
Receivables		(79)	(8)	(36)
Receivables – affiliated and related party		(15)	4	1
Inventories		(13)	14	(76)
Prepayments		13	15	(9)
Regulatory assets		(152)	21	(20)
Regulatory liabilities		(109)	(193)	265
Accounts payable		44	(19)	(54)
Accounts payable – affiliated and related party		(59)	52	(15)
Revenue subject to refund		0	0	(73)
Interest accrued		(22)	0	0
Unrecognized tax benefits		0	0	52
Taxes accrued		7	(3)	(10)
Pension and other postretirement benefits		(8)	(31)	(27)
Other assets and liabilities		(79)	97	169
Net cash provided by operating activities		719	1,012	448
Investing Activities
Property additions and construction expenditures		(758)	(742)	(497)
Proceeds from (purchases of) investments and sales of assets		7	(12)	39
Purchase of investments		(9)	15	(54)
Purchase of investments – affiliate		0	(1)	0
Short-term investments - affiliated		15	0	0
Investment in affiliate, net		0	(7)	344
Other		(5)	0	0
Net cash used in investing activities		(750)	(747)	(168)
Financing Activities
Proceeds from issuance of debt		397	0	0
Proceeds from issuance of affiliated debt		0	0	230
Repayment of long-term debt, including redemption premiums		(34)	0	(1,890)
Dividend to parent		(188)	(38)	(30)
Short-term borrowings, net		0	0	(73)
Short-term borrowings – affiliated, net		60	(219)	292
Contribution from parent		0	0	838
Return of capital to parent		(150)	0	(20)
Other		(5)	(7)	0
Net cash provided by (used in) financing activities		80	(264)	(653)
Net increase (decrease) in cash, restricted cash and equivalents		49	1	(373)
Cash, restricted cash and equivalents at beginning of period	[1]	5	4	377
Cash, restricted cash and equivalents at end of period	[1]	54	5	4
Supplemental Cash Flow Information
Cash for interest paid (net of capitalized interest)		175	176	220
Cash for income taxes paid		16	0	13
Cash for income taxes received		0	220	0
Noncash investing and financing activities:
Accrued construction expenditures	[2]	110	48	120
Leases	[3]	0	3	12
Contributed capital		$ 149	$ 322	$ 1

[1] Includes $24 million of restricted cash for the year ended December 31, 2021. For the years ended December 31, 2020 and 2019 there were no restricted cash and equivalent balances.

[2] See Note 2 for noncash investing and financing activities related to the adoption of a new accounting standard for leasing arrangements. See Note 5 for noncash financing activities related to capital contributions associated with the settlement of litigation. See Note 12 for noncash investing activities related to the property, plant and equipment conveyed to satisfy litigation.

[3] Includes $3 million and $4 million of financing leases entered into during the years ended December 31, 2020 and 2019, respectively, and $8 million of operating leases entered into during the year ended December 31, 2019.

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Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021		Dec. 31, 2020	Dec. 31, 2019
Statement Of Cash Flows [Abstract]
Cash paid for interest, capitalized interest	$ 3		$ 5	$ 5
Restricted cash and equivalents	$ 24	[1]	0	0
Financing leases			$ 3	4
Operating leases				$ 8

[1] At December 31 2020, 2019 and 2018 there were no restricted cash and equivalent balances.

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Consolidated Statements of Changes in Common Equity - USD ($) shares in Millions, $ in Millions	Total	Common Stock	Retained Earnings	Retained Earnings Cumulative Effect, Period of Adoption, Adjustment	Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Cumulative Effect, Period of Adoption, Adjustment	Noncontrolling Interest
Beginning balance at Dec. 31, 2018	$ 4,315	$ 2,860	$ 1,279	$ 1	$ (3)	$ (1)	$ 179
Beginning balance (in shares) at Dec. 31, 2018		40
Total comprehensive income (loss) available (attributable) to common shareholder	(1,221)		(1,240)		1		18
Capital contribution from parent	838	$ 835					3
Capital contribution returned to parent	(20)						(20)
Dividend to parent	(20)		(20)
Ending balance at Dec. 31, 2019	3,892	$ 3,695	20		(3)		180
Ending balance (in shares) at Dec. 31, 2019		40
Total comprehensive income (loss) available (attributable) to common shareholder	308		295		1		12
Capital contribution from parent	322	$ 322
Dividend to parent	(38)		(38)
Ending balance at Dec. 31, 2020	4,484	$ 4,017	277		(2)		192
Ending balance (in shares) at Dec. 31, 2020		40
Total comprehensive income (loss) available (attributable) to common shareholder	230		208		1		21
Capital contribution from parent	149	$ 149
Capital contribution returned to parent	(150)	(150)
Dividend to parent	(188)		(150)				(38)
Ending balance at Dec. 31, 2021	$ 4,525	$ 4,016	$ 335		$ (1)		$ 175
Ending balance (in shares) at Dec. 31, 2021		40

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Nature of Operations

12 Months Ended

Dec. 31, 2021

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Nature of Operations

1.  NATURE OF OPERATIONS

DESC is a wholly-owned subsidiary of SCANA, which is a wholly-owned subsidiary of Dominion Energy.

DESC is engaged in the generation, transmission and distribution of electricity in the central, southern and southwestern portions of South Carolina. Additionally, DESC distributes natural gas to residential, commercial and industrial customers in South Carolina.

DESC manages its daily operations through one primary operating segment: Dominion Energy South Carolina. 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.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

DESC makes certain estimates and assumptions in preparing its Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues, expenses and cash flows for the periods presented. Actual results may differ from those estimates.

DESC’s Consolidated Financial Statements include, after eliminating intercompany balances and transactions, the accounts of DESC, GENCO and Fuel Company. DESC has concluded that GENCO and Fuel Company are VIEs due to the members lacking the characteristics of a controlling financial interest. DESC is the primary beneficiary of GENCO and Fuel Company and therefore is required to consolidate the VIEs. The equity interests in GENCO and Fuel Company are held solely by SCANA, DESC’s parent. As a result, GENCO and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in the Consolidated Financial Statements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold exclusively to DESC, pursuant to a FERC approved power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Fuel Company acquires, owns and provides financing for DESC's nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 6.

Additionally, effective January 2021, DESC purchases shared services from DES, an affiliated VIE that provides accounting, legal, finance and certain administrative and technical services to all Dominion Energy subsidiaries, including DESC. DESC previously purchased such services from DESS, an affiliated VIE, that had provided such services to all SCANA subsidiaries. DESC has determined that it is not the primary beneficiary of DES as it does not have either the power to direct the activities that most significantly impact its economic performance or an obligation to absorb losses and benefits which could be significant to it. See Note 16 for amounts attributable to affiliates.

DESC reports certain contracts and instruments at fair value. See Note 9 for further information on fair value measurements.

DESC maintains pension and other postretirement benefit plans. See Note 11 for further information on these plans.

Certain amounts in the 2020 and 2019 Consolidated Financial Statements and Notes have been reclassified to conform to the 2021 presentation for comparative purposes; however, such reclassifications did not affect DESC’s net income, total assets, liabilities, equity or cash flows. Effective in the second quarter of 2021, DESC updated its Statements of Cash Flows to present net charges for allowance for credit risk and write-offs of accounts receivables within other adjustments to reconcile net income to net cash provided by operating activities from the previous presentation within changes in accounts receivable. All prior period information has been conformed to this presentation, which does not result in a change to net cash provided by operating activities.

Utility Plant

Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFUDC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense.

AFUDC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFUDC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. DESC calculated AFUDC using average composite rates of 2.6%, 2.6% and 4.3% for 2021, 2020 and 2019, respectively. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. DESC capitalizes interest on nuclear fuel in process at the actual interest cost incurred.

For property subject to cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from utility plant-in-service when it becomes probable it will be abandoned and recorded as a regulatory asset for amounts expected to be collected through future rates.

Provisions for depreciation and amortization are recorded using the straight-line method based on the estimated service lives of the various classes of property, and in most cases, include provisions for future cost of removal. The composite weighted average depreciation rates for utility plant by function were as follows:

	2021(1)			2020
Generation		2.46	%		2.50	%
Transmission		2.56	%		2.56	%
Distribution		2.48	%		2.42	%
Storage		2.85	%		2.75	%
General and other		2.27	%		3.17	%

(1) Rates include the impact of a change in depreciation rates approved in connection with the settlement of the electric base rate case, which resulted in a decrease to depreciation expense of $6 million and an expected annual decrease of $12 million.

DESC records nuclear fuel amortization using the units-of-production method, which is included in fuel used in electric generation and recovered through the fuel cost component of retail electric rates.

Major Maintenance

Planned major maintenance costs related to certain fossil fuel turbine generator equipment, nuclear refueling outages and cyclical tree trimming and vegetation management are collected in rates and accrued in periods other than when incurred in accordance with approval by the South Carolina Commission for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred.

Effective September 2021, DESC is authorized to collect $25 million annually through electric rates to offset certain turbine generator maintenance expenditures. Prior to September 2021, DESC was authorized to collect $18 million annually. For the years ended December 31, 2021 and 2020, DESC incurred $20 million and $19 million, respectively, for turbine generator maintenance.

Nuclear refueling outages are scheduled 18 months apart. As approved by the South Carolina Commission, DESC accrues $17 million annually for its portion of the nuclear refueling outages, that are scheduled to occur from the fall of 2021 through the fall of 2027 as well as unrecovered balances from the previous accrual cycle. Refueling outage costs incurred for which DESC was responsible totaled $24 million in 2021 and $23 million in 2020.

Effective September 2021, DESC implemented a tree trimming and vegetation management accrual where costs associated with cyclical tree trimming and vegetation management are accrued over the five-year operating cycle DESC seeks to maintain for such activities. As approved by the South Carolina Commission, DESC accrues $28 million annually. In 2021, DESC accrued $9 million during the period the accrual was effective and incurred costs totaling $9 million.  

Asset Retirement Obligations

DESC recognizes AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. Periodically, DESC assesses its AROs to determine if circumstances indicate that estimates of the amounts or timing of future cash flows associated with retirement activities have changed. AROs are adjusted when significant changes in the amounts or timing of future cash flows are identified. DESC reports accretion of AROs and depreciation on asset retirement costs as an adjustment to regulatory assets. 

Nuclear Decommissioning

Based on a decommissioning cost study completed in 2020, DESC’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $764 million, stated in 2021 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.

Under DESC’s method of funding decommissioning costs, DESC transfers to an external trust fund the amounts collected through rates ($3 million in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. The asset balance held in trust reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer on an after-tax basis.

Cash, Restricted Cash and Equivalents

Cash, restricted cash and equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Restricted Cash and Equivalents

Beginning in 2021, DESC holds restricted cash and equivalent balances that consists of federal assistance funds to be used towards customer bill assistance.

The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within DESC’s Consolidated Balance Sheets to the corresponding amounts reported within DESC’s Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019:

	Cash, Restricted Cash and Equivalents at End/Beginning of Year
	December 31, 2021		December 31, 2020		December 31, 2019		December 31, 2018
(millions)
Cash and cash equivalents	$	30	$	5	$	4	$	377
Restricted cash and equivalents(1)		24		—		—		—
Cash, restricted cash and equivalents shown in the    Consolidated Statements of Cash Flows	$	54	$	5	$	4	$	377

(1) At December 31 2020, 2019 and 2018 there were no restricted cash and equivalent balances.

Receivables

Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described in Note 4. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $139 million and $156 million at December 31, 2021 and 2020, respectively.

DESC sells electricity and natural gas and provides distribution and transmission services to customers in South Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of DESC’s customer base, which includes a large number of residential, commercial and industrial customers. Credit risk associated with accounts receivable is limited due to the large number of customers. DESC’s exposure to potential concentrations of credit risk results primarily from amounts due from Santee Cooper related to the jointly owned nuclear generating facility at Summer. Such receivables represented approximately 6% of DESC’s accounts receivable balance at December 31, 2021.

Inventories

Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the South Carolina Commission.

Income Taxes

A consolidated federal income tax return is filed for Dominion Energy and its subsidiaries, including DESC. In addition, where applicable, combined income tax returns for Dominion Energy, including DESC, are filed in various states including South Carolina; otherwise, separate state income tax returns are filed.

DESC participates in an intercompany tax sharing agreement with Dominion Energy. Current income taxes are based on taxable income or loss and credits determined on a separate company basis.

Under the agreements, if a subsidiary incurs a tax loss or earns a credit, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or credit or to the extent the tax loss or credit is absorbed by the taxable income of other Dominion Energy consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax asset until realized.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. DESC establishes a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. DESC did not have any valuation allowances recorded for the periods presented. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

DESC recognizes positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2021, DESC had $62 million of unrecognized tax benefits.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the Consolidated Balance Sheets and current payables are included in taxes accrued on the Consolidated Balance Sheets.

DESC recognizes interest on underpayments and overpayments of income taxes in interest expense and interest income, respectively. Penalties are also recognized in other expenses.

In 2021, DESC reflected a $21 million benefit in interest expense associated with the effective settlement of uncertain tax positions.  Interest expense for DESC was $7 million in 2020 and $18 million in 2019. Interest income for DESC was less than $1 million in both 2021 and 2020 and $2 million in 2019. In 2021, DESC recognized a $7 million benefit from the reversal of penalty expenses associated with the effective settlement of uncertain tax positions.  DESC recorded penalty expenses of $4 million in 2020 and $7 million in 2019.

At December 31, 2021, DESC had an income tax-related affiliated receivable of $24 million from Dominion Energy. This balance is expected to be received from Dominion Energy.

At December 31, 2020, DESC had an income tax-related affiliated payable of $31 million to Dominion Energy. This balance was paid to Dominion Energy in 2021.

At DESC investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.

Regulatory Assets and Liabilities

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

DESC evaluates whether or not recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on:

• Orders issued by regulatory commissions, legislation and judicial actions;

• Past experience; and

• Discussions with applicable regulatory authorities and legal counsel.

Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. See Notes 3 to the Consolidated Financial Statements for additional information.

Derivative Instruments

DESC is exposed to the impact of market fluctuations in the price of electricity and natural gas it markets and purchases, as well as interest rate risk in its business operations. DESC uses derivative instruments such as physical forwards and swaps to manage commodity and/or interest rate risks of its business operations.

All derivatives, except those for which an exception applies, are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions are reported as derivative assets. Derivative contracts representing unrealized losses are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance. See Note 9 for further information about fair value measurements and associated valuation methods for derivatives.

DESC does not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. DESC had margin assets of $11 million and $17 million associated with cash collateral at December 31, 2021 and 2020, respectively. DESC had no margin liabilities associated with cash collateral at December 31, 2021 and 2020. See Note 8 for further information about derivatives.

To manage price and interest rate risk, DESC holds derivative instruments that are not designated as hedges for accounting purposes. However, to the extent DESC does not hold offsetting position for such derivatives, it believes these instruments represent economic hedges that mitigate its exposure to fluctuations in commodity prices or interest rates. All income statement activity, including amounts realized upon settlement, is presented in operating expenses and interest charges based on the nature of the underlying risk.

Changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings. All income statement activity, including amounts realized upon settlement, is presented in operating expenses and interest charges based on the nature of the underlying risk.

DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS

In accordance with accounting guidance pertaining to derivatives and hedge accounting, DESC designates a portion of their derivative instruments as cash flow hedges for accounting purposes. For derivative instruments that are accounted for as cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.

Cash Flow Hedges- DESC uses interest rate swaps to hedge its exposure to variable interest rates on long-term debt. For transactions in which DESC is hedging the variability of cash flows, changes in the fair value of the derivatives are reported in regulatory assets or liabilities. Any derivative gains or losses reported in regulatory assets or liabilities are reclassified to earnings when the forecasted item is included in earnings. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Pursuant to regulatory orders, interest rate derivatives entered into by DESC after October 2013 were not designated for accounting purposes as cash flow hedges, and fair value changes and settlement amounts related to them have been recorded as regulatory assets and liabilities. Settlement losses on swaps generally have been amortized over the lives of subsequent debt issuances, and gains have been amortized to interest charges or have been applied as otherwise directed by the South Carolina Commission.

Debt Issuance Costs

DESC defers and amortizes debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as a reduction in long-term debt in the Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest charges. As permitted by regulatory authorities, gains or losses resulting from the refinancing or redemption of debt that are probable of recovery through future rates are deferred and amortized.

Environmental

An environmental assessment program is maintained to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred.

Statement of Operations Presentation

Revenues and expenses arising from regulated businesses are presented within Operating Income (Loss), and all other activities are presented within Other Expense, net.

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered, or contracts settled and includes amounts yet to be billed to customers. DESC collects sales, consumption, consumer utility taxes and sales taxes; however, these amounts are excluded from revenue and are recorded as liabilities until they are remitted to the respective taxing authority.

The primary types of sales and service activities reported as operating revenue for DESC are as follows:

Revenue from Contracts with Customers

• Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

• Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services; and

• Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities.

Other Revenue

• Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

DESC records refunds to customers as required by the South Carolina Commission as a reduction to regulated electric sales or regulated gas sales, as applicable. Revenues from electric and gas sales are recognized over time, as the customers of DESC consume gas and electricity as it is delivered. Sales of products and services typically transfer control and are recognized as revenue upon delivery of the product or service. The customer is able to direct the use of, and obtain substantially all of the benefits from, the product at the time the product is delivered. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. Payment for most sales and services varies by contract type, but is typically due within a month of billing.

DESC customers subject to an electric fuel cost recovery component or a PGA are billed based on a fuel or cost of gas factor calculated in accordance with cost recovery procedures approved by the South Carolina Commission and subject to adjustment periodically. Any difference between actual costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost recovery factors.

Certain amounts deferred for the WNA arise under specific arrangements with regulators rather than customers and are accounted for as an alternative revenue program. This alternative revenue is included within Other operating revenues, separate from revenue arising from contracts with customers, in the month such adjustments are deferred within regulatory accounts. As permitted, DESC has elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues.

Performance obligations which have not been satisfied by DESC relate primarily to demand or standby service for natural gas. Demand or standby charges for natural gas arise when an industrial customer reserves capacity on assets controlled by the service provider and may use that capacity to move natural gas it has acquired from other suppliers. For all periods presented, the amount of revenue recognized by DESC for these charges is equal to the amount of consideration DESC has a right to invoice and corresponds directly to the value transferred to the customer.

Leases

DESC leases certain assets including vehicles, real estate, office equipment and other assets under both operating and finance leases. For operating leases, rent expense is recognized on a straight-line basis over the term of the lease agreement, subject to regulatory framework. Rent expense associated with operating leases, short-term leases and variable leases is primarily recorded in other operations and maintenance expense in the Consolidated Statements of Comprehensive Income (Loss). Amortization expense and interest charges associated with finance leases are deferred within regulatory assets in the Consolidated Balance Sheets and amortized into the Consolidated Statements of Comprehensive Income (Loss).

Certain leases include one or more options to renew, with renewal terms that can extend the lease from one to 70 years. The exercise of renewal options is solely at DESC's discretion and is included in the lease term if the option is reasonably certain to be exercised. A right-of-use asset and corresponding lease liability for leases with original lease terms of one year or less are not included in the Consolidated Balance Sheets, unless such leases contain renewal options that DESC is reasonably certain will be exercised.

The determination of the discount rate utilized has a significant impact on the calculation of the present value of the lease liability included in the Consolidated Balance Sheets. For DESC’s leased assets, the discount rate implicit in the lease is generally unable to be determined from a lessee perspective. As such, DESC uses internally-developed incremental borrowing rates as a discount rate in the calculation of the present value of the lease liability. The incremental borrowing rates are determined based on an analysis of DESC's publicly available secured borrowing rates over various lengths of time that most closely corresponds to DESC's lease maturities.

New Accounting Standards

LEASES

In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases classified as operating leases, while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.

The guidance became effective for DESC's interim and annual reporting periods beginning January 1, 2019. DESC adopted this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. DESC applied the practical expedients, which required no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no evaluation of existing or expired land easements that were not previously accounted for as leases. In connection with the adoption of this revised accounting guidance, DESC recorded

$19 million of offsetting right-of-use assets and liabilities for operating leases in effect at the adoption date. See Note 13 for additional information.

TAX REFORM

In February 2018, the FASB issued revised accounting guidance to provide clarification on the application of the 2017 Tax Reform Act for balances recorded within AOCI. The revised guidance provides for stranded amounts within AOCI from the impacts of the 2017 Tax Reform Act to be reclassified to retained earnings. DESC adopted this guidance for interim and annual reporting periods beginning January 1, 2019 on a prospective basis. In connection with the adoption of this guidance, DESC reclassified a benefit of $1 million from AOCI to retained earnings. The amounts reclassified reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of DESC’s AOCI.

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Rate and Other Regulatory Matters

12 Months Ended

Dec. 31, 2021

Regulated Operations [Abstract]

Rate and Other Regulatory Matters

3.  RATE AND OTHER REGULATORY MATTERS

Regulatory Matters Involving Potential Loss Contingencies

As a result of issues generated in the ordinary course of business, DESC is involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for DESC to estimate a range of possible loss. For regulatory matters that DESC cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that DESC is able to estimate a range of possible loss. For regulatory matters that DESC is able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent DESC’s maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on DESC’s financial position, liquidity or results of operations.

FERC

In June 2019, DESC submitted the 2015 Task Order as a stand-alone rate schedule, which governs DESC’s provision of retail service to the DOE at the Savannah River Site. The 2015 Task Order also includes provisions that govern the operations and maintenance of certain transmission facilities, which DESC had determined to be services that are likely subject to FERC’s jurisdiction. DESC requested that FERC accept the 2015 Task Order for filing to become effective in August 2019 and accept the refund analysis included in the filing for amounts collected under the 2015 Task Order as well as under two prior task orders commencing in 1995 and each covering ten-year periods. During the second quarter of 2019, DESC recorded a $6 million ($4 million after-tax) charge primarily within interest charges in DESC’s Consolidated Statements of Comprehensive Income (Loss). In August 2019, DESC submitted a motion to withdraw the 2015 Task Order filing and related refund analysis as requested by FERC staff. As a result, DESC recorded a $10 million ($7 million after-tax) benefit, primarily within interest charges in DESC’s Consolidated Statements of Comprehensive Income (Loss) during the third quarter of 2019, to remove previously recorded reserves.

2017 Tax Reform Act

DESC’s provision of electric transmission service is pursuant to a FERC approved formula rate. In December 2019, FERC issued an order requiring transmission providers with transmission formula rates to account for the impacts of the 2017 Tax Reform Act on rates charged to customers. The order requires companies to include a mechanism to decrease or increase their income tax allowances to account for the 2017 Tax Reform Act and any other future changes in tax law, and to submit annual information reflecting the amortization of these excess deferred income taxes. DESC submitted a proposed update to its formula rate to FERC in May 2020. This matter is pending.

Other Regulatory Matters

South Carolina Electric Base Rate Case

In August 2020, DESC filed its retail electric base rate case and schedules with the South Carolina Commission. DESC proposed a non-fuel, base rate increase of $178 million, or 7.75% based on an adjusted test year data, effective on or after the first billing cycle of March 2021. The base rate increase was proposed to recover the significant investment in assets and operating resources required to serve an expanding customer base, maintain the safety, reliability and efficiency of DESC’s system and meet increasingly stringent reliability, security and environmental requirements for the benefit of South Carolina customers.  DESC presented an earned ROE of 5.90% based upon a fully-adjusted test period. The proposed rates would provide for an earned ROE equal to the current authorized earned ROE of 10.25% established in the previous rate case in 2012.  In January 2021, the South Carolina Commission approved a proposal made by the South Carolina Office of Regulatory Staff, and agreed to by DESC and other intervenors, to stay the base rate case due to the current economic conditions and to allow the parties more time to negotiate a settlement with a final order to be issued no later than August 2021.

In July 2021, DESC, the South Carolina Office of Regulatory Staff and other parties of record filed a comprehensive settlement agreement with the South Carolina Commission for approval. The comprehensive settlement agreement provides for a non-fuel, base rate increase of $62 million (resulting in a net increase of $36 million after considering an accelerated amortization of certain excess deferred income taxes) commencing with bills issued on September 1, 2021 and an authorized earned ROE of 9.50%. Additionally, DESC has agreed to commit up to $15 million to forgive retail electric customer balances that were more than 60 days past due as of May 31, 2021, and provide $15 million for energy efficiency upgrades and critical health and safety repairs to customer homes. Pursuant to the comprehensive settlement agreement, DESC would not file a retail electric base rate case prior to July 1, 2023, such that new rates would not be effective prior to January 1, 2024, absent unforeseen extraordinary economic or financial conditions that

may include changes in corporate tax rates. In July 2021, the South Carolina Commission voted to approve the comprehensive settlement agreement and issued its final order in August 2021.

In connection with this matter, DESC recorded charges of $249 million ($187 million after-tax) reflected within impairment of assets and other charges, including $237 million of regulatory assets associated with DESC’s purchases of its first mortgage bonds during 2019 that are no longer probable of recovery under the settlement agreement, and $18 million ($14 million after-tax) reflected within other income in its Consolidated Statements of Income for the year ended December 31, 2021.

Electric – Cost of Fuel

DESC’s retail electric rates include a cost of fuel component approved by the South Carolina Commission which may be adjusted periodically to reflect changes in the price of fuel purchased by DESC.

In February 2021, DESC filed with the South Carolina Commission a proposal to increase the total fuel cost component of retail electric rates. DESC’s proposed adjustment would increase annual base fuel component recoveries by approximately $36 million and is designed to recover DESC’s current base fuel costs, net of the existing over-collected balance, over the 12-month period beginning with the first billing cycle of May 2021. In addition, DESC proposed a decrease to its variable environmental component and an increase to its distributed energy resource component. In April 2021, the South Carolina Commission approved the filing.

In February 2022, DESC filed with the South Carolina Commission a proposal to increase the total fuel cost component of retail electric rates. DESC’s proposed adjustment is designed to recover DESC’s current base fuel costs, including its existing under-collected balance, over the 12-month period beginning with the first billing cycle of May 2022. DESC also proposed to apply $66 million representing the net balance of funds associated with the monetization of the bankruptcy settlement with Toshiba Corporation following the satisfaction of liens against NND Project property recorded in regulatory liabilities, as a reduction to its under-collected base fuel cost balance. In addition, DESC proposed an increase to its variable environmental and avoided capacity cost component. The net effect is a proposed annual increase of $143 million. This matter is pending.

Electric – Other

DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2021, DESC filed an application with the South Carolina Commission seeking approval to recover $48 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. In April 2021, the South Carolina Commission approved the filing. In connection with the approval of the comprehensive settlement agreement in the South Carolina base rate case discussed above, the net lost revenue component of the DSM rider was adjusted resulting in a recovery of $43 million commencing with bills issued on September 1, 2021.

In January 2022, DESC filed an application with the South Carolina Commission seeking approval to recover $60 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. This matter is pending.

DESC utilizes a pension costs rider approved by the South Carolina Commission which is designed to allow recovery of projected pension costs, including under-collected balances or net of over-collected balances, as applicable. The rider is typically reviewed for adjustment every 12 months with any resulting increase or decrease going into effect beginning with the first billing cycle in May. In February 2021, DESC requested that the South Carolina Commission approve an adjustment to this rider to decrease annual revenue by less than $1 million. In April 2021, the South Carolina Commission approved the filing. In February 2022, DESC requested that the South Carolina Commission approve an adjustment to this rider to decrease annual revenue by $12 million. This matter is pending.

Natural Gas Rates

In June 2021, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 2021 with a total revenue requirement of $426 million. This represents a $9 million overall annual increase to its natural gas rates under the terms of the RSA effective with the first billing cycle of November 2021. In October 2021, the South Carolina Commission issued an order approving a total revenue requirement of $424 million effective with the first billing cycle of November 2021. This represents a $7 million overall annual increase to DESC’s natural gas rates.

In November 2021, DESC filed an application with the South Carolina Commission seeking approval to create DSM programs for DESC's residential and commercial natural gas customers and a new rider to retail gas rates for the recovery of the associated program costs and a shared savings incentive of 9.9%. The application also includes a notice of intent that DESC would seek to recover the net lost revenues resulting from the proposed DSM programs through the annual RSA proceeding. This matter is pending.

DESC's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. DESC’s gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the South Carolina Commission.

Regulatory Assets and Regulatory Liabilities

Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises. As a result, DESC has recorded regulatory assets and regulatory liabilities which are summarized in the following table. Except for NND Project costs and certain other unrecovered plant costs, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

At December 31,	2021		2020
(millions)
Regulatory assets:
NND Project costs(1)	$	138		138
Deferred employee benefit plan costs(2)		8		9
Other unrecovered plant(3)		16		14
DSM programs(4)		23		29
AROs(5)		2		2
Cost of fuel and purchased gas under-collections(6)		126		1
Other		48		36
Regulatory assets - current		361		229
NND Project costs(1)		2,226		2,364
AROs(5)		311		309
Cost of reacquired debt(7)		10		243
Deferred employee benefit plan costs(2)		106		159
Deferred losses on interest rate derivatives(8)		295		308
Other unrecovered plant(3)		57		61
DSM programs(4)		45		46
Environmental remediation costs(9)		30		20
Deferred storm damage costs(10)		38		45
Deferred transmission operating costs(11)		77		63
Other(12)		128		108
Regulatory assets - noncurrent		3,323		3,726
Total regulatory assets	$	3,684	$	3,955
Regulatory liabilities:
Monetization of guaranty settlement(13)	$	67		67
Income taxes refundable through future rates(14)		42		21
Reserve for refunds to electric utility customers(15)		113		128
Cost of fuel and purchased gas over-collections(6)		—		58
Derivatives(16)		18		—
Other		5		9
Regulatory liabilities - current		245		283
Monetization of guaranty settlement(13)		831		903
Income taxes refundable through future rates(14)		903		919
Asset removal costs(17)		570		564
Deferred gains on interest rate derivatives(8)		67		69
Reserve for refunds to electric utility customers(15)		425		540
Derivatives(16)		131		—
Other		9		10
Regulatory liabilities - noncurrent		2,936		3,005
Total regulatory liabilities	$	3,181	$	3,288

(1) Reflects expenditures associated with the NND Project, which pursuant to the SCANA Merger Approval Order, will be recovered from electric service customers over a 20-year period ending in 2039. See Note 12 for more information.

(2) Employee benefit plan costs have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific South Carolina Commission regulatory orders. DESC expects to recover deferred pension costs through utility rates over periods through 2044. DESC expects to recover other deferred benefit costs through utility rates, primarily over average service periods of participating employees up to 11 years.

(3) Represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. DESC is amortizing these amounts through cost of service rates following depreciation amounts that were designed to recover the retired units cost over their previous estimated remaining useful lives, which has been estimated to be through 2025. Based on current projections of remaining decommissioning costs, projected recovery is expected to extend through 2029. In addition, amounts include unrecovered costs of existing meters and equipment retired from service prior to being fully depreciated as part of the Advanced Metering Infrastructure project, which are being recovered through rates through 2028. This amount also includes certain inventory and preliminary survey and investigation charges being amortized over five years related to the transition or conversion from coal to gas fired generation at certain facilities. Unamortized amounts are included in rate base and are earning a current return.

(4) Represents deferred costs associated with electric demand reduction programs, and such deferred costs are currently being recovered over three years through an approved rate rider.

(5) Represents deferred depreciation and accretion expense related to legal obligations associated with the future retirement of generation, transmission and distribution properties. The AROs primarily relate to DESC’s electric generating facilities, including Summer, and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 105 years.

(6) Represents amounts under- or over-collected from customers pursuant to the cost of fuel components approved by the South Carolina Commission.

(7) In 2021, DESC recorded a charge of $237 million ($178 million after-tax) in impairment of assets and other charges, reflected in the Corporate and Other segment, to write-off the balance of a regulatory asset that is no longer probable of recovery under the settlement agreement approved in DESC’s retail electric base rate case. See South Carolina Electric Base Rate Case discussed above for more information.

(8) Represents (i) the changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043.The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065.

(9) Reflects amounts associated with the assessment and clean-up of sites currently or formerly owned by DESC. Such remediation costs are expected to be recovered over periods of up to 22 years. See Note 12 for more information.

(10) Represents storm restoration costs for which DESC expects to receive future recovery through customer rates over approximately 10 years pursuant to the settlement agreement approved in DESC’s retail electric base rate case. Unamortized amounts are included in rate base and are earning a current return.

(11) Includes deferred depreciation and property taxes associated with certain transmission assets for which DESC expects recovery from customers through future rates over approximately 42 years pursuant to the settlement agreement approved in DESC’s retail electric base rate case. Unamortized amounts are included in rate base and earning a current return. See Note 12 for more information.

(12) Various other regulatory assets are expected to be recovered through rates over varying periods through 2047.

(13) Represents proceeds related to the monetization of the Toshiba Settlement. In accordance with the SCANA Merger Approval Order, this balance, net of amounts that may be required to satisfy liens, will be refunded to electric customers over a 20-year period ending in 2039. See Note 12 for more information.

(14) Includes (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the 2017 Tax Reform Act (certain of which are protected under normalization rules and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over prescribed periods as instructed by regulators) and (ii) deferred income taxes arising from investment tax credits, offset by (iii) deferred income taxes that arise from utility operations that have not been included in customer rates (a portion of which relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to 85 years). See Note 7 for more information.

(15) Reflects amounts previously collected from retail electric customers of DESC for the NND Project to be credited to customers over an estimated 11-year period effective February 2019 in connection with the SCANA Merger Approval Order. See Note 12 for more information.

(16) For jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

(17) Represents estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.

Regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under GAAP for regulated operations. The South Carolina Commission or the FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by one of these regulatory agencies, including deferred transmission operating costs that are the subject of regulatory proceedings as discussed in Note 12. While such costs are not currently being recovered, management believes that they would be allowable under existing rate-making concepts embodied in rate orders or applicable state law and expects to recover these costs through rates in future periods.

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Operating Revenue

12 Months Ended

Dec. 31, 2021

Revenues [Abstract]

Operating Revenue

4.  OPERATING REVENUE

DESC’s operating revenue consists of the following:

Year Ended December 31,	2021				2020
(millions)	Electric		Gas		Electric		Gas
Customer class:
Residential	$	1,211	$	245	$	1,127	$	201
Commercial		834		133		746		103
Industrial		424		103		341		65
Other		157		25		123		18
Revenues from contracts with customers		2,626		506		2,337		387
Other revenues		13		1		15		—
Total Operating Revenues	$	2,639	$	507	$	2,352	$	387

Contract liabilities represent the obligation to transfer goods or services to a customer for which consideration has already been received from the customer. DESC had contract liability balances of $8 million and $5 million at December 31, 2021 and 2020, respectively. For the years ended December 31, 2021 and 2020, DESC recognized revenue of $4 million and $6 million, respectively, from the beginning contract liability balances as DESC fulfilled its obligations to provide service to its customers. Contract liabilities are recorded in customer deposits and customer prepayments in the Consolidated Balance Sheets.

Contract Costs

Costs to obtain contracts are generally expensed when incurred. In limited instances, DESC provides economic development grants intended to support economic growth within DESC’s electric service territory and defers such grants as regulatory assets on the Consolidated Balance Sheets. Whenever these grants are contingent on a customer entering into a long-term electric supply contract with DESC, they are considered costs to obtain that underlying contract. Such costs that exceed certain thresholds are deferred and amortized on a straight-line basis over the term of the related service contract, which generally ranges from ten to 15 years.

Balances and activity related to contract costs deferred as regulatory assets were as follows:

	Regulatory Assets
(millions)	2021			2020
Beginning balance, January 1	$	12		$	13
Amortization		(1	)		(1	)
Ending balance, December 31	$	11		$	12

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Equity

12 Months Ended

Dec. 31, 2021

Stockholders Equity Note [Abstract]

Equity

5.  EQUITY

For all periods presented, DESC's authorized shares of common stock, no par value, were 50 million, of which 40.3 million were issued and outstanding, and DESC's authorized shares of preferred stock, no par value, were 20 million, of which 1,000 shares were issued and outstanding. All outstanding shares of common and preferred stock are held by SCANA.

In 2021, Dominion Energy issued $104 million of shares of Dominion Energy common stock to satisfy DESC’s obligation under a settlement agreement for the FILOT litigation discussed in Note 12. Additionally, in 2021, Dominion Energy issued $45 million of shares of Dominion Energy common stock to satisfy DESC’s obligation for the initial payment under a settlement agreement with the SCDOR discussed in Note 12. In connection with these transactions, DESC recorded equity contributions from Dominion Energy.

In 2021, DESC returned $150 million of capital previously contributed from SCANA which had been funded by Dominion Energy.

In 2020, Dominion Energy issued $322 million of shares of Dominion Energy common stock in accordance with the settlement agreement associated with the Santee Cooper Ratepayer Case, as discussed in Note 12. In connection with this transaction, DESC recorded an equity contribution from Dominion Energy.

In 2019, DESC received equity contributions of $835 million from SCANA which were funded by Dominion Energy. DESC primarily used these funds to redeem long-term debt and to repay intercompany credit agreement borrowings from Dominion Energy. See Note 6.

DESC’s bond indenture under which it issues first mortgage bonds contains provisions that could limit the payment of cash dividends on its common stock. DESC's bond indenture permits the payment of dividends on DESC's common stock only either (1) out of its Surplus (as defined in the bond indenture) or (2) in case there is no Surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, pursuant to the SCANA Merger Approval Order, the amount of any DESC dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry.

At December 31, 2021, DESC’s retained earnings exceed the balance established by the Federal Power Act as a reserve on earnings attributable to hydroelectric generation plants. As a result, DESC is permitted to pay dividends without additional regulatory approval provided that such amounts would not bring the retained earnings balance below the established threshold.

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Long-Term and Short-Term Debt

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Long-Term and Short-Term Debt

6.  LONG-TERM AND SHORT-TERM DEBT

Long-term debt by type with related weighted-average coupon rates and maturities at December 31, 2021 and 2020 is as follows:

At December 31,	2021 Weighted- average Coupon(1)			2021			2020
(millions, except percentages)
DESC:
First Mortgage Bonds, 2.30% to 6.625%, due 2021 to 2065		5.09	%	$	3,634		$	3,267
Tax-Exempt Financings:(2)
Variable rate due 2038		0.14	%		35			35
3.625% and 4.00%, due 2028 and 2033		3.90	%		54			54
Other		3.65	%		1			1
GENCO:
Tax-Exempt Financing, variable rate due 2038		0.14	%		33			33
Affiliated note, 3.05% due 2024		3.05	%		230			230
Total principal					3,987			3,620
Securities due within one year					—			(33	)
Unamortized discount, premium and debt issuance costs, net					(33	)		(30	)
Finance leases					10			15
Total long-term debt				$	3,964		$	3,572

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2021.

(2) Industrial revenue bonds totaling $68 million are secured by letters of credit that expire, subject to renewal, in the fourth quarter of 2022.

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2021, were as follows:

(millions, except percentages)	2022		2023		2024			2025		2026		Thereafter			Total
First Mortgage Bonds	$	—	$	—	$	—		$	—	$	—	$	3,634		$	3,634
Tax-Exempt Financings		—		—		—			—		—		122			122
Other		—		—		230			—		—		1			231
Total	$	—	$	—	$	230		$	—	$	—	$	3,757		$	3,987
Weighted-average coupon						3.05	%						4.99	%

Substantially all of DESC’s electric utility plant is pledged as collateral in connection with long-term debt.

DESC is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice the annual interest requirements on all outstanding Bonds and Bonds to be issued (Bond Ratio). For the year ended December 31, 2021, the Bond Ratio was approximately 6.

Long-Term Debt – Affiliate

In May 2019, GENCO issued a $230 million 3.05% promissory note due to Dominion Energy that matures in May 2024. The issuance by GENCO was approved by the South Carolina Commission. Proceeds from the issuance were used to redeem GENCO’s 5.49% senior secured notes due in 2024 at the remaining principal outstanding of $33 million plus accrued interest, repay money pool borrowings and to return $20 million of contributed equity capital to SCANA.

Short-Term Debt

DESC's short-term financing is supported through its access as co-borrower to Dominion Energy’s $6.0 billion joint revolving credit facility, which can be used for working capital, as support for the combined commercial paper programs of DESC, Dominion Energy, Virginia Power and Questar Gas, and for other general corporate purposes.

DESC's share of commercial paper and letters of credit outstanding under its joint credit facility with Dominion Energy, were as follows:

(millions)	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit
At December 31, 2021
Joint revolving credit facility(1)	$	1,000	$	—	$	—
At December 31, 2020
Joint revolving credit facility(1)	$	1,000	$	—	$	—

(1) A maximum of $1.0 billion of the facility is available to DESC, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. A sub-limit for DESC is set within the facility limit but can be changed at the option of the co-borrowers multiple times per year. At December 31, 2021, the sub-limit for DESC was $500 million. If DESC has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term borrowings from DESC's parent or from Dominion Energy. This credit facility matures in June 2026, with the potential to be extended by the borrowers to June 2028. The credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.0 billion (or the sub-limit, whichever is less) of letters of credit.  

In January 2021, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization. In March 2021, FERC granted DESC authority through March 2023 to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act) in amounts not to exceed $2.2 billion outstanding with maturity dates of one year or less. In addition, in March 2021, FERC granted GENCO authority through March 2023 to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less.

DESC is obligated with respect to an aggregate of $68 million of industrial revenue bonds which are secured by letters of credit. These letters of credit expire, subject to renewal, in the fourth quarter of 2022.

DESC has FERC approval to enter into an inter-company credit agreement with Dominion Energy under which DESC may have short-term borrowings outstanding up to $900 million. At December 31, 2021 and 2020, DESC had borrowings outstanding under this credit agreement totaling $415 million and $149 million, respectively, which are recorded in affiliated and related party payables in DESC’s Consolidated Balance Sheets. For the twelve months ended December 31, 2021 and 2020, DESC recorded interest charges of less than $1 million and $7 million, respectively.

Fuel Company and GENCO participated in a SCANA utility money pool until January 2021, when that utility money pool was closed. Money pool borrowings and investments bore interest at short-term market rates. For the years ended December 31, 2021 and 2020, DESC recorded interest income from money pool transactions of less than $1 million and $2 million, respectively, and for the same periods DESC recorded interest expense from money pool transactions of less than $1 million and $2 million, respectively. At December 31, 2020, DESC had outstanding money pool borrowings due to an affiliate of $206 million and investments due from an affiliate of $15 million. On its Consolidated Balance Sheets, DESC includes money pool borrowings within affiliated and related party payables and money pool investments within affiliated and related party receivables.

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Income Taxes

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Income Taxes

7.  INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. DESC is routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

As indicated in Note 2, DESC’s operations, including accounting for income taxes, are subject to regulatory accounting treatment. For regulated operations, many of the changes in deferred taxes represent amounts probable of collection from or refund to customers, and were recorded as either an increase to a regulatory asset or liability. See Note 3 for more information and current year developments.

Details of income tax expense for continuing operations including noncontrolling interests were as follows:

Year Ended December 31,	2021			2020			2019
(millions)
Current:
Federal	$	(52	)	$	(139	)	$	—
State		(39	)		3			34
Total current expense (benefit)		(91	)		(136	)		34
Deferred:
Federal
Taxes before operating loss carryforwards, investment tax credits and tax reform		61			158			(90	)
Tax utilization expense of operating loss carryforwards		34			33			102
State		7			17			(57	)
Total deferred expense (benefit)		102			208			(45	)
Investment tax credit-amortization		(2	)		(1	)		(1	)
Total income tax expense (benefit)	$	9		$	71		$	(12	)

Subsequent to the SCANA Combination, DESC’s annual utilization of its net operating losses are restricted by the tax law, however in certain circumstances the utilization may be increased if SCANA recognizes built-in gains on certain sales of assets. In December 2019, SCANA recognized a gain on the sale of SEMI’s assets to Dominion Energy, which increased the amount of DESC’s 2019 net operating loss utilization by approximately $79 million.

For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to DESC’s effective income tax rate as follows:

Year Ended December 31,	2021			2020			2019
U.S. statutory rate		21.0	%		21.0	%		21.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		5.6			4.2			3.9
AFUDC - equity		(0.4	)		(0.1	)		—
Amortization of federal investment tax credits		(0.6	)		(0.4	)		0.1
Production tax credits		—			—			0.4
Reversal of excess deferred income taxes		(8.1	)		(6.0	)		(1.4	)
NND Project impairment		—			—			(2.4	)
Write-off of regulatory asset		—			—			(15.8	)
Changes in unrecognized tax benefits		(15.8	)		—			(5.1	)
Prior period adjustments		1.6			—			—
Other		0.5			0.1			0.2
Effective tax rate		3.8	%		18.8	%		0.9	%

At DESC, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, which in some cases will be 35%. DESC has recorded an estimate of the portion of excess deferred income tax amortization in 2021, and changes in estimates of amounts probable of collection from or return to customers because of actions by our regulators. The reversal of these excess deferred income taxes will impact the effective tax rate, and rates charged to customers. See Note 3 for current year developments.

In December 2021, unrecognized tax benefits related to several state uncertain tax positions were effectively settled through negotiations with the taxing authority.  Management believed it was reasonably possible these unrecognized tax benefits could

decrease through settlement negotiations or payments during 2021, however no income tax benefits could be recognized unless or until the positions were effectively settled.  Resolution of these uncertain tax positions decreased income tax expense by $38 million.

In connection with the SCANA Combination, Dominion Energy committed to forgo, or limit, the recovery of certain income tax-related regulatory assets associated with the NND Project. DESC’s effective tax rate reflects deferred income tax expense of $194 million in satisfaction of this commitment. In addition, DESC recorded deferred income tax expense of $30 million with a corresponding increase to regulatory liabilities by $40 million and deferred tax assets by $10 million related to adjustments of amounts probable of return to customers on the nuclear project.

DESC’s deferred income taxes consist of the following:

At December 31,	2021			2020
(millions)
Deferred income taxes:
Total deferred income tax assets	$	1,015		$	1,101
Total deferred income tax liabilities		1,974			1,941
Total net deferred income tax liabilities	$	959		$	840
Total deferred income taxes:
Depreciation method and plant basis differences	$	1,139		$	1,098
Excess deferred income taxes		(228	)		(233	)
Unrecovered nuclear plant cost		508			529
DESC rate refund		(113	)		(140	)
Toshiba settlement		(189	)		(204	)
Nuclear decommissioning		(54	)		(51	)
Deferred state income taxes		226			208
Federal benefit of deferred state income taxes		(47	)		(44	)
Deferred fuel, purchased energy and gas costs		27			(12	)
Pension benefits		35			39
Other postretirement benefits		(35	)		(37	)
Loss and credit carryforwards		(343	)		(382	)
Other		33			69
Total net deferred income tax liabilities	$	959		$	840
Deferred Investment Tax Credits-Regulated Operations		16			18
Total Deferred Taxes and Deferred Investment Tax Credits	$	975		$	858

At December 31, 2021, DESC had the following deductible loss and credit carryforwards:

(millions)	Deductible Amount		Deferred Tax Asset		Expiration Period
Federal losses	$	890	$	187	2037
Federal production and other credits		—		29	2035-2041
State losses		2,617		131	2037-2040
State investment and other credits		—		27	2026-2031
Total	$	3,507	$	374

A reconciliation of changes in DESC’s unrecognized tax benefits follows:

(millions)	2021			2020		2019
Balance at January 1	$	138		$	132	$	106
Increases-prior period positions		6			5		76
Decreases-prior period positions		(57	)		—		(53	)
Increases-current period positions		1			1		3
Settlements with tax authorities		(26	)		—		—
Balance at December 31	$	62		$	138	$	132

Throughout 2019, the evaluation of federal and state income tax positions taken in DESC’s tax returns prior to the SCANA Combination increased unrecognized tax benefits by $79 million and increased income tax expense by $67 million. In the fourth quarter of 2019, DESC also remeasured its beginning unrecognized tax benefits by $53 million. These changes were offset by a $45 million reduction in credit carryforward deferred tax assets and a $7 million increase to accrued taxes resulting in a $1 million benefit to income tax expense.

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. If recognized, all the unrecognized tax benefits would impact the effective tax rate.

The statute is closed for IRS examination of years prior to 2013. The IRS is currently examining DESC’s federal returns from 2013 through 2017. DESC is no longer subject to state and local income tax examinations by tax authorities for years prior to 2018.

It is reasonably possible that these unrecognized tax benefits may decrease by $13 million within the next twelve months. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could increase by less than $1 million. Otherwise, with regard to 2021 and prior years, DESC cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2022.

DESC is also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if DESC utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are generally subject to examination.

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2021

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

8.  DERIVATIVE FINANCIAL INSTRUMENTS

See Note 2 for DESC’s accounting policies, objectives, and strategies for using derivative instruments. See Note 9 for further information about fair value measurements and associated valuation methods for derivatives.

Derivative assets and liabilities are presented gross on DESC’s Consolidated Balance Sheets. DESC’s derivative contracts include over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter contracts contain contractual rights of setoff through master netting arrangements and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency, or other conditions.

In general, most over-the-counter transactions are subject to collateral requirements. Types of collateral for over-the-counter contracts include cash, letters of credit, and, in some cases, other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities.

Certain of DESC’s derivative instruments contain credit-related contingent provisions. These provisions require DESC to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying the instruments that are in a liability position and not fully collateralized with cash were fully triggered as of December 31, 2021 and 2020, DESC would have been required to post $8 million and $10 million, respectively, of additional collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. DESC had posted $11 million and $1 million, respectively, of collateral at December 31, 2021 and 2020 related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of December 31, 2021 and 2020 was $19 million and $11 million, respectively, which does not include the impact of any offsetting asset positions.

The table below presents derivative balances by type of financial instrument, if the gross amounts recognized in the Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid. DESC’s commodity derivative assets are not subject to a master netting agreement or similar arrangement.

	December 31, 2021								December 31, 2020
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
(millions)	Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
Interest rate contracts:
Over-the-counter	$	19	$	—	$	11	$	8	$	27	$	—	$	17	$	10
Total derivatives	$	19	$	—	$	11	$	8	$	27	$	—	$	17	$	10

Volumes

The following table presents the volume of derivative activity at December 31, 2021. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions.

	Current		Noncurrent
Electricity (MWh in millions):
Fixed price		2		23
Interest rate(1) (in millions)	$	—	$	71

(1)   Maturity is determined based on final settlement period.

Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of derivatives and where they are presented in the Consolidated Balance Sheets:

(millions)	Fair Value - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
At December 31, 2021
Current Assets
Commodity	$	—	$	18	$	18
Total current derivative assets (1)		—		18		18
Noncurrent Assets
Commodity		—		130		130
Total noncurrent derivative assets (2)		—		130		130
Total derivative assets	$	—	$	148	$	148
Current Liabilities
Interest rate	$	1	$	1	$	2
Total current derivative liabilities(3)		1		1		2
Noncurrent Liabilities
Interest rate		11		6		17
Total noncurrent derivative liabilities(4)		11		6		17
Total derivative liabilities	$	12	$	7	$	19
At December 31, 2020
Current Liabilities
Interest rate	$	1	$	1	$	2
Total current derivative liabilities(3)		1		1		2
Noncurrent Liabilities
Interest rate		15		10		25
Total noncurrent derivative liabilities(4)		15		10		25
Total derivative liabilities	$	16	$	11	$	27

(1)   Current derivative assets are presented in other current assets in DESC’s Consolidated Balance Sheets.

(2) Noncurrent derivative assets are presented in other deferred debits and other assets in DESC’s Consolidated Balance Sheets.

(3)   Current derivative liabilities are presented in other current liabilities in DESC’s Consolidated Balance Sheets.

(4)  Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in DESC’s Consolidated Balance Sheets.

The following tables present the gains and losses on derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Comprehensive Income (Loss):

Derivatives in Cash Flow Hedging Relationships

(millions)	Increase (Decrease) in Derivatives Subject to Regulatory Treatment(1)
Year Ended December 31, 2021
Derivative type and location of gains (losses):
Interest rate	$	9
Total	$	9
Year Ended December 31, 2020
Derivative type and location of gains (losses):
Interest rate	$	1
Total	$	1
Year Ended December 31, 2019
Derivative type and location of gains (losses):
Interest rate	$	1
Total	$	1

(1)   Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/ liabilities have no associated effect in the Consolidated Statements of Comprehensive Income (Loss).

Derivatives Not designated as Hedging Instruments

(millions)	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2021			2020			2019
Derivative type and location of gains (losses):
Commodity contracts:
Purchased power	$	8			—			—
Interest rate contracts:
Interest charges		(2	)		(1	)		(1	)
Total	$	6		$	(1	)	$	(1	)

(1)   Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in the Consolidated Statements of Comprehensive Income (Loss).

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Fair Value Measurements, Including Derivatives

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Fair Value Measurements, Including Derivatives

9.  FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of DESC’s own nonperformance risk on its liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). DESC applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments. DESC applies credit adjustments to its derivative fair values in accordance with the requirements described above.

Inputs and Assumptions

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including industry publications, and to a lesser extent, broker quotes. When evaluating pricing information provided by Designated Contract Market settlement pricing, other pricing services, or brokers, DESC considers the ability to transact at the quoted price, i.e. if the quotes are based on an active market or an inactive market and to the extent which pricing models are used, if pricing is not readily available. If pricing information from external sources is not available, or if DESC believes that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases the unobservable inputs are developed and substantiated using historical information, available market data, third-party data and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships and changes in third-party sources.

The inputs and assumptions used in measuring fair value include the following:

For commodity derivative contracts:

• Forward commodity prices

• Transaction prices

• Volumes

• Commodity location

• Interest rates

• Credit quality of counterparties and DESC

• Credit enhancements

• Time value

For interest rate derivative contracts:

• Interest rate curves

• Credit quality of counterparties and DESC

• Notional value

• Credit enhancements

• Time value

Levels

DESC utilizes the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

• Level 1-Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date.

• Level 2-Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include interest rate swaps.

• Level 3-Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for DESC consist of long-dated commodity derivatives.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

Level 3 Valuations

DESC enters into physical forwards contracts, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical forwards contracts. The discounted cash flow model for forwards calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. For Level 3 fair value measurements, certain forward market prices are considered unobservable.

The following table presents DESC’s quantitative information about Level 3 fair value measurements at December 31, 2021. The range and weighted average are presented in dollars for market price inputs.

	Fair Value (millions)		Valuation Techniques	Unobservable Input	Range	Weighted Average(1)
Assets
Physical forwards:
Electricity	$	148	Discounted cash flow	Market price (per MWh)(2)	28-74	43
Total assets	$	148

(1)   Averages weighted by volume.

(2)   Represents market prices beyond defined terms for Levels 1 and 2.

Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)

Nonrecurring Fair Value Measurement

During the third quarter of 2020, DESC determined that certain of its nonutility property was impaired and recorded a $12 million charge ($9 million after-tax) within impairments and other charges in its Consolidated Statements of Comprehensive Income (Loss) to adjust the property down to its estimated fair value of $6 million. The fair value determinations are considered Level 2 fair value measurements due to the use of real estate appraised values.

Recurring Fair Value Measurements

Fair value disclosures for assets held in DESC’s pension plan are presented in Note 11.

The following table presents DESC’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:

	Level 1		Level 2		Level 3		Total
(millions)
At December 31, 2021
Assets
Commodity	$	—	$	—	$	148	$	148
Total assets	$	—	$	—	$	148	$	148
Liabilities
Interest rate	$	—	$	19	$	—	$	19
Total liabilities	$	—	$	19	$	—	$	19
At December 31, 2020
Liabilities
Interest rate	$	—	$	27	$	—	$	27
Total liabilities	$	—	$	27	$	—	$	27

The following table presents the net change in DESC's assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category. There were no net changes in assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category for the year ended December 31, 2020.

	2021
(millions)
Balance at January 1,	$	—
Total realized and unrealized gains (losses):
Included in earnings:
Purchased power		8
Included in regulatory assets/liabilities		148
Settlements		(8	)
Balance at December 31,	$	148

There are no unrealized gains and losses included in earnings in the Level 3 fair value category related to assets/liabilities still held at the reporting date for the year ended December 31, 2021.

Fair Value of Financial Instruments

Substantially all of DESC’s financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of financial instruments classified within current assets and current liabilities are representative of fair value because of the short-term nature of these instruments. For financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:

At December 31,	2021				2020
(millions)	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
Long-term debt(2)	$	3,724	$	4,831	$	3,360	$	4,748
Affiliated long-term debt		230		230		230		230

(1)   Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2)   Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs and discount or premium.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2021

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

10.  ASSET RETIREMENT OBLIGATIONS

A liability for the present value of an ARO is recognized when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.

The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to DESC’s regulated utility operations. As of December 31, 2021, DESC has recorded AROs of $287 million for nuclear plant decommissioning. In addition, DESC has recorded AROs of $312 million for other conditional obligations primarily related to other generation and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of precision, particularly since such payments will be made many years in the future.

A reconciliation of the beginning and ending aggregate carrying amount of AROs is as follows:

(millions)	2021			2020
Beginning balance	$	597		$	489
Liabilities settled		—			(4	)
Accretion expense		25			23
Revisions in estimated cash flows(1)		(23	)		89
Ending balance	$	599		$	597

(1)   The decrease in 2021 is due to the remeasurement of gas pipeline AROs. The increase in 2020 reflects revisions from the nuclear decommissioning cost study.

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Employee Benefit Plans and Equity Compensation Plan

12 Months Ended

Dec. 31, 2021

Compensation And Retirement Disclosure [Abstract]

Employee Benefit Plans and Equity Compensation Plan

11.  EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN

Pension and Other Postretirement Benefit Plans

SCANA sponsors a noncontributory defined benefit pension plan covering regular, full-time employees hired before January 1, 2014. DESC participates in SCANA's pension plan. SCANA’s policy has been to fund the plan as permitted by applicable federal income tax regulations, as determined by an independent actuary.

The pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and all eligible employees hired subsequently. Under the cash balance formula, benefits accumulate as a result of compensation credits

and interest credits. Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment. Benefits under the cash balance formula continued to accrue through December 31, 2020, after which no benefits accrue except for those participants under the cash balance formula who continue to earn interest credits. Benefits under the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued. Once the benefits under SCANA's pension plan no longer accrue, eligible participants will accrue benefits under a cash balance formula within the Dominion Energy Pension Plan, a qualified defined benefit pension plan sponsored by Dominion Energy.

In addition to pension benefits, SCANA provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. DESC participates in these programs. Retirees hired before January 1, 2011 share in a portion of their medical care cost, while employees hired subsequently are responsible for the full cost of retiree medical benefits elected by them. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.

The same benefit formula applies to all SCANA subsidiaries participating in the parent sponsored plans and, with regard to the pension plan, there are no legally separate asset pools. The postretirement benefit plans are accounted for as multiple employer plans.

Voluntary Retirement Program

In March 2019, Dominion Energy announced a voluntary retirement program to employees, including employees of DESC, that meet certain age and service requirements. In 2019, upon the determinations made concerning the number of employees that elected to participate in the program, DESC recorded a charge of $63 million ($47 million after-tax), of which $51 million was included within other operations and maintenance expense, $3 million within other taxes and $9 million within other income (expense), net. In addition, as a result of the voluntary retirement program, DESC recorded pension plan settlement losses of $16 million within other income (expense), net in 2019.

In the second quarter of 2019, DESC remeasured its pension and other postretirement benefit plans as a result of the voluntary retirement program. The remeasurement resulted in an increase in the pension benefit obligation of $16 million and an increase in the accumulated postretirement benefit obligation of $10 million. In addition, the remeasurement resulted in an increase in the fair value of pension plan assets of $27 million. The impact of the remeasurement on net periodic benefit cost was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 4.07% for the pension plan and 4.08% for the other postretirement benefit plan. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2018.

In the third quarter of 2019, DESC remeasured a pension plan as a result of a settlement from the voluntary retirement program. The settlement and related remeasurement resulted in an increase in the pension benefit obligation of $25 million and an increase in the fair value of the pension plan assets of $35 million for DESC. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 3.57%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2018.

Changes in Benefit Obligations

The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below.

	Pension Benefits						Other Postretirement Benefits
(millions)	2021			2020			2021			2020
Benefit obligation, January 1	$	742		$	727		$	184		$	214
Service cost		9			12			1			3
Interest cost		20			24			6			8
Plan participants’ contributions		—			—			—			2
Actuarial (gain) loss		(28	)		41			(8	)		(31	)
Benefits paid		(41	)		(22	)		(12	)		(13	)
Settlements		—			(40	)		—			—
Curtailment		—			—			—			—
Amounts funded to parent		—			—			—			1
Benefit obligation, December 31	$	702		$	742		$	171		$	184

The accumulated benefit obligation for pension benefits for DESC was $697 million at the end of 2021 and $732 million at the end of 2020. The accumulated pension benefit obligation differs from the projected pension benefit obligation above in that it reflects no assumptions about future compensation levels.

Significant assumptions used to determine the above benefit obligations are as follows:

	Pension Benefits						Other Postretirement Benefits
	2021			2020			2021			2020
Annual discount rate used to determine benefit obligation		3.06	%		2.73	%		3.11	%		2.80	%
Assumed annual rate of future salary increases for projected    benefit obligation		3.71	%		4.52	%	N/A			N/A
Crediting interest rate for cash balance plans		1.81	%		1.93	%	N/A			N/A

DESC’s pension benefit obligations include a gain of $29 million in 2021 resulting primarily from an increase in the discount rate and a completed experience study and a $43 million loss in 2020 resulting from a decrease in the discount rate. Actuarial gains recognized during 2021 in DESC’s other postretirement benefit obligations include a $8 million gain resulting from an increase in the discount rate. Actuarial gains recognized during 2020 in Dominion Energy’s other postretirement benefit obligations include a $51 million gain as a result from a completed experience study and other healthcare-related assumption changes and were partially offset by a $19 million loss resulting from a decrease in the discount rate.  

A 6.25% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2021. The rate was assumed to decrease gradually to 5.0% in 2026 and to remain at that level thereafter.

Funded Status

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021			2020
(millions)
Fair value of plan assets	$	768	$	747	$	—		$	—
Benefit obligation		702		742		171			184
Funded status	$	66	$	5	$	(171	)	$	(184	)

Amounts recognized on the consolidated balance sheets were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021			2020
(millions)
Noncurrent assets	$	66	$	5	$	—		$	—
Current liability		—		—		(10	)		(11	)
Noncurrent liability		—		—		(161	)		(173	)

Amounts recognized in accumulated other comprehensive loss were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021		2020
(millions)
Net actuarial loss	$	1	$	4	$	—	$	—

Amounts recognized in regulatory assets were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021			2020
(millions)
Net actuarial (gain) loss	$	70	$	114	$	(5	)	$	1

In connection with the joint ownership of Summer, costs related to pensions attributable to Santee Cooper as of both December 31, 2021 and 2020 totaled $14 million and $19 million and were recorded within deferred debits. Costs related to other postretirement benefits attributable to Santee Cooper as of December 31, 2021 and 2020 totaled $12 million both years, and was recorded within deferred debits.

Changes in Fair Value of Plan Assets

Pension Benefits
(millions)	2021			2020
Fair value of plan assets, January 1	$	747		$	725
Actual return (loss) on plan assets		62			84
Benefits paid		(41	)		(22	)
Settlements		—			(40	)
Fair value of plan assets, December 31	$	768		$	747

Investment Policies and Strategies

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

DESC’s overall objective for investing its pension plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are diversified among asset classes, securities, active and passive investment strategies and investment advisors. The strategic target asset allocations for DESC’s pension fund is: 45% global equities, 53% fixed income and 2% cash. Global equities include investments in U.S. and non-U.S. companies, developed and emerging markets and small and large cap companies. The split between U.S. and non-U.S. companies is roughly 60% U.S./40% Non-U.S. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. Equity and fixed income investments are in individual securities as well as mutual funds.  

DESC also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies.

For 2022, the expected long-term rate of return on assets will be 7.00%. DESC determines the expected long-term rates of return on plan assets for its pension plans by using a combination of:

• Expected inflation and risk-free interest rate assumptions;

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

• Expected future risk premiums, asset classes’ volatilities and correlations;

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

• Investment allocation of plan assets.

Fair Value Measurements

Assets held by the pension plan are measured at fair value and are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2021 and 2020, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

At December 31,	2021								2020
(millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	—	$	1	$	—	$	1	$	10	$	—	$	—	$	10
Corporate debt instruments		—		332		—		332		—		315		—		315
Government and other debt instruments		—		67		—		67		—		35		—		35
Total recorded at fair value	$	—	$	400	$	—	$	400	$	10	$	350	$	—	$	360
Assets recorded at NAV(1)
Common/collective trust funds								387								387
Total recorded at NAV							$	387							$	387
Total investments(2)							$	787							$	747

(1) These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient are not required to be categorized in the fair value hierarchy.

(2) Excludes net assets related to pending sales of securities of $4 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $25 million at December 31, 2021.

For purposes of calculating NAV, portfolio securities and other assets for which market quotes are readily available are valued at market value. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. U.S. Treasury securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt instruments and government and other debt instruments are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. In addition, corporate debt instruments include investments in open-end mutual funds registered with the SEC that invest in corporate debt instruments. Common collective trust assets and limited partnerships are valued at NAV, which has been determined based on the unit values of the trust funds. Unit values are determined by the organization sponsoring such trust funds by dividing the trust funds’ net assets at fair value by the units outstanding at each valuation date. Joint venture interests are invested in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges

and not traded on a daily basis. The valuation of such multi-strategy hedge fund of funds is estimated based on the NAV of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may influence their fair value.

Expected Cash Flows

Total benefits expected to be paid from the pension plan or company assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows:

Expected Benefit Payments

(millions)	Pension Benefits		Other Postretirement Benefits
2022	$	46	$	11
2023		44		11
2024		46		11
2025		45		11
2026		43		11
2027 - 2031		201		57

Pension Plan Contributions

Under its funding policies, DESC evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, DESC determines the amount of contributions for the current year, if any, at that time. DESC made no contributions to the pension trust in 2021, 2020 or 2019. DESC does not expect to contribute to its qualified pension plan in 2022.

Net Periodic Benefit Cost

Net periodic benefit cost is recorded utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables.

Components of Net Periodic Benefit Cost

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2021			2020			2019			2021		2020		2019
(millions)
Service cost	$	9		$	12		$	15		$	1	$	3	$	3
Interest cost		20			24			28			6		8		9
Expected return on assets		(48	)		(45	)		(40	)		—		—		—
Prior service cost amortization		—			—			—			—		—		—
Amortization of actuarial losses		6			6			11			—		—		—
Settlement loss		—			7			16			—		—		—
Curtailment		—			—			6			—		—		3
Net periodic benefit cost	$	(13	)	$	4		$	36		$	7	$	11	$	15

In connection with regulatory orders, DESC recovers current pension costs through a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. For retail electric operations, current pension expense is recognized based on amounts collected through a rate rider, and differences between actual pension expense and amounts recognized pursuant to the rider are deferred as a regulatory asset (for under-collections) or regulatory liability (for over-collections) as applicable. In addition, DESC amortizes certain previously deferred pension costs. See Note 3.

Other changes in plan assets and benefit obligations recognized in other comprehensive income (net of tax) were as follows:

	Pension Benefits								Other Postretirement Benefits
Year Ended December 31,	2021			2020		2019			2021		2020			2019
(millions)
Current year actuarial (gain) loss	$	(3	)	$	2	$	(1	)	$	—	$	(2	)	$	1
Total recognized in other comprehensive income	$	(3	)	$	2	$	(1	)	$	—	$	(2	)	$	1

Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows:

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2021			2020			2019			2021			2020			2019
(millions)
Current year actuarial (gain) loss	$	(39	)	$	1		$	(51	)	$	(6	)	$	(27	)	$	20
Amortization of actuarial losses		(5	)		(6	)		(11	)		—			(1	)		—
Settlement loss		—			(6	)		(16	)		—			—			—
Total recognized in regulatory assets	$	(44	)	$	(11	)	$	(78	)	$	(6	)	$	(28	)	$	20

Significant assumptions used in determining net periodic benefit cost:

	Pension Benefits			Other Postretirement Benefits
Year Ended December 31,	2021	2020	2019	2021	2020	2019
Discount rate	2.73%	3.47%	3.57/4.38%	2.80%	2.80%	4.08/4.41%
Expected return on plan assets	7.00%	7.00%	7.00%	n/a	n/a	n/a
Rate of compensation increase	4.52%	3.00%	3.00%	n/a	n/a	n/a
Crediting interest rate for cash balance plans	1.93%	2.67%	2.77/3.58%	n/a	n/a	n/a
Health care cost trend rate				6.25%	6.25%	6.60%
Ultimate health care cost trend rate				5.00%	5.00%	5.00%
Year achieved				2025-2026	2025-2026	2023

Participation in Dominion Energy Defined Benefit Plans

As discussed above, effective January 2021, DESC employees who had been receiving a cash balance formula became covered by the Dominion Energy Pension Plan. In addition, DESC employees hired in 2021 prior to July 2021 are covered by the Dominion Energy Pension Plan. As a participating employer, DESC is subject to Dominion Energy’s funding policy, which is to contribute annually an amount that is in accordance with ERISA. DESC made no contributions to the Dominion Energy Pension Plan during 2021. While DESC has not been notified by Dominion Energy of any required contributions to be made in 2022, it anticipates that it may have to contribute less than $1 million as a result of a contribution made by Dominion Energy in December 2021. DESC’s net periodic pension cost related to this plan was $3 million in 2021. Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in DESC’s Consolidated Statements of Income. The funded status of various Dominion Energy subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating Dominion Energy subsidiaries. At December 31, 2021, DESC’s pension and other postretirement benefits obligation includes $3 million for amounts due to Dominion Energy related to this plan.

Dominion Energy holds investments in trusts to fund employee benefit payments for the pension plan in which DESC’s employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that DESC will provide to Dominion Energy for its share of employee benefit plan contributions.

401(k) Retirement Savings Plan

Effective January 2021, DESC participates in a defined contribution savings plan sponsored by Dominion Energy.  Previously, DESC had participated in a defined contribution plan sponsored by SCANA, which was merged into the Dominion Energy plan in December 2020. DESC recognized employer matching contributions of $11 million in 2021 and $14 million in both 2020 and 2019.

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2021

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

12.  COMMITMENTS AND CONTINGENCIES

As a result of issues generated in the ordinary course of business, DESC is involved in legal proceedings before various courts and is periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that it is not possible for DESC to estimate a range of possible loss. For such matters that DESC cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that DESC is able to estimate a range of possible loss. For legal proceedings and governmental examinations that DESC is able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. DESC maintains various insurance programs, including general liability insurance coverage which provides coverage for personal injury or wrongful death cases. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent DESC’s maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on DESC’s financial position, liquidity or results of operations.

Environmental Matters

DESC is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

From a regulatory perspective, DESC continually monitors and evaluates its current and projected emission levels and strives to comply with all state and federal regulations regarding those emissions. DESC participates in the SO₂ and NO_X emission allowance programs with respect to coal plant emissions and also has constructed additional pollution control equipment at its coal-fired electric generating plants. These actions are expected to address many of the rules and regulations discussed herein.

Air

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

Ozone Standards

The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018 with states required to develop plans to address the new standard. In December 2021, the EPA approved the implementation plan developed for South Carolina. DESC does not expect compliance to have a material impact on its results of operations or cash flows.

ACE Rule

In July 2019, the EPA published the final rule informally referred to as the ACE Rule, as a replacement for the Clean Power Plan. The ACE Rule regulated GHG emissions from existing coal-fired power plants pursuant to Section 111(d) of the CAA and required states to develop plans by July 2022 establishing unit-specific performance standards for existing coal-fired power plants. In January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE Rule and remanded it to the EPA. This decision would take effect upon issuance of the court’s mandate. In March 2021, the court issued a partial mandate vacating and remanding all parts of the ACE Rule except for the portion of the ACE Rule that repealed the Clean Power Plan. In October 2021, the U.S. Supreme Court agreed to hear a challenge of the U.S. Court of Appeals for the D.C. Circuit’s decision on the ACE Rule. While the EPA has stated its intention to replace the ACE Rule, it is unknown at this time if or how the EPA will issue a replacement for the ACE Rule and how that replacement will affect DESC’s operations, financial condition and/or cash flows.

Carbon Regulations

In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and exceed a significant emissions rate of 75,000 tons per year of CO2 equivalent emissions. Until the EPA ultimately takes final action on this rulemaking, DESC cannot predict the impact to its results of operations, financial condition and/or cash flows.

In December 2018, the EPA proposed revised Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources. The proposed rule would amend the previous determination that the best system of emission reduction for newly constructed coal-fired steam generating units is no longer partial carbon capture and storage. Instead, the proposed revised best system of emission reduction for this source category is the most efficient demonstrated steam cycle (e.g., supercritical steam conditions for large units and subcritical steam conditions for small units) in combination with best operating practices. In January 2021, the EPA published a final rule affirming that fossil fuel-fired electric generating units meet the requirement that a source category “significantly contribute” to endangering air pollution for the purposes of regulating GHG emissions from new, modified and reconstructed stationary sources. The January 2021 rule also established a threshold for the “significant contribution” threshold that would have meant that no other source category, such as oil and gas facilities, petroleum refineries, and boilers, would meet that requirement at this time. In April 2021, the U.S. Court of Appeals for the D.C. Circuit granted an unopposed motion by the EPA to vacate and remand the January 2021 rule. The proposed revision to the performance standards for coal-fired steam generating units remains pending. Until the EPA ultimately takes final action on this rulemaking, DESC cannot predict the impact to its results of operations, financial condition and/or cash flows.

Water

The CWA, as amended, 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. DESC must comply with applicable aspects of the CWA programs at its operating facilities.

Regulation 316(b)

In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations

with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. DESC has five facilities that are subject to the final regulations. DESC is also working with the EPA and state regulatory agencies to assess the applicability of Section 316(b) to five hydroelectric facilities. DESC anticipates that it may have to install impingement control technologies at certain of these stations that have once-through cooling systems. DESC is currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technological, and cost benefit studies. DESC is conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications at certain facilities to ensure compliance with this rule. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

Effluent Limitations Guidelines

In September 2015, the EPA released a final rule to revise the ELG Rule. The final rule established updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. In April 2017, the EPA granted two separate petitions for reconsideration of the final ELG Rule and stayed future compliance dates in the rule. Also in April 2017, the U.S. Court of Appeals for the Fifth Circuit granted the EPA’s request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. In September 2017, the EPA signed a rule to postpone the earliest compliance dates for certain waste streams regulations in the final ELG Rule from November 2018 to November 2020; however, the latest date for compliance for these regulations was December 2023. In October 2020, the EPA released the final rule that extends the latest dates for compliance. Individual facilities’ compliance dates will vary based on circumstances and the determination by state regulators and may range from 2021 to 2028. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, as DESC expects that wastewater treatment technology retrofits and modifications to the bottom ash handling systems at the Williams and Wateree generating stations will be required, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

Capacity Use Area

In November 2019, a new CUA was established in the counties surrounding the Cope Generating Station (Western Capacity Use Area) under the South Carolina Groundwater Use and Reporting Regulation. Under the regulation any groundwater well in a CUA that withdraws above three million gallons per month must be permitted. The Cope Generating Station is located within this new Western Capacity Use Area. Cope has been using four deep groundwater wells for cooling water and other house loads since 1996. Prior to designation of the new Western Capacity Use Area, the wells at Cope Station were only required to be registered not permitted. As a result of this designation, Cope will need to restore the surface water equipment to operable status to reduce reliance on groundwater wells. This includes completion of 316(b) requirements, (including SCDHEC BACT determination and modification of the station national pollutant discharge elimination system permit) and extensive inspection, repair and/or replacement of the associated surface water withdrawal equipment which has been idle since 1996. While the impacts of this rule change are material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

Waste Management and Remediation

The operations of DESC are subject to a variety of state and federal laws and regulations governing the management and disposal of solid and hazardous waste, and release of hazardous substances associated with current and/or historical operations. The CERCLA, as amended, and similar state laws, may impose joint, several and strict liability for cleanup on potentially responsible parties who owned, operated or arranged for disposal at facilities affected by a release of hazardous substances. In addition, many states have created programs to incentivize voluntary remediation of sites where historical releases of hazardous substances are identified and property owners or responsible parties decide to initiate cleanups.

From time to time, DESC may be identified as a potentially responsible party in connection with the alleged release of hazardous substances or wastes at a site. Under applicable federal and state laws, DESC could be responsible for costs associated with the investigation or remediation of impacted sites, or subject to contribution claims by other responsible parties for their costs incurred at such sites. DESC also may identify, evaluate and remediate other potentially impacted sites under voluntary state programs. Remediation costs may be subject to reimbursement under DESC’s insurance policies, rate recovery mechanisms, or both. Except as described below, DESC does not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.

DESC has four decommissioned MGP sites in South Carolina that are in various states of investigation, remediation and monitoring under work plans approved by, or under review by, the SCDHEC or the EPA. DESC anticipates that activities at these sites will continue through 2025 at an estimated cost of $19 million. In addition, for one site, final approval of an updated work plan was received from the Army Corps of Engineers in December 2021, resulting in an additional $11 million of reserves and corresponding regulatory assets. DESC expects to recover costs arising from the remediation work at all four sites through rate recovery mechanisms and as of December 31, 2021, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $31 million and are included in regulatory assets.

Ash Pond and Landfill Closure Costs

In April 2015, the EPA enacted a final rule regulating CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store, CCRs. DESC currently has inactive and existing CCR ponds and CCR landfills

subject to the final rule at 3 different facilities. This rule created a legal obligation for DESC to retrofit or close all of its inactive and existing ash ponds over a certain period of time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary.

In December 2016, legislation was enacted that creates a framework for EPA- approved state CCR permit programs. In August 2017, the EPA issued interim guidance outlining the framework for state CCR program approval. The EPA has enforcement authority until state programs are approved. The EPA and states with approved programs both will have authority to enforce CCR requirements under their respective rules and programs. In September 2017, the EPA agreed to reconsider portions of the CCR rule in response to two petitions for reconsideration. In March 2018, the EPA proposed certain changes to the CCR rule related to issues remanded as part of the pending litigation and other issues the EPA is reconsidering. Several of the proposed changes would allow states with approved CCR permit programs additional flexibility in implementing their programs. In July 2018, the EPA promulgated the first phase of changes to the CCR rule. In August 2018, the U.S. Court of Appeals for the D.C. Circuit issued its decision in the pending challenges of the CCR rule, vacating and remanding to the EPA three provisions of the rule. Until this matter is resolved and all phases of the CCR rule are promulgated, DESC is unable to precisely estimate potential incremental impacts or costs related to existing coal ash sites in connection with future implementation of the final CCR rule. While such amounts may be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts.

SCANA Merger Approval Order

In accordance with the terms of the South Carolina Commission's SCANA Merger Approval Order, DESC adopted the Plan-B Levelized Customer Benefits Plan, effective February 2019, whereby the average bill for a DESC residential electric customer approximates that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the South Carolina Commission in August 2018. DESC also recorded a significant impairment charge in the fourth quarter of 2018, which charge resulted from its conclusion that NND Project capital costs exceeding the amount established in the SCANA Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed. In addition, in the first quarter of 2019, DESC recorded the following charges and liabilities which arose from or are related to provisions in the SCANA Merger Approval Order.

• A charge of $105 million ($79 million after-tax) included within the Corporate and Other segment related to certain assets that had been constructed in connection with the NND Project for which DESC committed to forgo recovery.

• A regulatory liability for refunds and restitution of amounts previously collected from retail electric customers of $1.0 billion ($756 million after-tax), recorded as a reduction in operating revenue, which will be credited to customers over an estimated 11 years effective February 2019. In addition, a previously existing regulatory liability of $1.0 billion will be credited to customers over 20 years ending 2039, which reflects amounts to be refunded to customers related to the monetization of guaranty settlement described in Note 3.

• A regulatory liability for refunds to natural gas customers totaling $2 million ($2 million after-tax).

• A tax charge of $194 million related to $258 million of regulatory assets for which DESC committed to forgo recovery.

Further, except for rate adjustments for fuel and environmental costs, DSM costs, and other rates routinely adjusted on an annual or biannual basis, DESC will freeze retail electric base rates at current levels until January 1, 2021. As discussed in Note 3, in April 2020, the South Carolina Commission issued an order vacating the portion of the SCANA Merger Approval Order requiring that new retail electric rates be implemented by January 1, 2021.

The South Carolina Commission order also approved the removal of DESC's investment in certain transmission assets that have not been abandoned from BLRA capital costs. The South Carolina Commission approved deferral of these operating costs related to the investment until recovery of the transmission capital costs and associated deferred operating costs was addressed in a future rate proceeding. These amounts were included in and approved as part of DESC’s electric base rate case filing discussed in Note 3.

Various parties filed petitions for rehearing or reconsideration of the SCANA Merger Approval Order. In January 2019, the South Carolina Commission issued an order (1) granting the request of various parties and finding that DESC was imprudent in its actions by not disclosing material information to the ORS and the South Carolina Commission with regard to costs incurred subsequent to March 2015 and (2) denying the petitions for rehearing or consideration as to other issues raised in the various petitions. The deadline to appeal the SCANA Merger Approval Order and the order on rehearing expired in April 2019, and no party has sought appeal.

Claims and Litigation

The following describes certain legal proceedings involving DESC relating primarily to events occurring before closing of the SCANA Combination. No reference to, or disclosure of, any proceeding, item or matter described below shall be construed as an admission or indication that such proceeding, item or matter is material. For certain of these matters, and unless otherwise noted therein, DESC is unable to estimate a reasonable range of possible loss and the related financial statement impacts, but for any such matter there could be a material impact to its results of operations, financial condition and/or cash flows. For the matters for which DESC is able to reasonably estimate a probable loss, the Consolidated Balance Sheets at December 31, 2021 and 2020 include reserves of $211 million and $208 million, respectively, and insurance receivables of $85 million and $8 million, respectively, included within other receivables. These balances at December 31, 2021 and 2020 include $85 million and $8 million, respectively, of offsetting reserves and insurance receivables related to personal injury or wrongful death cases which are currently pending. DESC’s Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2021, 2020 and 2019 include charges of $70 million ($53 million after-tax), $97 million ($73 million after-tax) and $590 million ($444 million after-tax), respectively, within impairment of assets and other charges, reflected in the Corporate and Other segment.

Ratepayer Class Actions

In May 2018, a consolidated complaint against DESC, SCANA and the State of South Carolina was filed in the State Court of Common Pleas in Hampton County, South Carolina (the DESC Ratepayer Case). The plaintiffs alleged, among other things, that DESC was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the NND Project, and that DESC committed unfair trade practices and violated state anti-trust laws. In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement. The court entered an order granting final approval of the settlement in June 2019, which became effective in July 2019. The settlement agreement, contingent upon the closing of the SCANA Combination, provided that SCANA and DESC establish an escrow account and proceeds from the escrow account would be distributed to the plaintiffs, after payment of certain taxes, attorneys' fees and other expenses and administrative costs. The escrow account would include (1) up to $2.0 billion, net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the escrow account in favor of class members over a period of time established by the South Carolina Commission in its order related to matters before the South Carolina Commission related to the NND Project, (2) a cash payment of $115 million and (3) the transfer of certain DESC-owned real estate or sales proceeds from the sale of such properties, which counsel for the plaintiffs estimated to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and DESC funded the cash payment portion of the

escrow account. In July 2019, DESC transferred $117 million representing the cash payment, plus accrued interest, to the plaintiffs. Through August 2020, property, plant and equipment with a net recorded value of $22 million had been transferred to the plaintiffs in coordination with the court-appointed real estate trustee to satisfy the settlement agreement. In September 2020, the court entered an order approving a final resolution of the transfer of real estate or sales proceeds with a cash contribution of $38.5 million by DESC and the conveyance of property, plant and equipment with a net recorded value of $3 million, which was completed by DESC in October 2020. In December 2021, the court approved a motion for and DESC completed the repurchase of $8 million of property, plant and equipment previously transferred to the plaintiffs.

In September 2017, a purported class action was filed by Santee Cooper ratepayers against Santee Cooper, DESC, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the State Court of Common Pleas in Hampton County, South Carolina (the Santee Cooper Ratepayer Case). The allegations were substantially similar to those in the DESC Ratepayer Case. In March 2020, the parties executed a settlement agreement relating to this matter as well as the Luquire Case and the Glibowski Case described below. The settlement agreement provided that Dominion Energy and Santee Cooper establish a fund for the benefit of class members in the amount of $520 million, of which Dominion Energy’s portion was $320 million of shares of Dominion Energy common stock. In July 2020, the court issued a final approval of the settlement agreement. In September 2020, Dominion Energy issued $322 million of shares of Dominion Energy common stock to satisfy its obligation under the settlement agreement, including interest charges.

In July 2019, a similar purported class action was filed by certain Santee Cooper ratepayers against DESC, SCANA, Dominion Energy and former directors and officers of SCANA in the State Court of Common Pleas in Orangeburg, South Carolina (the Luquire Case). In August 2019, DESC, SCANA and Dominion Energy were voluntarily dismissed from the case. The claims were similar to the Santee Cooper Ratepayer Case. In March 2020, the parties executed a settlement agreement as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Glibowski Case. This case was dismissed as part of the Santee Cooper Ratepayer Case settlement described above.

RICO Class Action

In January 2018, a purported class action was filed, and subsequently amended, against SCANA, DESC and certain former executive officers in the U.S. District Court for the District of South Carolina (the Glibowski Case). The plaintiff alleged, among other things, that SCANA, DESC and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. In March 2020, the parties executed a settlement agreement as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Luquire Case. This case was dismissed as part of the Santee Cooper Ratepayer Case settlement described above.

SCANA Shareholder Litigation

In February 2018, a purported class action was filed against Dominion Energy and certain former directors of SCANA and DESC in the State Court of Common Pleas in Richland County, South Carolina (the Metzler Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina and filed a Motion to Dismiss in March 2018. In September 2019, the U.S. District Court for the District of South Carolina granted the plaintiffs’ motion to consolidate the Metzler Lawsuit with another lawsuit regarding the SCANA Merger Agreement to which DESC is not a party. In October 2019, the plaintiffs filed an amended complaint against certain former directors and executive officers of SCANA and DESC, which stated substantially similar allegations to those in the initial lawsuits as well as an inseparable fraud claim. In November 2019, the defendants filed a motion to dismiss. In April 2020, the U.S. District Court for the District of South Carolina denied the motion to dismiss. In May 2020, SCANA filed a motion to intervene, which was denied in August 2020. In September 2020, SCANA filed a notice of appeal with the U.S. Court of Appeals for the Fourth Circuit. In June 2021, the parties reached an agreement in principle to settle this case, along with a related case to which DESC was not a party, subject to court approval, with no financial impact to DESC.

Employment Class Actions and Indemnification

In August 2017, a case was filed in the U.S. District Court for the District of South Carolina on behalf of persons who were formerly employed at the NND Project. In July 2018, the court certified this case as a class action. In February 2019, certain of these plaintiffs filed an additional case, which case has been dismissed and the plaintiffs have joined the case filed in August 2017. The plaintiffs allege, among other things, that SCANA, DESC, Fluor Corporation and Fluor Enterprises, Inc. violated the Worker Adjustment and Retraining Notification Act in connection with the decision to stop construction at the NND Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment and are seeking damages, which could be as much as $100 million for 100% of the NND Project. In January 2021, the U.S. District Court for the District of South Carolina granted summary judgment in favor of SCANA, DESC, Fluor Corporation and Fluor Enterprises, Inc. In February 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fourth Circuit. In November 2021, the U.S. Court of Appeals for the Fourth Circuit affirmed the lower court ruling.

In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against DESC and Santee Cooper. The plaintiffs make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants' alleged failure and refusal to defend and indemnify the Fluor defendants in the aforementioned case. This case is pending.

FILOT Litigation and Related Matters

In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against DESC in the State Court of Common Pleas in Fairfield County, South Carolina, making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of implied duty of good faith and fair dealing and unfair trade practices related to DESC’s termination of the FILOT agreement between DESC and Fairfield County related to the NND Project. The plaintiff sought a temporary and permanent injunction to prevent DESC from terminating the FILOT agreement. The plaintiff withdrew the motion for temporary injunction in December 2017. In July 2021, the parties executed a settlement agreement requiring DESC to pay $99 million, which could be satisfied in either cash or shares of Dominion Energy common stock. Also in July 2021, the State Court of Common Pleas in Fairfield County, South Carolina approved the settlement. In July 2021, Dominion Energy issued 1.4 million shares of Dominion Energy common stock to satisfy DESC’s obligation under the settlement agreement.

Governmental Proceedings and Investigations

In June 2018, DESC received a notice of proposed assessment of approximately $410 million, excluding interest, from the SCDOR following its audit of DESC’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NND Project, is based on the SCDOR’s position that DESC’s sales and use tax exemption for the NND Project does not apply because the facility will not become operational. In December 2020, the parties reached an agreement in principle in the amount of $165 million to resolve this matter. In June 2021, the parties executed a settlement agreement which allows DESC to fund the settlement amount through a combination of cash, shares of Dominion Energy common stock or real estate with an initial payment of at least $43 million in shares of Dominion Energy common stock. In August 2021, Dominion Energy issued 0.6 million shares of its common stock to satisfy DESC’s obligation for the initial payment under the settlement agreement.

In September and October 2017, SCANA was served with subpoenas issued by the U.S. Attorney’s Office for the District of South Carolina and the Staff of the SEC’s Division of Enforcement seeking documents related to the NND Project. In February 2020, the SEC filed a complaint against SCANA, two of its former executive officers and DESC in the U.S. District Court for the District of South Carolina alleging that the defendants violated federal securities laws by making false and misleading statements about the NND Project. In April 2020, SCANA and DESC reached an agreement in principle with the Staff of the SEC’s Division of Enforcement to settle, without admitting or denying the allegations in the complaint. In December 2020, the U.S. District Court for the District of South Carolina issued an order approving the settlement which required SCANA to pay a civil monetary penalty totaling $25 million, and SCANA and DESC to pay disgorgement and prejudgment interest totaling $112.5 million, which disgorgement and prejudgment interest amount were deemed satisfied by the settlements in the SCANA Securities Class Action and the DESC Ratepayer Case. SCANA paid the civil penalty in December 2020. The SEC civil action against two former executive officers of SCANA remains pending and is currently subject to a stay granted by the court in June 2020 at the request of the U.S. Attorney’s Office for the District of South Carolina.

In addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and DESC. Dominion Energy is cooperating fully with the investigations by the U.S. Attorney’s Office and the South Carolina Law Enforcement Division, including responding to additional subpoenas and document requests. Dominion Energy has also entered into a cooperation agreement with the U.S. Attorney’s Office and the South Carolina Attorney General’s Office. The cooperation agreement provides that in consideration of its full cooperation with these investigations to the satisfaction of both agencies, neither such agency will criminally prosecute or bring any civil action against Dominion Energy or any of its current, previous, or future direct or indirect subsidiaries related to the NND Project. A former executive officer of SCANA entered a plea agreement with the U.S. Attorney’s Office and the South Carolina Attorney General’s Office in June 2020 and entered a guilty plea with the U.S. District Court for the District of South Carolina in July 2020. Another former executive officer of SCANA entered a plea agreement with the U.S. Attorney's Office and the South Carolina Attorney General's Office in November 2020 and entered guilty pleas in the U.S. District Court for the District of South Carolina and in South Carolina state court in February 2021. As a result of the pleas, Dominion Energy has terminated indemnity for these former executive officers related to these two cases.

Abandoned NND Project

DESC, for itself and as agent for Santee Cooper, entered into an engineering, construction and procurement contract with Westinghouse and WECTEC in 2008 for the design and construction of the NND Project, of which DESC’s ownership share is 55%. Various difficulties were encountered in connection with the project. The ability of Westinghouse and WECTEC to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters preceded the filing for bankruptcy protection by Westinghouse and WECTEC in March 2017, and were the subject of comprehensive analyses performed by SCANA and Santee Cooper.

Based on the results of SCANA’s analysis, and in light of Santee Cooper's decision to suspend construction on the NND Project, in July 2017, SCANA determined to stop the construction of the units and to pursue recovery of costs incurred in connection with the construction under the abandonment provisions of the Base Load Review Act or through other means. This decision by SCANA became the focus of numerous legislative, regulatory and legal proceedings. Some of these proceedings are described above.

In September 2017, DESC, for itself and as agent for Santee Cooper, filed with the U.S. Bankruptcy Court for the Southern District of New York Proofs of Claim for unliquidated damages against each of Westinghouse and WECTEC. These Proofs of Claim were based

upon the anticipatory repudiation and material breach by Westinghouse and WECTEC of the contract, and assert against Westinghouse and WECTEC any and all claims that are based thereon or that may be related thereto.

Westinghouse’s reorganization plan was confirmed by the U.S. Bankruptcy Court for the Southern District of New York and became effective in August 2018. In connection with the effectiveness of the reorganization plan, the contract associated with the NND Project was deemed rejected. DESC contested approximately $285 million of filed liens in Fairfield County, South Carolina. Most of these asserted liens were claims that relate to work performed by Westinghouse subcontractors before the Westinghouse bankruptcy, although some of them were claims arising from work performed after the Westinghouse bankruptcy.

DESC and Santee Cooper were responsible for amounts owed to Westinghouse for valid work performed by Westinghouse subcontractors on the NND Project after the Westinghouse bankruptcy filing until termination of the interim assessment agreement. In December 2019, DESC and Santee Cooper entered into a confidential settlement agreement with W Wind Down Co LLC resolving claims relating to the interim assessment agreement.

Further, some Westinghouse subcontractors that made claims against Westinghouse in the bankruptcy proceeding also filed claims against DESC and Santee Cooper in South Carolina state court for damages. Many of these claimants asserted construction liens against the NND Project site. In December 2021, settlements were reached to resolve all remaining claims made by Westinghouse subcontractors. All amounts for which Dominion Energy was ultimately responsible were funded utilizing, and did not exceed, the portion of the Toshiba Settlement allocated for such balances within the SCANA Merger Approval Order recorded in regulatory liabilities on DESC’s Consolidated Balance Sheets.

Nuclear Insurance

Under Price-Anderson, DESC (for itself and on behalf of Santee-Cooper) maintains agreements of indemnity with the U.S. Nuclear Regulatory Commission that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Summer. Price-Anderson provides funds up to $13.5 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $450 million by American Nuclear Insurers with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is liable for up to $138 million per reactor owned for each nuclear incident occurring at any reactor in the U.S., provided that not more than $21 million of the liability per reactor would be assessed per year. DESC’s maximum assessment, based on its two-thirds ownership of Summer, would be $92 million per incident, but not more than $14 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

DESC currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Summer for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.33 billion resulting from an event of a non-nuclear origin. The NEIL policies in aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. The NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, DESC’s portion of the retrospective premium assessment would not exceed $24 million. DESC currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Summer for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, DESC's portion of the retrospective premium assessment would not exceed $2 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Summer exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that DESC's rates would not recover the cost of any purchased replacement power, DESC will retain the risk of loss as a self-insurer. DESC has no reason to anticipate a serious nuclear or other incident. However, if such an incident were to occur, it likely would have a material impact on DESC's results of operations, cash flows and financial position.

Spent Nuclear Fuel

The Nuclear Waste Policy Act of 1982 required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. DESC entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. By mutual agreement of the parties, damage award payments and settlement payments are made until the DOE has accepted the same amount of spent fuel from the facility as if it has fully performed its contractual obligations. In 2021, DESC received payment of $1 million for resolution of its share of claims incurred at Summer for the period of January 1, 2020 through December 31, 2020. In 2020, DESC received payment of $4 million for resolution of its share of claims incurred at Summer for the period of January 1, 2019 through December 31, 2019. As of December 31, 2021, the federal government has not accepted any spent fuel from Summer, and it remains unclear when the repository may become available. DESC has constructed an independent spent fuel storage installation to accommodate the spent nuclear fuel output for the life of Summer. DESC may evaluate other technology as it becomes available.

Long-Term Purchase Agreements

At December 31, 2021, DESC had the following long-term commitments that are noncancelable or cancelable only under certain conditions, and that a third party that will provide the contracted goods or services has used to secure financing.

(millions)	2022		2023		2024		2025		2026		Thereafter		Total
Purchased electric capacity(1)	$	83	$	82	$	82	$	83	$	86	$	834	$	1,250

(1)   Includes affiliated amounts with certain solar facilities of $238 million.

Commitments represent estimated amounts payable for energy under power purchase contracts with qualifying facilities which expire at various dates through 2046. Energy payments are generally based on fixed dollar amounts per month and totaled $73 million in 2021, $64 million in 2020 and $37 million in 2019.

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Leases

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Leases

13. LEASES

At December 31, 2021 and 2020, DESC had the following lease assets and liabilities recorded in the Consolidated Balance Sheets:

At December 31,	2021		2020
(millions)
Lease assets:
Operating lease assets(1)	$	19	$	21
Finance lease assets(2)		13		20
Total lease assets	$	32	$	41
Lease liabilities:
Operating lease - current(3)	$	2	$	3
Operating lease - noncurrent(4)		17		18
Finance lease - current(5)		5		6
Finance lease - noncurrent		10		15
Total lease liabilities	$	34	$	42

(1)   Included in other deferred debits and other assets in the Consolidated Balance Sheets.

(2)   Included in utility plant, net, in the Consolidated Balance Sheets, net of $20 million and $24 million of accumulated amortization at December 31, 2021 and December 31, 2020, respectively.

(3)   Included in other current liabilities in the Consolidated Balance Sheets.

(4)   Included in other deferred credits and other liabilities in the Consolidated Balance Sheets.

(5)   Included in securities due within one year in the Consolidated Balance Sheets.

For the years ended December 31, 2021, 2020 and 2019, total lease cost consisted of the following:

Year Ended December 31,	2021		2020		2019
(millions)
Finance lease cost:
Amortization	$	6	$	8	$	7
Interest		1		1		1
Operating lease cost		4		4		4
Short-term lease cost		2		2		1
Total lease cost	$	13	$	15	$	13

For the years ended December 31, 2021, 2020 and 2019, cash paid for amounts included in the measurement of lease liabilities consisted of the following amounts, included in the Consolidated Statements of Cash Flows:

Year Ended December 31,	2021		2020		2019
(millions)
Operating cash flows from finance leases	$	1	$	1	$	1
Operating cash flows from operating leases		4		4		3
Financing cash flows from finance leases		6		8		7

At December 31, 2021 and 2020, the weighted average remaining lease term and weighted average discount rate for finance and operating leases were as follows:

At December 31,	2021			2020
Weighted average remaining lease term - finance leases	4 years			4 years
Weighted average remaining lease term - operating leases	20 years			19 years
Weighted average discount rate - finance leases		2.91	%		2.92	%
Weighted average discount rate - operating leases		3.97	%		3.95	%

Lease liabilities have the following scheduled maturities:

(millions)	Operating			Finance
2022	$	3		$	5
2023		2			4
2024		2			3
2025		1			1
2026		1			1
After 2026		21			1
Total undiscounted lease payments		30			15
Present value adjustment		(11	)		(1	)
Present value of lease liabilities	$	19		$	14

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Operating Segments

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Operating Segments

14.  OPERATING SEGMENTS

The Corporate and Other Segment 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.

In 2021, DESC reported after-tax net expenses of $212 million for specific items in the Corporate and Other segment, of which $208 million was attributable to its operating segment.

The net expense for specific items attributable to DESC’s operating segment in 2021 primarily related to $266 million ($199 million after-tax) of charges associated with the settlement of the South Carolina electric base rate case and a $70 million ($53 million after-tax) charge associated with litigation.

In 2020, DESC reported after-tax net expenses of $104 million for specific items in the Corporate and Other segment, all of which were attributable to its operating segment.

The net expense for specific items attributable to DESC’s operating segment in 2020 primarily related to $99 million ($74 million after-tax) of charges associated with litigation.

In 2019, DESC reported after-tax net expenses of $1.6 billion for specific items in the Corporate and Other segment, all of which were attributable to its operating segment.

The net expense for specific items attributable to DESC’s operating segment in 2019 primarily related to the impact of the following items:

• A $1.0 billion ($756 million after-tax) charge for refunds of amounts previously collected from retail electric customers for the NND Project;

• $590 million ($444 million after-tax) of charges associated with litigation;

• A $194 million tax charge for $258 million of income tax-related regulatory assets for which DESC committed to forgo recovery;

• A $114 million ($86 million after-tax) charge for utility plant primarily for which DESC committed to forgo recovery;

• $100 million ($76 million after-tax) of merger-related costs associated with the SCANA Combination, including a $79 million ($59 million after-tax) charge related to a voluntary retirement program; and 

• $66 million tax charges for changes in unrecognized tax benefits.

The following table presents segment information pertaining to DESC’s operations:

Year Ended December 31,	Dominion Energy South Carolina		Corporate and Other			Consolidated Total
(millions)
2021
External revenue	$	3,146	$	—		$	3,146
Depreciation and amortization		486		—			486
Interest and related charges		215		(23	)		192
Income tax expense (benefit)		125		(116	)		9
Comprehensive income (loss) available (attributable) to    common shareholder		421		(212	)		209
Capital expenditures		758		—			758
Total assets (billions)		14.9		—			14.9
2020
External revenue	$	2,739	$	—		$	2,739
Depreciation and amortization		474		—			474
Interest and related charges		223		6			229
Income tax expense (benefit)		107		(36	)		71
Comprehensive income (loss) available (attributable) to    common shareholder		410		(113	)		297
Capital expenditures		742		—			742
Total assets (billions)		14.5		—			14.5
2019
External revenue	$	2,937	$	(1,008	)	$	1,929
Depreciation and amortization		452		(2	)		450
Interest and related charges		247		13			260
Income tax expense (benefit)		163		(175	)		(12	)
Comprehensive income (loss) available (attributable) to    common shareholder		408		(1,647	)		(1,239	)
Capital expenditures		497		—			497

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Utility Plant and Nonutility Property

12 Months Ended

Dec. 31, 2021

Utility Plant And Non Utility Property [Abstract]

Utility Plant and Nonutility Property

15.  UTILITY PLANT AND NONUTILITY PROPERTY

Major classes of utility plant and other property and their respective balances at December 31, 2021 and 2020 were as follows:

At December 31,	2021		2020
(millions)
Gross utility plant:
Generation	$	6,053	$	5,921
Transmission		2,037		1,963
Distribution		5,191		4,909
Storage		76		74
General and other		601		563
Intangible		242		250
Construction work in progress		481		460
Nuclear fuel		603		575
Total gross utility plant	$	15,284	$	14,715
Gross nonutility property	$	44	$	45

Jointly Owned Utility Plant

DESC jointly owns and is the operator of Summer. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. DESC’s share of the direct expenses of Summer is included in the corresponding operating expenses on its income statement. The units associated with the NND Project, net of impairment charges, have been reclassified from construction work in progress to a regulatory asset as a result of the decision to stop their construction. See additional discussion at Note 3. In May 2019, DESC and Santee Cooper entered into an agreement in which DESC agreed to purchase 11.7% of Santee Cooper’s ownership interest in the NND Project nuclear fuel, which will be used at Summer, for $8 million to true up the ownership percentage from the 55% ownership percentage that was applicable for the NND Project to the 66.7% ownership percentage applicable for Summer.

At December 31,	2021			2020
	Summer Unit 1			Summer Unit 1
Percent owned	66.7%			66.7%
Plant in service	$	1.6	billion	$	1.6	billion
Accumulated depreciation	$	725	million	$	702	million
Construction work in progress	$	76	million	$	62	million

Included within other receivables on the balance sheet were amounts due to DESC from Santee Cooper for its share of direct expenses. These amounts totaled $32 million at December 31, 2021 and $28 million at December 31, 2020.

Sale of Warranty Service Contract Assets

In May 2019, DESC entered into an agreement to sell certain warranty service contract assets for total consideration of $7 million. The transaction closed in August 2019, resulting in a $7 million ($5 million after-tax) gain recorded in other expense, net in DESC’s Consolidated Statements of Comprehensive Income (Loss). Pursuant to the agreement, upon closing DESC entered into a service agreement with the buyer under which the buyer will compensate DESC in connection with the right to use DESC’s brand in marketing materials and other services over a ten-year term.

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Affiliated and Related Party Transactions

12 Months Ended

Dec. 31, 2021

Related Party Transactions [Abstract]

Affiliated and Related Party Transactions

16.  AFFILIATED AND RELATED PARTY TRANSACTIONS

DESC owns 40% of Canadys Refined Coal, LLC, which was involved in the manufacturing and sale of refined coal to reduce emissions at one of DESC’s generating facilities. DESC accounts for this investment using the equity method. Purchases and sales of the related coal are recorded as other income (expense), net in the Consolidated Statements of Comprehensive Income (Loss).

DESS, on behalf of itself and its parent company, provided the following services to DESC through December 2020, which were rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, DESS processed and paid invoices for DESC and was reimbursed. Effective January 2021, DES provides to DESC the services previously provided by DESS. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in other operations and maintenance – affiliated suppliers and other expense, net in the Consolidated Statements of Comprehensive Income (Loss).

DESC transacts with affiliates for certain quantities of electricity in the ordinary course of business. DESC also enters into certain commodity derivative contracts with affiliates. DESC uses these contracts, which are principally comprised of forward commodity purchases, to manage commodity price risks associated with purchases of electricity. See Note 8 for more information.

Year Ended December 31,	2021		2020		2019
(millions)
Purchases of coal from affiliate	$	—	$	—	$	121
Sales of coal to affiliate		—		—		120
Purchases of fuel used in electric generation from affiliate		—		—		43
Direct and allocated costs from DES and DESS(1)		226		294		297
Operating Revenues – Electric from sales to affiliate		4		4		4
Operating Revenues – Gas from sales to affiliate		1		1		1
Operating Expenses – Other taxes from affiliate		7		9		6
Purchases of electricity from solar affiliates		14		12		8
Demand and transportation charges from DECG - Fuel used in    electric generation		—		16		19
Demand and transportation charges from DECG - Gas purchased    for resale		—		36		44

(1)   Includes capitalized expenditures of $37 million, $81 million and $53 million for the years ended December 31, 2021, 2020 and 2019, respectively.

At December 31,	2021		2020
(millions)
Payable to DES and DESS		30		59
Payable to Public Service Company of North Carolina, Incorporated		—		5
Receivable from Public Service Company of North Carolina, Incorporated		60		—
Payable to solar affiliates		1		1
Receivable from nuclear affiliates		1		—
Payable to DEI		1		—
Derivative assets with affiliates(1)		28		—

(1)   Effective in the second quarter of 2021, contracts for the future purchase of certain quantities of electricity from solar affiliates no longer met the criteria for the normal purchase normal sale exception and are accounted for as derivative contracts.

Borrowings from an affiliate are described in Note 6. Certain disclosures regarding DESC’s participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 11.

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Other Income (Expense), Net

12 Months Ended

Dec. 31, 2021

Income Statement [Abstract]

Other Income (Expense), Net

17.  OTHER INCOME (EXPENSE), NET

Components of other income (expense), net are as follows:

Year Ended December 31,	2021			2020			2019
(millions)
Revenues from contracts with customers	$	—		$	1		$	4
Other income		11			13			19
Other expense		(18	)		(38	)		(57	)
Allowance for equity funds used during construction		5			1			1
Other expense, net	$	(2	)	$	(23	)	$	(33	)

 Non-service cost components of pension and other postretirement benefits are included in other expense.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

General

General

DESC makes certain estimates and assumptions in preparing its Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues, expenses and cash flows for the periods presented. Actual results may differ from those estimates.

DESC’s Consolidated Financial Statements include, after eliminating intercompany balances and transactions, the accounts of DESC, GENCO and Fuel Company. DESC has concluded that GENCO and Fuel Company are VIEs due to the members lacking the characteristics of a controlling financial interest. DESC is the primary beneficiary of GENCO and Fuel Company and therefore is required to consolidate the VIEs. The equity interests in GENCO and Fuel Company are held solely by SCANA, DESC’s parent. As a result, GENCO and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in the Consolidated Financial Statements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold exclusively to DESC, pursuant to a FERC approved power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Fuel Company acquires, owns and provides financing for DESC's nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 6.

Additionally, effective January 2021, DESC purchases shared services from DES, an affiliated VIE that provides accounting, legal, finance and certain administrative and technical services to all Dominion Energy subsidiaries, including DESC. DESC previously purchased such services from DESS, an affiliated VIE, that had provided such services to all SCANA subsidiaries. DESC has determined that it is not the primary beneficiary of DES as it does not have either the power to direct the activities that most significantly impact its economic performance or an obligation to absorb losses and benefits which could be significant to it. See Note 16 for amounts attributable to affiliates.

DESC reports certain contracts and instruments at fair value. See Note 9 for further information on fair value measurements.

DESC maintains pension and other postretirement benefit plans. See Note 11 for further information on these plans.

Certain amounts in the 2020 and 2019 Consolidated Financial Statements and Notes have been reclassified to conform to the 2021 presentation for comparative purposes; however, such reclassifications did not affect DESC’s net income, total assets, liabilities, equity or cash flows. Effective in the second quarter of 2021, DESC updated its Statements of Cash Flows to present net charges for allowance for credit risk and write-offs of accounts receivables within other adjustments to reconcile net income to net cash provided by operating activities from the previous presentation within changes in accounts receivable. All prior period information has been conformed to this presentation, which does not result in a change to net cash provided by operating activities.

Utility Plant

Utility Plant

Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFUDC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense.

AFUDC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFUDC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. DESC calculated AFUDC using average composite rates of 2.6%, 2.6% and 4.3% for 2021, 2020 and 2019, respectively. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. DESC capitalizes interest on nuclear fuel in process at the actual interest cost incurred.

For property subject to cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from utility plant-in-service when it becomes probable it will be abandoned and recorded as a regulatory asset for amounts expected to be collected through future rates.

Provisions for depreciation and amortization are recorded using the straight-line method based on the estimated service lives of the various classes of property, and in most cases, include provisions for future cost of removal. The composite weighted average depreciation rates for utility plant by function were as follows:

	2021(1)			2020
Generation		2.46	%		2.50	%
Transmission		2.56	%		2.56	%
Distribution		2.48	%		2.42	%
Storage		2.85	%		2.75	%
General and other		2.27	%		3.17	%

(1) Rates include the impact of a change in depreciation rates approved in connection with the settlement of the electric base rate case, which resulted in a decrease to depreciation expense of $6 million and an expected annual decrease of $12 million.

DESC records nuclear fuel amortization using the units-of-production method, which is included in fuel used in electric generation and recovered through the fuel cost component of retail electric rates.

Major Maintenance

Major Maintenance

Planned major maintenance costs related to certain fossil fuel turbine generator equipment, nuclear refueling outages and cyclical tree trimming and vegetation management are collected in rates and accrued in periods other than when incurred in accordance with approval by the South Carolina Commission for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred.

Effective September 2021, DESC is authorized to collect $25 million annually through electric rates to offset certain turbine generator maintenance expenditures. Prior to September 2021, DESC was authorized to collect $18 million annually. For the years ended December 31, 2021 and 2020, DESC incurred $20 million and $19 million, respectively, for turbine generator maintenance.

Nuclear refueling outages are scheduled 18 months apart. As approved by the South Carolina Commission, DESC accrues $17 million annually for its portion of the nuclear refueling outages, that are scheduled to occur from the fall of 2021 through the fall of 2027 as well as unrecovered balances from the previous accrual cycle. Refueling outage costs incurred for which DESC was responsible totaled $24 million in 2021 and $23 million in 2020.

Effective September 2021, DESC implemented a tree trimming and vegetation management accrual where costs associated with cyclical tree trimming and vegetation management are accrued over the five-year operating cycle DESC seeks to maintain for such activities. As approved by the South Carolina Commission, DESC accrues $28 million annually. In 2021, DESC accrued $9 million during the period the accrual was effective and incurred costs totaling $9 million.  

Asset Retirement Obligations

Asset Retirement Obligations

DESC recognizes AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. Periodically, DESC assesses its AROs to determine if circumstances indicate that estimates of the amounts or timing of future cash flows associated with retirement activities have changed. AROs are adjusted when significant changes in the amounts or timing of future cash flows are identified. DESC reports accretion of AROs and depreciation on asset retirement costs as an adjustment to regulatory assets. 

Nuclear Decommissioning

Nuclear Decommissioning

Based on a decommissioning cost study completed in 2020, DESC’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $764 million, stated in 2021 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.

Under DESC’s method of funding decommissioning costs, DESC transfers to an external trust fund the amounts collected through rates ($3 million in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. The asset balance held in trust reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer on an after-tax basis.

Cash, Restricted Cash and Equivalents

Cash, Restricted Cash and Equivalents

Cash, restricted cash and equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Restricted Cash and Equivalents

Beginning in 2021, DESC holds restricted cash and equivalent balances that consists of federal assistance funds to be used towards customer bill assistance.

The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within DESC’s Consolidated Balance Sheets to the corresponding amounts reported within DESC’s Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019:

	Cash, Restricted Cash and Equivalents at End/Beginning of Year
	December 31, 2021		December 31, 2020		December 31, 2019		December 31, 2018
(millions)
Cash and cash equivalents	$	30	$	5	$	4	$	377
Restricted cash and equivalents(1)		24		—		—		—
Cash, restricted cash and equivalents shown in the    Consolidated Statements of Cash Flows	$	54	$	5	$	4	$	377

(1) At December 31 2020, 2019 and 2018 there were no restricted cash and equivalent balances.

Receivables

Receivables

Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described in Note 4. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $139 million and $156 million at December 31, 2021 and 2020, respectively.

DESC sells electricity and natural gas and provides distribution and transmission services to customers in South Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of DESC’s customer base, which includes a large number of residential, commercial and industrial customers. Credit risk associated with accounts receivable is limited due to the large number of customers. DESC’s exposure to potential concentrations of credit risk results primarily from amounts due from Santee Cooper related to the jointly owned nuclear generating facility at Summer. Such receivables represented approximately 6% of DESC’s accounts receivable balance at December 31, 2021.

Inventories

Inventories

Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the South Carolina Commission.

Income Taxes

Income Taxes

A consolidated federal income tax return is filed for Dominion Energy and its subsidiaries, including DESC. In addition, where applicable, combined income tax returns for Dominion Energy, including DESC, are filed in various states including South Carolina; otherwise, separate state income tax returns are filed.

DESC participates in an intercompany tax sharing agreement with Dominion Energy. Current income taxes are based on taxable income or loss and credits determined on a separate company basis.

Under the agreements, if a subsidiary incurs a tax loss or earns a credit, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or credit or to the extent the tax loss or credit is absorbed by the taxable income of other Dominion Energy consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax asset until realized.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. DESC establishes a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. DESC did not have any valuation allowances recorded for the periods presented. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

DESC recognizes positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2021, DESC had $62 million of unrecognized tax benefits.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the Consolidated Balance Sheets and current payables are included in taxes accrued on the Consolidated Balance Sheets.

DESC recognizes interest on underpayments and overpayments of income taxes in interest expense and interest income, respectively. Penalties are also recognized in other expenses.

In 2021, DESC reflected a $21 million benefit in interest expense associated with the effective settlement of uncertain tax positions.  Interest expense for DESC was $7 million in 2020 and $18 million in 2019. Interest income for DESC was less than $1 million in both 2021 and 2020 and $2 million in 2019. In 2021, DESC recognized a $7 million benefit from the reversal of penalty expenses associated with the effective settlement of uncertain tax positions.  DESC recorded penalty expenses of $4 million in 2020 and $7 million in 2019.

At December 31, 2021, DESC had an income tax-related affiliated receivable of $24 million from Dominion Energy. This balance is expected to be received from Dominion Energy.

At December 31, 2020, DESC had an income tax-related affiliated payable of $31 million to Dominion Energy. This balance was paid to Dominion Energy in 2021.

At DESC investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

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

DESC evaluates whether or not recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on:

• Orders issued by regulatory commissions, legislation and judicial actions;

• Past experience; and

• Discussions with applicable regulatory authorities and legal counsel.

Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. See Notes 3 to the Consolidated Financial Statements for additional information.

Derivative Instruments

Derivative Instruments

DESC is exposed to the impact of market fluctuations in the price of electricity and natural gas it markets and purchases, as well as interest rate risk in its business operations. DESC uses derivative instruments such as physical forwards and swaps to manage commodity and/or interest rate risks of its business operations.

All derivatives, except those for which an exception applies, are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions are reported as derivative assets. Derivative contracts representing unrealized losses are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance. See Note 9 for further information about fair value measurements and associated valuation methods for derivatives.

DESC does not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. DESC had margin assets of $11 million and $17 million associated with cash collateral at December 31, 2021 and 2020, respectively. DESC had no margin liabilities associated with cash collateral at December 31, 2021 and 2020. See Note 8 for further information about derivatives.

To manage price and interest rate risk, DESC holds derivative instruments that are not designated as hedges for accounting purposes. However, to the extent DESC does not hold offsetting position for such derivatives, it believes these instruments represent economic hedges that mitigate its exposure to fluctuations in commodity prices or interest rates. All income statement activity, including amounts realized upon settlement, is presented in operating expenses and interest charges based on the nature of the underlying risk.

Changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings. All income statement activity, including amounts realized upon settlement, is presented in operating expenses and interest charges based on the nature of the underlying risk.

DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS

In accordance with accounting guidance pertaining to derivatives and hedge accounting, DESC designates a portion of their derivative instruments as cash flow hedges for accounting purposes. For derivative instruments that are accounted for as cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.

Cash Flow Hedges- DESC uses interest rate swaps to hedge its exposure to variable interest rates on long-term debt. For transactions in which DESC is hedging the variability of cash flows, changes in the fair value of the derivatives are reported in regulatory assets or liabilities. Any derivative gains or losses reported in regulatory assets or liabilities are reclassified to earnings when the forecasted item is included in earnings. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Pursuant to regulatory orders, interest rate derivatives entered into by DESC after October 2013 were not designated for accounting purposes as cash flow hedges, and fair value changes and settlement amounts related to them have been recorded as regulatory assets and liabilities. Settlement losses on swaps generally have been amortized over the lives of subsequent debt issuances, and gains have been amortized to interest charges or have been applied as otherwise directed by the South Carolina Commission.

Debt Issuance Costs

Debt Issuance Costs

DESC defers and amortizes debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as a reduction in long-term debt in the Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest charges. As permitted by regulatory authorities, gains or losses resulting from the refinancing or redemption of debt that are probable of recovery through future rates are deferred and amortized.

Environmental

Environmental

An environmental assessment program is maintained to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred.

Statement of Operations Presentation

Statement of Operations Presentation

Revenues and expenses arising from regulated businesses are presented within Operating Income (Loss), and all other activities are presented within Other Expense, net.

Operating Revenue

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered, or contracts settled and includes amounts yet to be billed to customers. DESC collects sales, consumption, consumer utility taxes and sales taxes; however, these amounts are excluded from revenue and are recorded as liabilities until they are remitted to the respective taxing authority.

The primary types of sales and service activities reported as operating revenue for DESC are as follows:

Revenue from Contracts with Customers

• Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

• Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services; and

• Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities.

Other Revenue

• Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

DESC records refunds to customers as required by the South Carolina Commission as a reduction to regulated electric sales or regulated gas sales, as applicable. Revenues from electric and gas sales are recognized over time, as the customers of DESC consume gas and electricity as it is delivered. Sales of products and services typically transfer control and are recognized as revenue upon delivery of the product or service. The customer is able to direct the use of, and obtain substantially all of the benefits from, the product at the time the product is delivered. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. Payment for most sales and services varies by contract type, but is typically due within a month of billing.

DESC customers subject to an electric fuel cost recovery component or a PGA are billed based on a fuel or cost of gas factor calculated in accordance with cost recovery procedures approved by the South Carolina Commission and subject to adjustment periodically. Any difference between actual costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost recovery factors.

Certain amounts deferred for the WNA arise under specific arrangements with regulators rather than customers and are accounted for as an alternative revenue program. This alternative revenue is included within Other operating revenues, separate from revenue arising from contracts with customers, in the month such adjustments are deferred within regulatory accounts. As permitted, DESC has elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues.

Performance obligations which have not been satisfied by DESC relate primarily to demand or standby service for natural gas. Demand or standby charges for natural gas arise when an industrial customer reserves capacity on assets controlled by the service provider and may use that capacity to move natural gas it has acquired from other suppliers. For all periods presented, the amount of revenue recognized by DESC for these charges is equal to the amount of consideration DESC has a right to invoice and corresponds directly to the value transferred to the customer.

Leases

Leases

DESC leases certain assets including vehicles, real estate, office equipment and other assets under both operating and finance leases. For operating leases, rent expense is recognized on a straight-line basis over the term of the lease agreement, subject to regulatory framework. Rent expense associated with operating leases, short-term leases and variable leases is primarily recorded in other operations and maintenance expense in the Consolidated Statements of Comprehensive Income (Loss). Amortization expense and interest charges associated with finance leases are deferred within regulatory assets in the Consolidated Balance Sheets and amortized into the Consolidated Statements of Comprehensive Income (Loss).

Certain leases include one or more options to renew, with renewal terms that can extend the lease from one to 70 years. The exercise of renewal options is solely at DESC's discretion and is included in the lease term if the option is reasonably certain to be exercised. A right-of-use asset and corresponding lease liability for leases with original lease terms of one year or less are not included in the Consolidated Balance Sheets, unless such leases contain renewal options that DESC is reasonably certain will be exercised.

The determination of the discount rate utilized has a significant impact on the calculation of the present value of the lease liability included in the Consolidated Balance Sheets. For DESC’s leased assets, the discount rate implicit in the lease is generally unable to be determined from a lessee perspective. As such, DESC uses internally-developed incremental borrowing rates as a discount rate in the calculation of the present value of the lease liability. The incremental borrowing rates are determined based on an analysis of DESC's publicly available secured borrowing rates over various lengths of time that most closely corresponds to DESC's lease maturities.

New Accounting Standards

New Accounting Standards

LEASES

In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases classified as operating leases, while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.

The guidance became effective for DESC's interim and annual reporting periods beginning January 1, 2019. DESC adopted this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. DESC applied the practical expedients, which required no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no evaluation of existing or expired land easements that were not previously accounted for as leases. In connection with the adoption of this revised accounting guidance, DESC recorded

$19 million of offsetting right-of-use assets and liabilities for operating leases in effect at the adoption date. See Note 13 for additional information.

TAX REFORM

In February 2018, the FASB issued revised accounting guidance to provide clarification on the application of the 2017 Tax Reform Act for balances recorded within AOCI. The revised guidance provides for stranded amounts within AOCI from the impacts of the 2017 Tax Reform Act to be reclassified to retained earnings. DESC adopted this guidance for interim and annual reporting periods beginning January 1, 2019 on a prospective basis. In connection with the adoption of this guidance, DESC reclassified a benefit of $1 million from AOCI to retained earnings. The amounts reclassified reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of DESC’s AOCI.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Schedule of Weighted Average Depreciation Rates

The composite weighted average depreciation rates for utility plant by function were as follows:

	2021(1)			2020
Generation		2.46	%		2.50	%
Transmission		2.56	%		2.56	%
Distribution		2.48	%		2.42	%
Storage		2.85	%		2.75	%
General and other		2.27	%		3.17	%

(1) Rates include the impact of a change in depreciation rates approved in connection with the settlement of the electric base rate case, which resulted in a decrease to depreciation expense of $6 million and an expected annual decrease of $12 million.

Schedule of Cash and Cash Equivalents

The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within DESC’s Consolidated Balance Sheets to the corresponding amounts reported within DESC’s Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019:

	Cash, Restricted Cash and Equivalents at End/Beginning of Year
	December 31, 2021		December 31, 2020		December 31, 2019		December 31, 2018
(millions)
Cash and cash equivalents	$	30	$	5	$	4	$	377
Restricted cash and equivalents(1)		24		—		—		—
Cash, restricted cash and equivalents shown in the    Consolidated Statements of Cash Flows	$	54	$	5	$	4	$	377

(1) At December 31 2020, 2019 and 2018 there were no restricted cash and equivalent balances.

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Rate and Other Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2021

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities

At December 31,	2021		2020
(millions)
Regulatory assets:
NND Project costs(1)	$	138		138
Deferred employee benefit plan costs(2)		8		9
Other unrecovered plant(3)		16		14
DSM programs(4)		23		29
AROs(5)		2		2
Cost of fuel and purchased gas under-collections(6)		126		1
Other		48		36
Regulatory assets - current		361		229
NND Project costs(1)		2,226		2,364
AROs(5)		311		309
Cost of reacquired debt(7)		10		243
Deferred employee benefit plan costs(2)		106		159
Deferred losses on interest rate derivatives(8)		295		308
Other unrecovered plant(3)		57		61
DSM programs(4)		45		46
Environmental remediation costs(9)		30		20
Deferred storm damage costs(10)		38		45
Deferred transmission operating costs(11)		77		63
Other(12)		128		108
Regulatory assets - noncurrent		3,323		3,726
Total regulatory assets	$	3,684	$	3,955
Regulatory liabilities:
Monetization of guaranty settlement(13)	$	67		67
Income taxes refundable through future rates(14)		42		21
Reserve for refunds to electric utility customers(15)		113		128
Cost of fuel and purchased gas over-collections(6)		—		58
Derivatives(16)		18		—
Other		5		9
Regulatory liabilities - current		245		283
Monetization of guaranty settlement(13)		831		903
Income taxes refundable through future rates(14)		903		919
Asset removal costs(17)		570		564
Deferred gains on interest rate derivatives(8)		67		69
Reserve for refunds to electric utility customers(15)		425		540
Derivatives(16)		131		—
Other		9		10
Regulatory liabilities - noncurrent		2,936		3,005
Total regulatory liabilities	$	3,181	$	3,288

(1) Reflects expenditures associated with the NND Project, which pursuant to the SCANA Merger Approval Order, will be recovered from electric service customers over a 20-year period ending in 2039. See Note 12 for more information.

(2) Employee benefit plan costs have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific South Carolina Commission regulatory orders. DESC expects to recover deferred pension costs through utility rates over periods through 2044. DESC expects to recover other deferred benefit costs through utility rates, primarily over average service periods of participating employees up to 11 years.

(3) Represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. DESC is amortizing these amounts through cost of service rates following depreciation amounts that were designed to recover the retired units cost over their previous estimated remaining useful lives, which has been estimated to be through 2025. Based on current projections of remaining decommissioning costs, projected recovery is expected to extend through 2029. In addition, amounts include unrecovered costs of existing meters and equipment retired from service prior to being fully depreciated as part of the Advanced Metering Infrastructure project, which are being recovered through rates through 2028. This amount also includes certain inventory and preliminary survey and investigation charges being amortized over five years related to the transition or conversion from coal to gas fired generation at certain facilities. Unamortized amounts are included in rate base and are earning a current return.

(4) Represents deferred costs associated with electric demand reduction programs, and such deferred costs are currently being recovered over three years through an approved rate rider.

(5) Represents deferred depreciation and accretion expense related to legal obligations associated with the future retirement of generation, transmission and distribution properties. The AROs primarily relate to DESC’s electric generating facilities, including Summer, and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 105 years.

(6) Represents amounts under- or over-collected from customers pursuant to the cost of fuel components approved by the South Carolina Commission.

(7) In 2021, DESC recorded a charge of $237 million ($178 million after-tax) in impairment of assets and other charges, reflected in the Corporate and Other segment, to write-off the balance of a regulatory asset that is no longer probable of recovery under the settlement agreement approved in DESC’s retail electric base rate case. See South Carolina Electric Base Rate Case discussed above for more information.

(8) Represents (i) the changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043.The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065.

(9) Reflects amounts associated with the assessment and clean-up of sites currently or formerly owned by DESC. Such remediation costs are expected to be recovered over periods of up to 22 years. See Note 12 for more information.

(10) Represents storm restoration costs for which DESC expects to receive future recovery through customer rates over approximately 10 years pursuant to the settlement agreement approved in DESC’s retail electric base rate case. Unamortized amounts are included in rate base and are earning a current return.

(11) Includes deferred depreciation and property taxes associated with certain transmission assets for which DESC expects recovery from customers through future rates over approximately 42 years pursuant to the settlement agreement approved in DESC’s retail electric base rate case. Unamortized amounts are included in rate base and earning a current return. See Note 12 for more information.

(12) Various other regulatory assets are expected to be recovered through rates over varying periods through 2047.

(13) Represents proceeds related to the monetization of the Toshiba Settlement. In accordance with the SCANA Merger Approval Order, this balance, net of amounts that may be required to satisfy liens, will be refunded to electric customers over a 20-year period ending in 2039. See Note 12 for more information.

(14) Includes (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the 2017 Tax Reform Act (certain of which are protected under normalization rules and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over prescribed periods as instructed by regulators) and (ii) deferred income taxes arising from investment tax credits, offset by (iii) deferred income taxes that arise from utility operations that have not been included in customer rates (a portion of which relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to 85 years). See Note 7 for more information.

(15) Reflects amounts previously collected from retail electric customers of DESC for the NND Project to be credited to customers over an estimated 11-year period effective February 2019 in connection with the SCANA Merger Approval Order. See Note 12 for more information.

(16) For jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

(17) Represents estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.

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Operating Revenue (Tables)

12 Months Ended

Dec. 31, 2021

Revenue Recognition And Deferred Revenue [Abstract]

Operating Revenue Subsequent to the Adoption of Guidance for Revenue Recognition from Contracts with Customers

DESC’s operating revenue consists of the following:

Year Ended December 31,	2021				2020
(millions)	Electric		Gas		Electric		Gas
Customer class:
Residential	$	1,211	$	245	$	1,127	$	201
Commercial		834		133		746		103
Industrial		424		103		341		65
Other		157		25		123		18
Revenues from contracts with customers		2,626		506		2,337		387
Other revenues		13		1		15		—
Total Operating Revenues	$	2,639	$	507	$	2,352	$	387

Balance and Activity Related to Contract Costs Deferred as Regulatory Assets

Balances and activity related to contract costs deferred as regulatory assets were as follows:

	Regulatory Assets
(millions)	2021			2020
Beginning balance, January 1	$	12		$	13
Amortization		(1	)		(1	)
Ending balance, December 31	$	11		$	12

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Long-Term and Short-Term Debt (Tables)

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Schedule of Debt

Long-term debt by type with related weighted-average coupon rates and maturities at December 31, 2021 and 2020 is as follows:

At December 31,	2021 Weighted- average Coupon(1)			2021			2020
(millions, except percentages)
DESC:
First Mortgage Bonds, 2.30% to 6.625%, due 2021 to 2065		5.09	%	$	3,634		$	3,267
Tax-Exempt Financings:(2)
Variable rate due 2038		0.14	%		35			35
3.625% and 4.00%, due 2028 and 2033		3.90	%		54			54
Other		3.65	%		1			1
GENCO:
Tax-Exempt Financing, variable rate due 2038		0.14	%		33			33
Affiliated note, 3.05% due 2024		3.05	%		230			230
Total principal					3,987			3,620
Securities due within one year					—			(33	)
Unamortized discount, premium and debt issuance costs, net					(33	)		(30	)
Finance leases					10			15
Total long-term debt				$	3,964		$	3,572

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2021.

(2) Industrial revenue bonds totaling $68 million are secured by letters of credit that expire, subject to renewal, in the fourth quarter of 2022.

Schedule of Principal Payments of Long-Term Debt

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2021, were as follows:

(millions, except percentages)	2022		2023		2024			2025		2026		Thereafter			Total
First Mortgage Bonds	$	—	$	—	$	—		$	—	$	—	$	3,634		$	3,634
Tax-Exempt Financings		—		—		—			—		—		122			122
Other		—		—		230			—		—		1			231
Total	$	—	$	—	$	230		$	—	$	—	$	3,757		$	3,987
Weighted-average coupon						3.05	%						4.99	%

Schedule of Line of Credit Facilities

DESC's share of commercial paper and letters of credit outstanding under its joint credit facility with Dominion Energy, were as follows:

(millions)	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit
At December 31, 2021
Joint revolving credit facility(1)	$	1,000	$	—	$	—
At December 31, 2020
Joint revolving credit facility(1)	$	1,000	$	—	$	—

(1) A maximum of $1.0 billion of the facility is available to DESC, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. A sub-limit for DESC is set within the facility limit but can be changed at the option of the co-borrowers multiple times per year. At December 31, 2021, the sub-limit for DESC was $500 million. If DESC has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term borrowings from DESC's parent or from Dominion Energy. This credit facility matures in June 2026, with the potential to be extended by the borrowers to June 2028. The credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.0 billion (or the sub-limit, whichever is less) of letters of credit.  

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Details of Income Tax Expense for Continuing Operations Including Noncontrolling Interests

Details of income tax expense for continuing operations including noncontrolling interests were as follows:

Year Ended December 31,	2021			2020			2019
(millions)
Current:
Federal	$	(52	)	$	(139	)	$	—
State		(39	)		3			34
Total current expense (benefit)		(91	)		(136	)		34
Deferred:
Federal
Taxes before operating loss carryforwards, investment tax credits and tax reform		61			158			(90	)
Tax utilization expense of operating loss carryforwards		34			33			102
State		7			17			(57	)
Total deferred expense (benefit)		102			208			(45	)
Investment tax credit-amortization		(2	)		(1	)		(1	)
Total income tax expense (benefit)	$	9		$	71		$	(12	)

Schedule of Effective Income Tax Rate Reconciliation

For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to DESC’s effective income tax rate as follows:

Year Ended December 31,	2021			2020			2019
U.S. statutory rate		21.0	%		21.0	%		21.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		5.6			4.2			3.9
AFUDC - equity		(0.4	)		(0.1	)		—
Amortization of federal investment tax credits		(0.6	)		(0.4	)		0.1
Production tax credits		—			—			0.4
Reversal of excess deferred income taxes		(8.1	)		(6.0	)		(1.4	)
NND Project impairment		—			—			(2.4	)
Write-off of regulatory asset		—			—			(15.8	)
Changes in unrecognized tax benefits		(15.8	)		—			(5.1	)
Prior period adjustments		1.6			—			—
Other		0.5			0.1			0.2
Effective tax rate		3.8	%		18.8	%		0.9	%

Schedule of Deferred Income Taxes

DESC’s deferred income taxes consist of the following:

At December 31,	2021			2020
(millions)
Deferred income taxes:
Total deferred income tax assets	$	1,015		$	1,101
Total deferred income tax liabilities		1,974			1,941
Total net deferred income tax liabilities	$	959		$	840
Total deferred income taxes:
Depreciation method and plant basis differences	$	1,139		$	1,098
Excess deferred income taxes		(228	)		(233	)
Unrecovered nuclear plant cost		508			529
DESC rate refund		(113	)		(140	)
Toshiba settlement		(189	)		(204	)
Nuclear decommissioning		(54	)		(51	)
Deferred state income taxes		226			208
Federal benefit of deferred state income taxes		(47	)		(44	)
Deferred fuel, purchased energy and gas costs		27			(12	)
Pension benefits		35			39
Other postretirement benefits		(35	)		(37	)
Loss and credit carryforwards		(343	)		(382	)
Other		33			69
Total net deferred income tax liabilities	$	959		$	840
Deferred Investment Tax Credits-Regulated Operations		16			18
Total Deferred Taxes and Deferred Investment Tax Credits	$	975		$	858

Summary of Tax Credit Carryforwards

At December 31, 2021, DESC had the following deductible loss and credit carryforwards:

(millions)	Deductible Amount		Deferred Tax Asset		Expiration Period
Federal losses	$	890	$	187	2037
Federal production and other credits		—		29	2035-2041
State losses		2,617		131	2037-2040
State investment and other credits		—		27	2026-2031
Total	$	3,507	$	374

Schedule of Unrecognized Tax Benefits Roll Forward

A reconciliation of changes in DESC’s unrecognized tax benefits follows:

(millions)	2021			2020		2019
Balance at January 1	$	138		$	132	$	106
Increases-prior period positions		6			5		76
Decreases-prior period positions		(57	)		—		(53	)
Increases-current period positions		1			1		3
Settlements with tax authorities		(26	)		—		—
Balance at December 31	$	62		$	138	$	132

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Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2021

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Offsetting Liabilities

The table below presents derivative balances by type of financial instrument, if the gross amounts recognized in the Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid. DESC’s commodity derivative assets are not subject to a master netting agreement or similar arrangement.

	December 31, 2021								December 31, 2020
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
(millions)	Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
Interest rate contracts:
Over-the-counter	$	19	$	—	$	11	$	8	$	27	$	—	$	17	$	10
Total derivatives	$	19	$	—	$	11	$	8	$	27	$	—	$	17	$	10

Schedule of Volume of Derivative Activity

The following table presents the volume of derivative activity at December 31, 2021. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions.

	Current		Noncurrent
Electricity (MWh in millions):
Fixed price		2		23
Interest rate(1) (in millions)	$	—	$	71

(1)   Maturity is determined based on final settlement period.

Fair Value of Derivatives

The following table presents the fair values of derivatives and where they are presented in the Consolidated Balance Sheets:

(millions)	Fair Value - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
At December 31, 2021
Current Assets
Commodity	$	—	$	18	$	18
Total current derivative assets (1)		—		18		18
Noncurrent Assets
Commodity		—		130		130
Total noncurrent derivative assets (2)		—		130		130
Total derivative assets	$	—	$	148	$	148
Current Liabilities
Interest rate	$	1	$	1	$	2
Total current derivative liabilities(3)		1		1		2
Noncurrent Liabilities
Interest rate		11		6		17
Total noncurrent derivative liabilities(4)		11		6		17
Total derivative liabilities	$	12	$	7	$	19
At December 31, 2020
Current Liabilities
Interest rate	$	1	$	1	$	2
Total current derivative liabilities(3)		1		1		2
Noncurrent Liabilities
Interest rate		15		10		25
Total noncurrent derivative liabilities(4)		15		10		25
Total derivative liabilities	$	16	$	11	$	27

(1)   Current derivative assets are presented in other current assets in DESC’s Consolidated Balance Sheets.

(2) Noncurrent derivative assets are presented in other deferred debits and other assets in DESC’s Consolidated Balance Sheets.

(3)   Current derivative liabilities are presented in other current liabilities in DESC’s Consolidated Balance Sheets.

(4)  Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in DESC’s Consolidated Balance Sheets.

Derivatives in Cash Flow Hedging Relationships

The following tables present the gains and losses on derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Comprehensive Income (Loss):

Derivatives in Cash Flow Hedging Relationships

(millions)	Increase (Decrease) in Derivatives Subject to Regulatory Treatment(1)
Year Ended December 31, 2021
Derivative type and location of gains (losses):
Interest rate	$	9
Total	$	9
Year Ended December 31, 2020
Derivative type and location of gains (losses):
Interest rate	$	1
Total	$	1
Year Ended December 31, 2019
Derivative type and location of gains (losses):
Interest rate	$	1
Total	$	1

(1)   Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/ liabilities have no associated effect in the Consolidated Statements of Comprehensive Income (Loss).

Derivatives Not Designated as Hedging Instruments

Derivatives Not designated as Hedging Instruments

(millions)	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2021			2020			2019
Derivative type and location of gains (losses):
Commodity contracts:
Purchased power	$	8			—			—
Interest rate contracts:
Interest charges		(2	)		(1	)		(1	)
Total	$	6		$	(1	)	$	(1	)

(1)   Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in the Consolidated Statements of Comprehensive Income (Loss).

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Fair Value Measurements, Including Derivatives (Tables)

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Schedule of Quantitative Information About Level 3 Fair Value Measurements

The following table presents DESC’s quantitative information about Level 3 fair value measurements at December 31, 2021. The range and weighted average are presented in dollars for market price inputs.

	Fair Value (millions)		Valuation Techniques	Unobservable Input	Range	Weighted Average(1)
Assets
Physical forwards:
Electricity	$	148	Discounted cash flow	Market price (per MWh)(2)	28-74	43
Total assets	$	148

(1)   Averages weighted by volume.

(2)   Represents market prices beyond defined terms for Levels 1 and 2.

Schedule of Sensitivity of The Fair Value Measurements To Changes in The Significant Unobservable Inputs

Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)

Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis

The following table presents DESC’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:

	Level 1		Level 2		Level 3		Total
(millions)
At December 31, 2021
Assets
Commodity	$	—	$	—	$	148	$	148
Total assets	$	—	$	—	$	148	$	148
Liabilities
Interest rate	$	—	$	19	$	—	$	19
Total liabilities	$	—	$	19	$	—	$	19
At December 31, 2020
Liabilities
Interest rate	$	—	$	27	$	—	$	27
Total liabilities	$	—	$	27	$	—	$	27

Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis and included in Level 3

The following table presents the net change in DESC's assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category. There were no net changes in assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category for the year ended December 31, 2020.

	2021
(millions)
Balance at January 1,	$	—
Total realized and unrealized gains (losses):
Included in earnings:
Purchased power		8
Included in regulatory assets/liabilities		148
Settlements		(8	)
Balance at December 31,	$	148

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

For financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:

At December 31,	2021				2020
(millions)	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
Long-term debt(2)	$	3,724	$	4,831	$	3,360	$	4,748
Affiliated long-term debt		230		230		230		230

(1)   Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2)   Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs and discount or premium.

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2021

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Reconciliation of the Carrying Amount of AROs

A reconciliation of the beginning and ending aggregate carrying amount of AROs is as follows:

(millions)	2021			2020
Beginning balance	$	597		$	489
Liabilities settled		—			(4	)
Accretion expense		25			23
Revisions in estimated cash flows(1)		(23	)		89
Ending balance	$	599		$	597

(1)   The decrease in 2021 is due to the remeasurement of gas pipeline AROs. The increase in 2020 reflects revisions from the nuclear decommissioning cost study.

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Employee Benefit Plans and Equity Compensation Plan (Tables)

12 Months Ended

Dec. 31, 2021

Compensation And Retirement Disclosure [Abstract]

Schedule of Changes in Projected Benefit Obligations

The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below.

	Pension Benefits						Other Postretirement Benefits
(millions)	2021			2020			2021			2020
Benefit obligation, January 1	$	742		$	727		$	184		$	214
Service cost		9			12			1			3
Interest cost		20			24			6			8
Plan participants’ contributions		—			—			—			2
Actuarial (gain) loss		(28	)		41			(8	)		(31	)
Benefits paid		(41	)		(22	)		(12	)		(13	)
Settlements		—			(40	)		—			—
Curtailment		—			—			—			—
Amounts funded to parent		—			—			—			1
Benefit obligation, December 31	$	702		$	742		$	171		$	184

Schedule of Assumptions Used to Determine Benefit Obligations

Significant assumptions used to determine the above benefit obligations are as follows:

	Pension Benefits						Other Postretirement Benefits
	2021			2020			2021			2020
Annual discount rate used to determine benefit obligation		3.06	%		2.73	%		3.11	%		2.80	%
Assumed annual rate of future salary increases for projected    benefit obligation		3.71	%		4.52	%	N/A			N/A
Crediting interest rate for cash balance plans		1.81	%		1.93	%	N/A			N/A

Schedule of Net Funded Status

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021			2020
(millions)
Fair value of plan assets	$	768	$	747	$	—		$	—
Benefit obligation		702		742		171			184
Funded status	$	66	$	5	$	(171	)	$	(184	)

Schedule of Amounts Recognized in Balance Sheet

Amounts recognized on the consolidated balance sheets were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021			2020
(millions)
Noncurrent assets	$	66	$	5	$	—		$	—
Current liability		—		—		(10	)		(11	)
Noncurrent liability		—		—		(161	)		(173	)

Schedule of Amounts Recognized in Accumulated Other Comprehensive Loss

Amounts recognized in accumulated other comprehensive loss were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021		2020
(millions)
Net actuarial loss	$	1	$	4	$	—	$	—

Schedule of Amounts Recognized in Regulatory Assets

Amounts recognized in regulatory assets were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021			2020
(millions)
Net actuarial (gain) loss	$	70	$	114	$	(5	)	$	1

Schedule of Changes in Fair Value of Plan Assets

Changes in Fair Value of Plan Assets

Pension Benefits
(millions)	2021			2020
Fair value of plan assets, January 1	$	747		$	725
Actual return (loss) on plan assets		62			84
Benefits paid		(41	)		(22	)
Settlements		—			(40	)
Fair value of plan assets, December 31	$	768		$	747

Schedule of Fair Value Measurements By Category

At December 31, 2021 and 2020, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

At December 31,	2021								2020
(millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	—	$	1	$	—	$	1	$	10	$	—	$	—	$	10
Corporate debt instruments		—		332		—		332		—		315		—		315
Government and other debt instruments		—		67		—		67		—		35		—		35
Total recorded at fair value	$	—	$	400	$	—	$	400	$	10	$	350	$	—	$	360
Assets recorded at NAV(1)
Common/collective trust funds								387								387
Total recorded at NAV							$	387							$	387
Total investments(2)							$	787							$	747

(1) These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient are not required to be categorized in the fair value hierarchy.

Schedule of Expected Benefit Payments

Expected Benefit Payments

(millions)	Pension Benefits		Other Postretirement Benefits
2022	$	46	$	11
2023		44		11
2024		46		11
2025		45		11
2026		43		11
2027 - 2031		201		57

Components of Net Periodic Benefit Cost

Components of Net Periodic Benefit Cost

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2021			2020			2019			2021		2020		2019
(millions)
Service cost	$	9		$	12		$	15		$	1	$	3	$	3
Interest cost		20			24			28			6		8		9
Expected return on assets		(48	)		(45	)		(40	)		—		—		—
Prior service cost amortization		—			—			—			—		—		—
Amortization of actuarial losses		6			6			11			—		—		—
Settlement loss		—			7			16			—		—		—
Curtailment		—			—			6			—		—		3
Net periodic benefit cost	$	(13	)	$	4		$	36		$	7	$	11	$	15

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss)

Other changes in plan assets and benefit obligations recognized in other comprehensive income (net of tax) were as follows:

	Pension Benefits								Other Postretirement Benefits
Year Ended December 31,	2021			2020		2019			2021		2020			2019
(millions)
Current year actuarial (gain) loss	$	(3	)	$	2	$	(1	)	$	—	$	(2	)	$	1
Total recognized in other comprehensive income	$	(3	)	$	2	$	(1	)	$	—	$	(2	)	$	1

Schedule of Defined Benefit Plan Amounts Recognized in Regulatory Assets

Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows:

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2021			2020			2019			2021			2020			2019
(millions)
Current year actuarial (gain) loss	$	(39	)	$	1		$	(51	)	$	(6	)	$	(27	)	$	20
Amortization of actuarial losses		(5	)		(6	)		(11	)		—			(1	)		—
Settlement loss		—			(6	)		(16	)		—			—			—
Total recognized in regulatory assets	$	(44	)	$	(11	)	$	(78	)	$	(6	)	$	(28	)	$	20

Schedule of Assumptions Used in Determining Net Periodic Benefit Cost

Significant assumptions used in determining net periodic benefit cost:

	Pension Benefits			Other Postretirement Benefits
Year Ended December 31,	2021	2020	2019	2021	2020	2019
Discount rate	2.73%	3.47%	3.57/4.38%	2.80%	2.80%	4.08/4.41%
Expected return on plan assets	7.00%	7.00%	7.00%	n/a	n/a	n/a
Rate of compensation increase	4.52%	3.00%	3.00%	n/a	n/a	n/a
Crediting interest rate for cash balance plans	1.93%	2.67%	2.77/3.58%	n/a	n/a	n/a
Health care cost trend rate				6.25%	6.25%	6.60%
Ultimate health care cost trend rate				5.00%	5.00%	5.00%
Year achieved				2025-2026	2025-2026	2023

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2021

Commitments And Contingencies Disclosure [Abstract]

Schedule of Long-Term Purchase Agreements

At December 31, 2021, DESC had the following long-term commitments that are noncancelable or cancelable only under certain conditions, and that a third party that will provide the contracted goods or services has used to secure financing.

(millions)	2022		2023		2024		2025		2026		Thereafter		Total
Purchased electric capacity(1)	$	83	$	82	$	82	$	83	$	86	$	834	$	1,250

(1)   Includes affiliated amounts with certain solar facilities of $238 million.

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Leases (Tables)

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Schedule of Lease Assets and Liabilities Recorded in Consolidated Balance Sheets

At December 31, 2021 and 2020, DESC had the following lease assets and liabilities recorded in the Consolidated Balance Sheets:

At December 31,	2021		2020
(millions)
Lease assets:
Operating lease assets(1)	$	19	$	21
Finance lease assets(2)		13		20
Total lease assets	$	32	$	41
Lease liabilities:
Operating lease - current(3)	$	2	$	3
Operating lease - noncurrent(4)		17		18
Finance lease - current(5)		5		6
Finance lease - noncurrent		10		15
Total lease liabilities	$	34	$	42

(1)   Included in other deferred debits and other assets in the Consolidated Balance Sheets.

(2)   Included in utility plant, net, in the Consolidated Balance Sheets, net of $20 million and $24 million of accumulated amortization at December 31, 2021 and December 31, 2020, respectively.

(3)   Included in other current liabilities in the Consolidated Balance Sheets.

(4)   Included in other deferred credits and other liabilities in the Consolidated Balance Sheets.

(5)   Included in securities due within one year in the Consolidated Balance Sheets.

Summary of Total Lease Cost

For the years ended December 31, 2021, 2020 and 2019, total lease cost consisted of the following:

Year Ended December 31,	2021		2020		2019
(millions)
Finance lease cost:
Amortization	$	6	$	8	$	7
Interest		1		1		1
Operating lease cost		4		4		4
Short-term lease cost		2		2		1
Total lease cost	$	13	$	15	$	13

Cash Paid for Amounts Included in Measurement of Lease Liabilities

For the years ended December 31, 2021, 2020 and 2019, cash paid for amounts included in the measurement of lease liabilities consisted of the following amounts, included in the Consolidated Statements of Cash Flows:

Year Ended December 31,	2021		2020		2019
(millions)
Operating cash flows from finance leases	$	1	$	1	$	1
Operating cash flows from operating leases		4		4		3
Financing cash flows from finance leases		6		8		7

Summary of Weighted Average Remaining Lease Term And Discount Rate for Operating and Finance Leases

At December 31, 2021 and 2020, the weighted average remaining lease term and weighted average discount rate for finance and operating leases were as follows:

At December 31,	2021			2020
Weighted average remaining lease term - finance leases	4 years			4 years
Weighted average remaining lease term - operating leases	20 years			19 years
Weighted average discount rate - finance leases		2.91	%		2.92	%
Weighted average discount rate - operating leases		3.97	%		3.95	%

Schedule of Maturity Analysis of Operating and Finance Lease Liabilities

Lease liabilities have the following scheduled maturities:

(millions)	Operating			Finance
2022	$	3		$	5
2023		2			4
2024		2			3
2025		1			1
2026		1			1
After 2026		21			1
Total undiscounted lease payments		30			15
Present value adjustment		(11	)		(1	)
Present value of lease liabilities	$	19		$	14

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Operating Segments (Tables)

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

The following table presents segment information pertaining to DESC’s operations:

Year Ended December 31,	Dominion Energy South Carolina		Corporate and Other			Consolidated Total
(millions)
2021
External revenue	$	3,146	$	—		$	3,146
Depreciation and amortization		486		—			486
Interest and related charges		215		(23	)		192
Income tax expense (benefit)		125		(116	)		9
Comprehensive income (loss) available (attributable) to    common shareholder		421		(212	)		209
Capital expenditures		758		—			758
Total assets (billions)		14.9		—			14.9
2020
External revenue	$	2,739	$	—		$	2,739
Depreciation and amortization		474		—			474
Interest and related charges		223		6			229
Income tax expense (benefit)		107		(36	)		71
Comprehensive income (loss) available (attributable) to    common shareholder		410		(113	)		297
Capital expenditures		742		—			742
Total assets (billions)		14.5		—			14.5
2019
External revenue	$	2,937	$	(1,008	)	$	1,929
Depreciation and amortization		452		(2	)		450
Interest and related charges		247		13			260
Income tax expense (benefit)		163		(175	)		(12	)
Comprehensive income (loss) available (attributable) to    common shareholder		408		(1,647	)		(1,239	)
Capital expenditures		497		—			497

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Utility Plant and Nonutility Property (Tables)

12 Months Ended

Dec. 31, 2021

Utility Plant And Non Utility Property [Abstract]

Property, Plant and Equipment

Major classes of utility plant and other property and their respective balances at December 31, 2021 and 2020 were as follows:

At December 31,	2021		2020
(millions)
Gross utility plant:
Generation	$	6,053	$	5,921
Transmission		2,037		1,963
Distribution		5,191		4,909
Storage		76		74
General and other		601		563
Intangible		242		250
Construction work in progress		481		460
Nuclear fuel		603		575
Total gross utility plant	$	15,284	$	14,715
Gross nonutility property	$	44	$	45

Schedule of Jointly Owned Utility Plants

At December 31,	2021			2020
	Summer Unit 1			Summer Unit 1
Percent owned	66.7%			66.7%
Plant in service	$	1.6	billion	$	1.6	billion
Accumulated depreciation	$	725	million	$	702	million
Construction work in progress	$	76	million	$	62	million

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Affiliated and Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2021

Related Party Transactions [Abstract]

Schedule of Affiliated Transactions

Amounts expensed are primarily recorded in other operations and maintenance – affiliated suppliers and other expense, net in the Consolidated Statements of Comprehensive Income (Loss).

Year Ended December 31,	2021		2020		2019
(millions)
Purchases of coal from affiliate	$	—	$	—	$	121
Sales of coal to affiliate		—		—		120
Purchases of fuel used in electric generation from affiliate		—		—		43
Direct and allocated costs from DES and DESS(1)		226		294		297
Operating Revenues – Electric from sales to affiliate		4		4		4
Operating Revenues – Gas from sales to affiliate		1		1		1
Operating Expenses – Other taxes from affiliate		7		9		6
Purchases of electricity from solar affiliates		14		12		8
Demand and transportation charges from DECG - Fuel used in    electric generation		—		16		19
Demand and transportation charges from DECG - Gas purchased    for resale		—		36		44

(1)   Includes capitalized expenditures of $37 million, $81 million and $53 million for the years ended December 31, 2021, 2020 and 2019, respectively.

Schedule of Affiliated Transactions

At December 31,	2021		2020
(millions)
Payable to DES and DESS		30		59
Payable to Public Service Company of North Carolina, Incorporated		—		5
Receivable from Public Service Company of North Carolina, Incorporated		60		—
Payable to solar affiliates		1		1
Receivable from nuclear affiliates		1		—
Payable to DEI		1		—
Derivative assets with affiliates(1)		28		—

(1)   Effective in the second quarter of 2021, contracts for the future purchase of certain quantities of electricity from solar affiliates no longer met the criteria for the normal purchase normal sale exception and are accounted for as derivative contracts.

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Other Income (Expense), Net (Tables)

12 Months Ended

Dec. 31, 2021

Income Statement [Abstract]

Components of Other Income (Expense), Net

Components of other income (expense), net are as follows:

Year Ended December 31,	2021			2020			2019
(millions)
Revenues from contracts with customers	$	—		$	1		$	4
Other income		11			13			19
Other expense		(18	)		(38	)		(57	)
Allowance for equity funds used during construction		5			1			1
Other expense, net	$	(2	)	$	(23	)	$	(33	)

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Nature of Operations (Narrative) (Detail)	12 Months Ended
	Dec. 31, 2021 Segment
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Number of primary operating segments	1

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Summary of Significant Accounting Policies (Narrative) (Detail) $ in Millions		3 Months Ended	6 Months Ended	12 Months Ended
	Jan. 01, 2019 USD ($)	Sep. 30, 2021 USD ($)	Jun. 30, 2021 USD ($)	Dec. 31, 2021 USD ($) MW		Dec. 31, 2020 USD ($)		Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Significant Accounting Policies
Public utilities, allowance for funds used during construction, rate				2.60%		2.60%		4.30%
Utilities operating expense, maintenance and operations				$ 417		$ 357		$ 388
Turbine maintenance expense				20		19
Amount accrued annually for nuclear fuel outages				17
Nuclear refueling outage cost				24		23
Amount accrued annually for tree trimming and vegetation management		$ 28		9
Tree trimming and vegetation management cost				9
Decommissioning liability, noncurrent				764
Payments to acquire investments to be held in decommissioning trust fund				3
Restricted cash and equivalent balances				24	[1]	0		0	$ 0
Unbilled revenues				139		156
Unrecognized tax benefits				62		138		132	$ 106
Interest expense				21		7		18
Interest income								2
Penalty expenses						4		$ 7
Income taxes related to affiliated payable						31
Income taxes related to affiliated receivable				24
Margin liabilities with cash collateral				0		0
Margin assets with cash collateral				$ 11		17
Option to extend, existence, operating lease				true
Operating lease, right of use asset	$ 19			$ 19	[2]	21	[2]
Operating lease liability	$ 19			19
Operating Lease, Liability, Statement of Financial Position [Extensible Enumeration]	Other
Reclassification From AOCI to retained earnings	$ 1
Maximum [Member]
Significant Accounting Policies
Interest income				$ 1		$ 1
Lease renewal term				70 years
Original term of leases				1 year
Minimum [Member]
Significant Accounting Policies
Lease renewal term				1 year
Accounts Receivable [Member] | Credit Concentration Risk [Member] | Residential Commercial And Industrial Customers
Significant Accounting Policies
Concentration risk percentage				6.00%
Turbine [Member]
Significant Accounting Policies
Utilities operating expense, maintenance and operations		$ 25	$ 18
Genco
Significant Accounting Policies
Power Generation Capacity Megawatts | MW				605

[1] At December 31 2020, 2019 and 2018 there were no restricted cash and equivalent balances.

[2] Included in other deferred debits and other assets in the Consolidated Balance Sheets.

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Summary of Significant Accounting Policies (Schedule of Weighted Average Depreciation Rates) (Detail)	12 Months Ended
	Dec. 31, 2021	[1]	Dec. 31, 2020
Generation
Composite weighted average depreciation rates for utility plant	2.46%		2.50%
Transmission
Composite weighted average depreciation rates for utility plant	2.56%		2.56%
Distribution
Composite weighted average depreciation rates for utility plant	2.48%		2.42%
Storage
Composite weighted average depreciation rates for utility plant	2.85%		2.75%
General and other
Composite weighted average depreciation rates for utility plant	2.27%		3.17%

[1] (1) Rates include the impact of a change in depreciation rates approved in connection with the settlement of the electric base rate case, which resulted in a decrease to depreciation expense of $6 million and an expected annual decrease of $12 million.

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Summary of Significant Accounting Policies (Schedule of Weighted Average Depreciation Rates) (Parenthetical) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Accounting Policies [Abstract]
Public utilities, decrease in depreciation expense	$ 6
Public utilities, annual decrease in depreciation expense	$ 12

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Summary of Significant Accounting Policies (Schedule of Cash and Cash equivalents) (Details) - USD ($) $ in Millions		Dec. 31, 2021		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Cash and cash equivalents		$ 30		$ 5	$ 4	$ 377
Restricted cash and equivalents		24	[1]	0	0	0
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	[2]	$ 54		$ 5	$ 4	$ 377

[1] At December 31 2020, 2019 and 2018 there were no restricted cash and equivalent balances.

[2] Includes $24 million of restricted cash for the year ended December 31, 2021. For the years ended December 31, 2020 and 2019 there were no restricted cash and equivalent balances.

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Rate and Other Regulatory Matters (Narrative) (Detail) - USD ($) $ in Millions		1 Months Ended								3 Months Ended			6 Months Ended	12 Months Ended
	Sep. 01, 2021	Feb. 28, 2022	Feb. 25, 2022	Oct. 31, 2021	Jul. 31, 2021	Jun. 30, 2021	May 31, 2021	Apr. 30, 2021	Aug. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Feb. 25, 2021
Rate And Other Regulatory Matters [Line Items]
Percentage of current authorized earned ROE				9.90%
Other asset impairment charges													$ 249
Other asset impairment charges after tax													187
Purchase of first mortgage bond													$ 237
Recovery under settlement agreement														$ 18
Recovery under settlement agreement after tax														$ 14
South Carolina Commission Order for Increase/Decrease of Total Fuel Cost Component of Retail Electric Rates to produce a projected under-recovery			$ 143														$ 36
South Carolina Commission Order, Annual DSM Program Rate Rider Recovery Amount								$ 60
Annual increase (decrease) in pension cost rider		$ (12)
South Carolina Commission order, revenue requirement under RSA				$ 424		$ 426
South Carolina Commission order, increase in natural gas rates under RSA				$ 7		$ 9
Regulatory asset recovery assessment end period														2047
Impairment of assets and other charges												$ 105		$ 311	$ (14)	$ 576
Monetization Of Guaranty Settlement [Member]
Rate And Other Regulatory Matters [Line Items]
Electric service customers over period														20 years
End period for recovery														2039
Income Taxes Refundable Through Future Rates [Member]
Rate And Other Regulatory Matters [Line Items]
Remaining lives of related property period														85 years
Reserve For Refunds To Electric Utility Customers [Member]
Rate And Other Regulatory Matters [Line Items]
Electric service customers over period														11 years
Deferred Losses or Gains On Interest Rate Derivatives [Member]
Rate And Other Regulatory Matters [Line Items]
Changes in fair value and payments of interest rate derivatives designated as cash flow hedge, amortized to interest expense, year														2043
Changes in fair value and payments of interest rate derivatives not designed, amortized to interest, year														2065
Dominion Energy South Carolina [Member]
Rate And Other Regulatory Matters [Line Items]
Impairment of assets and other charges														$ 237
Impairment of assets and other charges, after-tax														$ 178
NND Project Costs [Member]
Rate And Other Regulatory Matters [Line Items]
Electric service customers over period														20 years
End period for recovery														2039
Deferred Employee Benefit Plan Costs [Member]
Rate And Other Regulatory Matters [Line Items]
Regulatory asset recovery assessment end period														2044
Average service period expected to recover other deferred benefit costs														11 years
Other Unrecovered Plant [Member]
Rate And Other Regulatory Matters [Line Items]
Remaining useful lives of coal-fired generating units, year														2025
New expected remaining useful lives of coal-fired generating units, year														2029
Recovery period for existing meters and equipment retired from service														2028
Demand Side Management Programs [Member]
Rate And Other Regulatory Matters [Line Items]
Recovery period of regulatory asset														3 years
Asset Retirement Obligation Costs [Member]
Rate And Other Regulatory Matters [Line Items]
Recovery period of regulatory asset														105 years
Environmental Remediation Costs [Member]
Rate And Other Regulatory Matters [Line Items]
MPG environmental remediation														22 years
Maximum [Member]
Rate And Other Regulatory Matters [Line Items]
Annual increase (decrease) in pension cost rider								(1)
Rider D S M
Rate And Other Regulatory Matters [Line Items]
South Carolina Commission Order, Annual DSM Program Rate Rider Recovery Amount	$ 43							$ 48
South Carolina Electric Base Rate Case
Rate And Other Regulatory Matters [Line Items]
Amount of Increase in proposed non fuel base rate									$ 178
Increase in proposed non fuel base rate									7.75%
Percentage of ROE based on fully adjusted test period									5.90%
Percentage of current authorized earned ROE									10.25%
South Carolina Office Of Regulatory Staff And Other Parties [Member]
Rate And Other Regulatory Matters [Line Items]
Amount of Increase in proposed non fuel base rate					$ 62
Percentage of current authorized earned ROE					9.50%
Non fuel base rate increase after amortization					$ 36
Retail electric customer balance					15
Due days for forgive retail electric customer balance							60 days
Welfare charges for customers					$ 15
Toshiba Corporation [Member]
Rate And Other Regulatory Matters [Line Items]
Bankruptcy, amount of claims filed			$ 66
Savannah River Site
Rate And Other Regulatory Matters [Line Items]
Interest charges (benefit)										$ (10)	$ 6
Interest charges (benefit), after tax										$ (7)	$ 4

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Rate and Other Regulatory Matters (Schedule of Regulatory Assets) (Detail) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Regulatory Assets
Regulatory assets, current		$ 361	$ 229
Regulatory assets, noncurrent		3,323	3,726
Total regulatory assets		3,684	3,955
NND Project Costs [Member]
Regulatory Assets
Regulatory assets, current	[1]	138	138
Regulatory assets, noncurrent	[1]	2,226	2,364
Deferred Employee Benefit Plan Costs [Member]
Regulatory Assets
Regulatory assets, current	[2]	8	9
Regulatory assets, noncurrent	[2]	106	159
Other Unrecovered Plant [Member]
Regulatory Assets
Regulatory assets, current	[3]	16	14
Regulatory assets, noncurrent	[3]	57	61
Demand Side Management Programs [Member]
Regulatory Assets
Regulatory assets, current	[4]	23	29
Regulatory assets, noncurrent	[4]	45	46
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory assets, current	[5]	2	2
Regulatory assets, noncurrent	[5]	311	309
Cost of Fuel and Purchased Gas Under-Collections [Member]
Regulatory Assets
Regulatory assets, current	[6]	126	1
Other Regulatory Assets [Member]
Regulatory Assets
Regulatory assets, current		48	36
Regulatory assets, noncurrent	[7]	128	108
Cost of Reacquired Debt [Member]
Regulatory Assets
Regulatory assets, noncurrent	[8]	10	243
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets
Regulatory assets, noncurrent	[9]	295	308
Environmental Remediation Costs [Member]
Regulatory Assets
Regulatory assets, noncurrent	[10]	30	20
Deferred Storm Damage Costs [Member]
Regulatory Assets
Regulatory assets, noncurrent	[11]	38	45
Deferred Transmission Operating Costs [Member]
Regulatory Assets
Regulatory assets, noncurrent	[12]	$ 77	$ 63

[1] Reflects expenditures associated with the NND Project, which pursuant to the SCANA Merger Approval Order, will be recovered from electric service customers over a 20-year period ending in 2039. See Note 12 for more information

[2] Employee benefit plan costs have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific South Carolina Commission regulatory orders. DESC expects to recover deferred pension costs through utility rates over periods through 2044. DESC expects to recover other deferred benefit costs through utility rates, primarily over average service periods of participating employees up to 11 years.

[3] Represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. DESC is amortizing these amounts through cost of service rates following depreciation amounts that were designed to recover the retired units cost over their previous estimated remaining useful lives, which has been estimated to be through 2025. Based on current projections of remaining decommissioning costs, projected recovery is expected to extend through 2029. In addition, amounts include unrecovered costs of existing meters and equipment retired from service prior to being fully depreciated as part of the Advanced Metering Infrastructure project, which are being recovered through rates through 2028. This amount also includes certain inventory and preliminary survey and investigation charges being amortized over five years related to the transition or conversion from coal to gas fired generation at certain facilities. Unamortized amounts are included in rate base and are earning a current return.

[4] Represents deferred costs associated with electric demand reduction programs, and such deferred costs are currently being recovered over three years through an approved rate rider.

[5] Represents deferred depreciation and accretion expense related to legal obligations associated with the future retirement of generation, transmission and distribution properties. The AROs primarily relate to DESC’s electric generating facilities, including Summer, and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 105 years.

[6] Represents amounts under- or over-collected from customers pursuant to the cost of fuel components approved by the South Carolina Commission

[7] Various other regulatory assets are expected to be recovered through rates over varying periods through 2047.

[8] In 2021, DESC recorded a charge of $237 million ($178 million after-tax) in impairment of assets and other charges, reflected in the Corporate and Other segment, to write-off the balance of a regulatory asset that is no longer probable of recovery under the settlement agreement approved in DESC’s retail electric base rate case. See South Carolina Electric Base Rate Case discussed above for more information.

[9] Represents (i) the changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043.The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065.

[10] Reflects amounts associated with the assessment and clean-up of sites currently or formerly owned by DESC. Such remediation costs are expected to be recovered over periods of up to 22 years. See Note 12 for more information.

[11] Represents storm restoration costs for which DESC expects to receive future recovery through customer rates over approximately 10 years pursuant to the settlement agreement approved in DESC’s retail electric base rate case. Unamortized amounts are included in rate base and are earning a current return.

[12] Includes deferred depreciation and property taxes associated with certain transmission assets for which DESC expects recovery from customers through future rates over approximately 42 years pursuant to the settlement agreement approved in DESC’s retail electric base rate case. Unamortized amounts are included in rate base and earning a current return. See Note 12 for more information.

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Rate and Other Regulatory Matters (Schedule of Regulatory Liabilities) (Detail) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Regulatory Liabilities
Regulatory liability, current		$ 245	$ 283
Regulatory liability, noncurrent		2,936	3,005
Total regulatory liabilities		3,181	3,288
Monetization Of Guaranty Settlement [Member]
Regulatory Liabilities
Regulatory liability, current	[1]	67	67
Regulatory liability, noncurrent	[1]	831	903
Income Taxes Refundable Through Future Rates [Member]
Regulatory Liabilities
Regulatory liability, current	[2]	42	21
Regulatory liability, noncurrent	[2]	903	919
Reserve For Refunds To Electric Utility Customers [Member]
Regulatory Liabilities
Regulatory liability, current	[3]	113	128
Regulatory liability, noncurrent	[3]	425	540
Other Regulatory Liability [Member]
Regulatory Liabilities
Regulatory liability, current		5	9
Regulatory liability, noncurrent		9	10
Cost of Fuel and Purchased Gas Over-Collections [Member]
Regulatory Liabilities
Regulatory liability, current	[4]		58
Derivatives [Member]
Regulatory Liabilities
Regulatory liability, current	[5]	18
Regulatory liability, noncurrent	[5]	131
Asset Removal Costs [Member]
Regulatory Liabilities
Regulatory liability, noncurrent	[6]	570	564
Deferred Gains On Interest Rate Derivatives [Member]
Regulatory Liabilities
Regulatory liability, noncurrent	[7]	$ 67	$ 69

[1] Represents proceeds related to the monetization of the Toshiba Settlement. In accordance with the SCANA Merger Approval Order, this balance, net of amounts that may be required to satisfy liens, will be refunded to electric customers over a 20-year period ending in 2039. See Note 12 for more information.

[2] Includes (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the 2017 Tax Reform Act (certain of which are protected under normalization rules and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over prescribed periods as instructed by regulators) and (ii) deferred income taxes arising from investment tax credits, offset by (iii) deferred income taxes that arise from utility operations that have not been included in customer rates (a portion of which relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to 85 years). See Note 7 for more information.

[3] Reflects amounts previously collected from retail electric customers of DESC for the NND Project to be credited to customers over an estimated 11-year period effective February 2019 in connection with the SCANA Merger Approval Order. See Note 12 for more information.

[4] Represents amounts under- or over-collected from customers pursuant to the cost of fuel components approved by the South Carolina Commission

[5] For jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

[6] Represents estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.

[7] Represents (i) the changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043.The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065.

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Operating Revenue (Operating Revenue Subsequent to the Adoption of Guidance for Revenue Recognition from Contracts with Customers) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating revenue from contracts with customers		$ 0	$ 1	$ 4
Total Operating Revenues	[1]	3,146	2,739	$ 1,929
Electric Operations
Operating revenue from contracts with customers		2,626	2,337
Other revenues		13	15
Total Operating Revenues		2,639	2,352
Gas Distribution
Operating revenue from contracts with customers		506	387
Other revenues		1	0
Total Operating Revenues		507	387
Residential | Electric Operations
Operating revenue from contracts with customers		1,211	1,127
Residential | Gas Distribution
Operating revenue from contracts with customers		245	201
Commercial | Electric Operations
Operating revenue from contracts with customers		834	746
Commercial | Gas Distribution
Operating revenue from contracts with customers		133	103
Industrial | Electric Operations
Operating revenue from contracts with customers		424	341
Industrial | Gas Distribution
Operating revenue from contracts with customers		103	65
Other | Electric Operations
Operating revenue from contracts with customers		157	123
Other | Gas Distribution
Operating revenue from contracts with customers		$ 25	$ 18

[1] See Note 16 for amounts attributable to affiliates.

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Operating Revenue (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disaggregation Of Revenue [Line Items]
Contract liability balances	$ 8	$ 5
Revenue recognized from contract liability balances	$ 4	$ 6
Minimum [Member]
Disaggregation Of Revenue [Line Items]
Service Contract, Term	10 years
Maximum [Member]
Disaggregation Of Revenue [Line Items]
Service Contract, Term	15 years

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Operating Revenue (Balance and Activity Related to Contract Costs Deferred as Regulatory Assets) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Revenues [Abstract]
Beginning balance	$ 12	$ 13
Amortization	(1)	(1)
Ending balance	$ 11	$ 12

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Equity (Narrative) (Detail) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Class Of Stock [Line Items]
Common stock, par value		$ 0
Common stock, shares authorized		50,000,000
Common stock, shares issued		40,300,000
Common stock, shares outstanding		40,300,000	40,300,000
Preferred stock, par value		$ 0
Preferred stock, shares authorized		20,000,000
Preferred stock, shares issued		1,000
Preferred stock, shares outstanding		1,000
Contributions from SCANA		$ 0	$ 0	$ 838
Dominion Energy
Class Of Stock [Line Items]
Contributions from SCANA		150		$ 835
Dominion Energy | Common Stock
Class Of Stock [Line Items]
Common stock issued to satisfy the settlement	$ 322
Dominion Energy | FILOT [Member] | Common Stock
Class Of Stock [Line Items]
Common stock issued to satisfy the settlement		104
Dominion Energy | SCDOR [Member] | Common Stock
Class Of Stock [Line Items]
Common stock issued to satisfy the settlement		$ 45
Dominion Energy | DESC Ratepayer Case | Common Stock
Class Of Stock [Line Items]
Common stock issued to satisfy the settlement			$ 322

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Long-Term and Short-Term Debt (Schedule of Debt) (Detail) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Total principal		$ 3,987	$ 3,620
Securities due within one year		0	(33)
Unamortized discount, premium and debt issuance costs, net		(33)	(30)
Finance leases		14
Total long-term debt		3,964	3,572
First Mortgage Bonds
Debt Instrument [Line Items]
Total principal		$ 3,634
First Mortgage Bonds | DESC
Debt Instrument [Line Items]
Weighted-average coupon rate	[1]	5.09%
Total principal		$ 3,634	3,267
Tax Exempt Financings Variable Rate Due 2038 | DESC
Debt Instrument [Line Items]
Weighted-average coupon rate	[1]	0.14%
Total principal	[2]	$ 35	35
Tax Exempt Financings Variable Rate Due 2038 | Genco
Debt Instrument [Line Items]
Weighted-average coupon rate	[1]	0.14%
Total principal		$ 33	33
Tax Exempt Financings 3.625% and 4.00% Due 2028 and 2033 | DESC
Debt Instrument [Line Items]
Weighted-average coupon rate	[1]	3.90%
Total principal	[2]	$ 54	54
Other Debt
Debt Instrument [Line Items]
Total principal		$ 231
Other Debt | DESC
Debt Instrument [Line Items]
Weighted-average coupon rate	[1]	3.65%
Total principal		$ 1	1
3.05% Affiliated Note Due 2024 | Genco
Debt Instrument [Line Items]
Weighted-average coupon rate	[1]	3.05%
Total principal		$ 230	230
Finance Lease
Debt Instrument [Line Items]
Finance leases		$ 10	$ 15

[1] Represents weighted-average coupon rates for debt outstanding as of December 31, 2021.

[2] Industrial revenue bonds totaling $68 million are secured by letters of credit that expire, subject to renewal, in the fourth quarter of 2022.

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Long-Term and Short-Term Debt (Schedule of Debt) (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Redemption of remaining principal outstanding plus accrued interest	$ 34	$ 0	$ 1,890
Letter of Credit
Debt Instrument [Line Items]
Debt instrument, face amount	$ 68
First Mortgage Bonds | Minimum [Member] | DESC
Debt Instrument [Line Items]
Debt Instrument, Maturity Year	2021
Debt instrument, interest rate	2.30%
First Mortgage Bonds | Maximum [Member] | DESC
Debt Instrument [Line Items]
Debt Instrument, Maturity Year	2065
Debt instrument, interest rate	6.625%
Tax Exempt Financings Variable Rate Due 2038 | DESC
Debt Instrument [Line Items]
Debt Instrument, Maturity Year	2038
Tax Exempt Financings Variable Rate Due 2038 | Genco
Debt Instrument [Line Items]
Debt Instrument, Maturity Year	2038
Tax Exempt Financings 3.625% and 4.00% Due 2028 and 2033 | Minimum [Member] | DESC
Debt Instrument [Line Items]
Debt Instrument, Maturity Year	2028
Debt instrument, interest rate	3.625%
Tax Exempt Financings 3.625% and 4.00% Due 2028 and 2033 | Maximum [Member] | DESC
Debt Instrument [Line Items]
Debt Instrument, Maturity Year	2033
Debt instrument, interest rate	4.00%
3.05% Affiliated Note Due 2024 | Genco
Debt Instrument [Line Items]
Debt Instrument, Maturity Year	2024
Debt instrument, interest rate	3.05%

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Long-Term and Short-Term Debt (Schedule of Principal Payments of Long-Term Debt) (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
2022	$ 0
2023	0
2024	230
2025	0
2026	0
Thereafter	3,757
Total	$ 3,987	$ 3,620
Weighted-average coupon, 2024	3.05%
Weighted-average coupon, Thereafter	4.99%
First Mortgage Bonds
Debt Instrument [Line Items]
2022	$ 0
2023	0
2024	0
2025	0
2026	0
Thereafter	3,634
Total	3,634
Tax Exempt Financings
Debt Instrument [Line Items]
2022	0
2023	0
2024	0
2025	0
2026	0
Thereafter	122
Total	122
Other Debt
Debt Instrument [Line Items]
2022	0
2023	0
2024	230
2025	0
2026	0
Thereafter	1
Total	$ 231

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Long-Term and Short-Term Debt (Narrative) (Detail) - USD ($)		1 Months Ended			12 Months Ended
		Mar. 31, 2020	May 31, 2019	Apr. 30, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Unfunded property additions					70.00%
Consecutive months for bond ratio					12 months
Months preceding issuance of bonds					18 months
Bond ratio					6.00%
Redemption of remaining principal outstanding plus accrued interest					$ 34,000,000	$ 0	$ 1,890,000,000
Equity capital contribution returned to parent					150,000,000	0	20,000,000
Commercial paper borrowing limit		$ 2,200,000,000
Interest charges	[1]				192,000,000	229,000,000	$ 260,000,000
Interest income from money pool transactions					1,000,000	2,000,000
Interest expense from money pool transactions					1,000,000	2,000,000
Money pool borrowings due to affiliates						206,000,000
Investments due from affiliates						15,000,000
Maximum [Member]
Debt Instrument [Line Items]
Short term commercial paper maturity period		1 year
Dominion Energy
Debt Instrument [Line Items]
Short-term borrowings outstanding, maximum				$ 900,000,000
Short-term borrowings outstanding					415,000,000	149,000,000
Interest charges						$ 7,000,000
Dominion Energy | Maximum [Member]
Debt Instrument [Line Items]
Interest charges					1,000,000
Current Joint Revolving Credit Facility | Dominion Energy
Debt Instrument [Line Items]
Facility limit					6,000,000,000.0
Letter of Credit
Debt Instrument [Line Items]
Debt instrument, face amount					68,000,000
Facility limit					$ 1,000,000,000.0
Genco
Debt Instrument [Line Items]
Commercial paper borrowing limit		$ 200,000,000
Genco | Maximum [Member]
Debt Instrument [Line Items]
Short term commercial paper maturity period		1 year
Genco | 3.05% Promissory Note due in May 2024
Debt Instrument [Line Items]
Debt instrument, face amount			$ 230,000,000
Debt instrument, interest rate			3.05%
Debt instrument, maturity date			2024-05
Genco | 5.49% Senior Secured Note Due 2024
Debt Instrument [Line Items]
Debt instrument, interest rate			5.49%
Debt Instrument, Maturity Year			2024
Redemption of remaining principal outstanding plus accrued interest			$ 33,000,000
Equity capital contribution returned to parent			$ 20,000,000

[1] See Note 16 for amounts attributable to affiliates.

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Long-Term and Short-Term Debt (Schedule of Line of Credit Facilities) (Detail) - Joint Revolving Credit Facility - USD ($)	Dec. 31, 2021	Dec. 31, 2020	[1]
Debt Instrument [Line Items]
Facility limit	$ 1,000,000,000	$ 1,000,000,000
Outstanding Commercial Paper	0	0
Outstanding Letters of Credit	$ 0	$ 0

[1] A maximum of $1.0 billion of the facility is available to DESC, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. A sub-limit for DESC is set within the facility limit but can be changed at the option of the co-borrowers multiple times per year. At December 31, 2021, the sub-limit for DESC was $500 million. If DESC has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term borrowings from DESC's parent or from Dominion Energy. This credit facility matures in June 2026, with the potential to be extended by the borrowers to June 2028. The credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.0 billion (or the sub-limit, whichever is less) of letters of credit.

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Long-Term and Short-Term Debt (Schedule of Line of Credit Facilities) (Parenthetical) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	[1]
Joint Revolving Credit Facility
Debt Instrument [Line Items]
Facility limit	$ 1,000,000,000	$ 1,000,000,000
Line of credit facility maturity date	2026-06
Line of Credit Facility
Debt Instrument [Line Items]
Facility limit	$ 500,000,000
Letter of Credit
Debt Instrument [Line Items]
Facility limit	$ 1,000,000,000.0

[1] A maximum of $1.0 billion of the facility is available to DESC, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. A sub-limit for DESC is set within the facility limit but can be changed at the option of the co-borrowers multiple times per year. At December 31, 2021, the sub-limit for DESC was $500 million. If DESC has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term borrowings from DESC's parent or from Dominion Energy. This credit facility matures in June 2026, with the potential to be extended by the borrowers to June 2028. The credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.0 billion (or the sub-limit, whichever is less) of letters of credit.

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Income Taxes (Narrative) (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Investments Owned Federal Income Tax Note [Line Items]
Increase in net operating loss utilization				$ 79
Weighted average rate used to originate deferred tax liability		35.00%
Increase Decrease in Income Tax Expense		$ 38
Deferred income taxes, net		117	$ 229	(379)
Regulatory liabilities		(109)	(193)	265
Increase in income tax expense	$ 1
Increase in unrecognized tax benefits	53
Reduction in credit carryforward deferred tax assets	(45)
Increase in accrued taxes	$ 7	$ 7	$ (3)	(10)
Income tax examination, description		The statute is closed for IRS examination of years prior to 2013. The IRS is currently examining DESC’s federal returns from 2013 through 2017. DESC is no longer subject to state and local income tax examinations by tax authorities for years prior to 2018
Decrease in Unrecognized Tax Benefits is Reasonably Possible		$ 13
Maximum [Member]
Investments Owned Federal Income Tax Note [Line Items]
Potential increase in earnings in next twelve months if tax benefits recognized		$ 1
Prior to SCANA Combination
Investments Owned Federal Income Tax Note [Line Items]
Increase in unrecognized tax benefits				79
Increase in income tax expense				67
Earliest Tax Year | Federal | IRS
Investments Owned Federal Income Tax Note [Line Items]
Income tax examination, year under examination		2013
Latest Tax Year | Federal | IRS
Investments Owned Federal Income Tax Note [Line Items]
Income tax examination, year under examination		2017
SCANA Combination
Investments Owned Federal Income Tax Note [Line Items]
Deferred income taxes, net				194
Increase in deferred income tax expense				30
Regulatory liabilities				40
Increase in deferred tax assets				$ 10

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Income Taxes (Details of Income Tax Expense for Continuing Operations Including Noncontrolling Interests) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current:
Federal	$ (52)	$ (139)	$ 0
State	(39)	3	34
Total current expense (benefit)	(91)	(136)	34
Deferred:
Taxes before operating loss carryforwards, investment tax credits and tax reform	61	158	(90)
Tax utilization expense of operating loss carryforwards	34	33	102
State	7	17	(57)
Total deferred expense (benefit)	102	208	(45)
Investment tax credit-amortization	(2)	(1)	(1)
Total income tax expense (benefit)	$ 9	$ 71	$ (12)

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Income Taxes (Schedule of Effective Income Tax Rate Reconciliation) (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
U.S. statutory rate	21.00%	21.00%	21.00%
Increases (reductions) resulting from:
State taxes, net of federal benefit	5.60%	4.20%	3.90%
AFUDC - equity	(0.40%)	(0.10%)	0.00%
Amortization of federal investment tax credits	(0.60%)	(0.40%)	0.10%
Production tax credits	0.00%	0.00%	0.40%
Reversal of excess deferred income taxes	(8.10%)	(6.00%)	(1.40%)
NND Project impairment	0.00%	0.00%	(2.40%)
Write-off of regulatory asset	0.00%	0.00%	(15.80%)
Changes in unrecognized tax benefits	(15.80%)	0.00%	(5.10%)
Prior period adjustments	1.60%
Other	0.50%	0.10%	0.20%
Effective tax rate	3.80%	18.80%	0.90%

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Income Taxes (Schedule of Deferred Income Taxes) (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred income taxes:
Total deferred income tax assets	$ 1,015	$ 1,101
Total deferred income tax liabilities	1,974	1,941
Total net deferred income tax liabilities	959	840
Depreciation method and plant basis differences	1,139	1,098
Excess deferred income taxes	(228)	(233)
Unrecovered nuclear plant cost	508	529
DESC rate refund	(113)	(140)
Toshiba settlement	(189)	(204)
Nuclear decommissioning	(54)	(51)
Deferred state income taxes	226	208
Federal benefit of deferred state income taxes	(47)	(44)
Deferred fuel, purchased energy and gas costs	27	(12)
Pension benefits	35	39
Other postretirement benefits	(35)	(37)
Loss and credit carryforwards	(343)	(382)
Other	33	69
Deferred Investment Tax Credits-Regulated Operations	16	18
Total Deferred Taxes and Deferred Investment Tax Credits	$ 975	$ 858

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Income Taxes (Summary of Deductible Loss and Credit Carryforwards) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Investments Owned Federal Income Tax Note [Line Items]
Loss and Credit Carryforwards, Deductible Amount	$ 3,507
Loss and Credit Carryforwards, Deferred Tax Asset	374
Federal
Investments Owned Federal Income Tax Note [Line Items]
Loss Carryforwards, Deductible Amount	890
Loss Carryforwards, Deferred Tax Asset	$ 187
Loss Carryforwards, Expiration Period	2037
Federal | Production and Other Credits
Investments Owned Federal Income Tax Note [Line Items]
Credit Carryforwards, Deductible Amount	$ 0
Credit Carryforwards, Deferred Tax Asset	$ 29
Federal | Minimum [Member] | Production and Other Credits
Investments Owned Federal Income Tax Note [Line Items]
Credit Carryforwards, Expiration Period	2035
Federal | Maximum [Member] | Production and Other Credits
Investments Owned Federal Income Tax Note [Line Items]
Credit Carryforwards, Expiration Period	2041
State
Investments Owned Federal Income Tax Note [Line Items]
Loss Carryforwards, Deductible Amount	$ 2,617
Loss Carryforwards, Deferred Tax Asset	131
State | Investment and Other Credits
Investments Owned Federal Income Tax Note [Line Items]
Credit Carryforwards, Deductible Amount	0
Credit Carryforwards, Deferred Tax Asset	$ 27
State | Minimum [Member]
Investments Owned Federal Income Tax Note [Line Items]
Loss Carryforwards, Expiration Period	2037
State | Minimum [Member] | Investment and Other Credits
Investments Owned Federal Income Tax Note [Line Items]
Credit Carryforwards, Expiration Period	2026
State | Maximum [Member]
Investments Owned Federal Income Tax Note [Line Items]
Loss Carryforwards, Expiration Period	2040
State | Maximum [Member] | Investment and Other Credits
Investments Owned Federal Income Tax Note [Line Items]
Credit Carryforwards, Expiration Period	2031

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Income Taxes (Reconciliation of Unrecognized Tax Benefits Roll Forward) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Balance at January 1	$ 138	$ 132	$ 106
Increases-prior period positions	6	5	76
Decreases-prior period positions	(57)	0	(53)
Increases-current period positions	1	1	3
Settlements with tax authorities	(26)	0	0
Balance at December 31	$ 62	$ 138	$ 132

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Derivative Financial Instruments (Narrative) (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Additional collateral to its counterparties	$ 8	$ 10
Collateral already posted	11	1
Fair value of derivative instruments with credit-related contingent provisions that are in liability position and not fully collateralized with cash	$ 19	$ 11

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Derivative Financial Instruments (Offsetting Liabilities) (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet	$ 19	$ 27
Gross amounts not offset in the consolidated balance sheet, financial instruments	0	0
Gross amounts not offset in the consolidated balance sheet, cash collateral paid	11	17
Gross amounts not offset in the consolidated balance sheet, net amounts	8	10
Interest Rate Contract [Member] | Over The Counter [Member]
Derivative [Line Items]
Gross Liabilities Presented in the Consolidated Balance Sheet	19	27
Gross amounts not offset in the consolidated balance sheet, financial instruments	0	0
Gross amounts not offset in the consolidated balance sheet, cash collateral paid	11	17
Gross amounts not offset in the consolidated balance sheet, net amounts	$ 8	$ 10

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Derivative Financial Instruments (Schedule of Volume of Derivative Activity) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) MWh
Interest Rate Swap Current [Member]
Derivative [Line Items]
Fixed price | MWh	2
Interest rate(1) (in millions) | $	$ 0
Interest Rate Swap Noncurrent [Member]
Derivative [Line Items]
Fixed price | MWh	23
Interest rate(1) (in millions) | $	$ 71

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Derivative Financial Instruments (Fair Value of Derivatives) (Detail) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Derivative Assets	[1]	$ 148
Derivative Liability		19	$ 27
Other Current Assets
Derivative [Line Items]
Derivative Assets	[2]	18
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	[3]	2	2
Other Noncurrent Assets
Derivative [Line Items]
Derivative Assets		130
Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability	[4]	17	25
Commodity Contract | Other Current Assets
Derivative [Line Items]
Derivative Assets		18
Commodity Contract | Other Noncurrent Assets
Derivative [Line Items]
Derivative Assets		130
Interest Rate Contract [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability		2	2
Interest Rate Contract [Member] | Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability		17	25
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Assets	[1]	0
Derivative Liability		12	16
Designated as Hedging Instrument [Member] | Other Current Assets
Derivative [Line Items]
Derivative Assets	[2]	0
Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	[3]	1	1
Designated as Hedging Instrument [Member] | Other Noncurrent Assets
Derivative [Line Items]
Derivative Assets		0
Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability	[4]	11	15
Designated as Hedging Instrument [Member] | Commodity Contract | Other Current Assets
Derivative [Line Items]
Derivative Assets		0
Designated as Hedging Instrument [Member] | Commodity Contract | Other Noncurrent Assets
Derivative [Line Items]
Derivative Assets		0
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability		1	1
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability		11	15
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Assets	[1]	148
Derivative Liability		7	11
Not Designated as Hedging Instrument [Member] | Other Current Assets
Derivative [Line Items]
Derivative Assets	[2]	18
Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	[3]	1	1
Not Designated as Hedging Instrument [Member] | Other Noncurrent Assets
Derivative [Line Items]
Derivative Assets		130
Not Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability	[4]	6	10
Not Designated as Hedging Instrument [Member] | Commodity Contract | Other Current Assets
Derivative [Line Items]
Derivative Assets		18
Not Designated as Hedging Instrument [Member] | Commodity Contract | Other Noncurrent Assets
Derivative [Line Items]
Derivative Assets		130
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability		1	1
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability		$ 6	$ 10

[1] Noncurrent derivative assets are presented in other deferred debits and other assets in DESC’s Consolidated Balance Sheets.

[2] Current derivative assets are presented in other current assets in DESC’s Consolidated Balance Sheets.

[3] Current derivative liabilities are presented in other current liabilities in DESC’s Consolidated Balance Sheets

[4] (4)  Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in DESC’s Consolidated Balance Sheets.

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Derivative Financial Instruments (Derivatives in Cash Flow Hedging Relationships) (Detail) - Cash Flow Hedging [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[1]	$ 9	$ 1	$ 1
Interest Rate Contract [Member]
Derivative [Line Items]
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[1]	$ 9	$ 1	$ 1

[1] Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/ liabilities have no associated effect in the Consolidated Statements of Comprehensive Income (Loss).

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Derivative Financial Instruments (Derivatives Not Designated as Hedging Instruments) (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives(1)	[1]	$ 6	$ (1)	$ (1)
Commodity Contracts [Member] | Purchased Power [Member]
Derivative [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives(1)	[1]	8	0	0
Interest Rate Contract [Member] | Interest Charges [Member]
Derivative [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives(1)	[1]	$ (2)	$ (1)	$ (1)

[1] Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in the Consolidated Statements of Comprehensive Income (Loss).

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Fair Value Measurements, Including Derivatives (Schedule of Quantitative Information About Level 3 Fair Value Measurements) (Details) $ in Millions	Dec. 31, 2021 USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total assets, fair value	$ 148
Electricity [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total assets, fair value	148
Minimum [Member] | Electricity [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total assets, fair value	28
Maximum [Member] | Electricity [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total assets, fair value	74
Weighted Average | Electricity [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total assets, fair value	$ 43

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Fair Value Measurements, Including Derivatives (Nonrecurring Fair Value Measurements) (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2020	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of assets and other charges		$ 105	$ 311	$ (14)	$ 576
Impairment of assets and other charges, after-tax		$ 79
Nonutility Property
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of assets and other charges	$ 12
Impairment of assets and other charges, after-tax	9
Estimated fair value of property	$ 6

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Fair Value Measurements, Including Derivatives (Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis) (Details) - Fair value, recurring - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Assets
Total assets	$ 148
Liabilities
Total liabilities	19	$ 27
Commodity Contract
Assets
Total assets	148
Interest Rate Contract [Member]
Liabilities
Total liabilities	19	27
Level 1
Assets
Total assets	0
Liabilities
Total liabilities	0	0
Level 1 | Commodity Contract
Assets
Total assets	0
Level 1 | Interest Rate Contract [Member]
Liabilities
Total liabilities	0	0
Level 2
Assets
Total assets	0
Liabilities
Total liabilities	19	27
Level 2 | Commodity Contract
Assets
Total assets	0
Level 2 | Interest Rate Contract [Member]
Liabilities
Total liabilities	19	27
Level 3
Assets
Total assets	148
Liabilities
Total liabilities	0	0
Level 3 | Commodity Contract
Assets
Total assets	148
Level 3 | Interest Rate Contract [Member]
Liabilities
Total liabilities	$ 0	$ 0

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Fair Value Measurements, Including Derivatives (Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis and Included in Level 3) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Regulatory Assets
Beginning balance	$ 0
Included in earnings:
Purchased power	8
Settlements	(8)
Ending balance	148
Other Regulatory Assets Liabilities
Included in earnings:
Included in regulatory assets/liabilities	$ 148

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Fair Value Measurements, Including Derivatives (Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis) (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Unrealized gains and losses	$ 0

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Fair Value Measurements, Including Derivatives (Schedule of Carrying Values and Estimated Fair Values of Debt Instruments) (Detail) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Long-term debt	[1]	$ 3,724	$ 3,360
Affiliated long-term debt		230	230
Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Long-term debt	[1],[2]	4,831	4,748
Affiliated long-term debt	[2]	$ 230	$ 230

[1] Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs and discount or premium.

[2] Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

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Asset Retirement Obligations (Narrative) (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, other conditional obligations	$ 312
Assets held in trust, nuclear decommissioning	256	$ 238
Asset retirement obligation, nuclear decommissioning	$ 287

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Asset Retirement Obligations (Schedule of Reconciliation of the Carrying Amount of AROs) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Beginning balance		$ 597	$ 489
Liabilities settled			(4)
Accretion expense		25	23
Revisions in estimated cash flows	[1]	(23)	89
Ending balance		$ 599	$ 597

[1] The decrease in 2021 is due to the remeasurement of gas pipeline AROs. The increase in 2020 reflects revisions from the nuclear decommissioning cost study.

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Employee Benefit Plans and Equity Compensation Plan (Narrative) (Detail) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Voluntary retirement program related charges						$ 63
Voluntary retirement program related charges net of taxes						47
Increase in pension benefit obligation	$ 25	$ 16
Increase in accumulated postretirement benefit obligation		10
Increase in fair value of pension plan assets	$ 35	$ 27
Defined benefit plan, accumulated benefit obligation				$ 697	$ 732
Gain (loss) from change in discount rate				$ (8)	(19)
Defined benefit plan, annual rate of increase in the per capita cost of covered health care benefits				6.25%
Defined benefit plan, ultimate health care cost trend rate				5.00%
Defined benefit plan, assumptions used calculating net periodic benefit cost, expected long-term rate of return on plan assets				7.00%
Defined benefit plan, contributions by employer				$ 0	0	0
Pension and other postretirement benefits				164	172
Defined contribution plan, employer matching contributions				$ 11	14	$ 14
Global Equities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				45.00%
Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				53.00%
Cash
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				2.00%
U.S Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage				60.00%
Non-U.S Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage				40.00%
Summer
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, shared costs deferred with joint ownership				$ 14	$ 19
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate percentage	3.57%	4.07%		3.06%	2.73%
Recognized actuarial gain (loss)				$ (29)	$ (43)
Defined benefit plan, assumptions used calculating net periodic benefit cost, expected long-term rate of return on plan assets				7.00%	7.00%	7.00%
Defined benefit plan, net periodic benefit (credit) cost				$ (13)	$ 4	$ 36
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate percentage		4.08%		3.11%	2.80%
Recognized actuarial gain (loss)					$ (51)
Defined benefit plan, ultimate health care cost trend rate				5.00%	5.00%	5.00%
Defined benefit plan, net periodic benefit (credit) cost				$ 7	$ 11	$ 15
Other Postretirement Benefits | Summer
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, shared costs deferred with joint ownership				12	$ 12
Dominion Energy Defined Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, contributions by employer				0
Defined benefit plan, net periodic benefit (credit) cost				3
Pension and other postretirement benefits				$ 3
Dominion Energy Defined Benefit Plans | Maximum [Member] | Forecast
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, contributions by employer			$ 1
Other Operations and Maintenance Expense
Defined Benefit Plan Disclosure [Line Items]
Voluntary retirement program related charges						51
Other Taxes
Defined Benefit Plan Disclosure [Line Items]
Voluntary retirement program related charges						3
Other Income (Expense), Net
Defined Benefit Plan Disclosure [Line Items]
Voluntary retirement program related charges						9
Settlement losses as a result of voluntary retirement program						$ 16

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Employee Benefit Plans and Equity Compensation Plan (Changes in Benefit Obligations) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation, January 1	$ 742	$ 727
Service cost	9	12	$ 15
Interest cost	20	24	28
Plan participants’ contributions	0	0
Actuarial (gain) loss	(28)	41
Benefits paid	(41)	(22)
Settlements	0	(40)
Curtailment	0	0
Amounts funded to parent	0	0
Benefit obligation, December 31	702	742	727
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation, January 1	184	214
Service cost	1	3	3
Interest cost	6	8	9
Plan participants’ contributions	0	2
Actuarial (gain) loss	(8)	(31)
Benefits paid	(12)	(13)
Settlements	0	0
Curtailment	0	0
Amounts funded to parent	0	1
Benefit obligation, December 31	$ 171	$ 184	$ 214

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Employee Benefit Plans and Equity Compensation Plan (Significant Assumptions Used to Determine Benefit Obligations) (Detail)	Dec. 31, 2021	Dec. 31, 2020	Sep. 30, 2019	Jun. 30, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Annual discount rate used to determine benefit obligation	3.06%	2.73%	3.57%	4.07%
Assumed annual rate of future salary increases for projected benefit obligation	3.71%	4.52%
Crediting interest rate for cash balance plans	1.81%	1.93%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Annual discount rate used to determine benefit obligation	3.11%	2.80%		4.08%

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Employee Benefit Plans and Equity Compensation Plan (Funded Status) (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 768	$ 747	$ 725
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	768	747
Benefit obligation	702	742	727
Funded status	66	5
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	171	184	$ 214
Funded status	$ (171)	$ (184)

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Employee Benefit Plans and Equity Compensation Plan (Amounts Recognized on Consolidated Balance Sheets) (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Noncurrent assets	$ 66	$ 5
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liability	(10)	(11)
Noncurrent liability	$ (161)	$ (173)

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Employee Benefit Plans and Equity Compensation Plan (Amounts Recognized in Accumulated Other Comprehensive Loss) (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (gain) loss	$ 1	$ 4

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Employee Benefit Plans and Equity Compensation Plan (Amounts Recognized in Regulatory Assets) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (gain) loss	$ 70	$ 114
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (gain) loss	$ (5)	$ 1

XML

Employee Benefit Plans (Change in Fair Value of Plan Assets) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Compensation And Retirement Disclosure [Abstract]
Fair value of plan assets, January 1	$ 747	$ 725
Actual return (loss) on plan assets	62	84
Benefits paid	(41)	(22)
Settlements		(40)
Fair value of plan assets, December 31	$ 768	$ 747

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Employee Benefit Plans (Schedule of Fair Value Measurements By Category) (Detail) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		$ 400	$ 360
Common/collective trust funds	[1]	387	387
Total recorded at NAV		387	387
Total investments(2)	[2]	787	747
Level 1
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value			10
Fair Value, Inputs, Level 2
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		400	350
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1	10
Cash and cash equivalents | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value			10
Cash and cash equivalents | Fair Value, Inputs, Level 2
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		1
Corporate Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		332	315
Corporate Debt Securities | Fair Value, Inputs, Level 2
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		332	315
Government and Other Debt Instruments
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		67	35
Government and Other Debt Instruments | Fair Value, Inputs, Level 2
Defined Benefit Plan Disclosure [Line Items]
Total recorded at fair value		$ 67	$ 35

[1] These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient are not required to be categorized in the fair value hierarchy

[2] Excludes net assets related to pending sales of securities of $4 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $25 million at December 31, 2021.

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Employee Benefit Plans (Schedule of Fair Value Measurements By Category) (Parenthetical) (Detail) - Pension Benefits $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Pending sales of securities	$ 4
Net accrued income	2
Pending purchases of securities	$ 25

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Employee Benefit Plans (Expected Benefit Payments) (Detail) $ in Millions	Dec. 31, 2021 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, expected benefit payments, 2022	$ 46
Defined benefit plan, expected benefit payments, 2023	44
Defined benefit plan, expected benefit payments, 2024	46
Defined benefit plan, expected benefit payments, 2025	45
Defined benefit plan, expected benefit payments, 2026	43
Defined benefit plan, expected benefit payments, 2027-2031	201
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, expected benefit payments, 2022	11
Defined benefit plan, expected benefit payments, 2023	11
Defined benefit plan, expected benefit payments, 2024	11
Defined benefit plan, expected benefit payments, 2025	11
Defined benefit plan, expected benefit payments, 2026	11
Defined benefit plan, expected benefit payments, 2027-2031	$ 57

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Employee Benefit Plans (Components of Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 9	$ 12	$ 15
Interest cost	20	24	28
Expected return on assets	(48)	(45)	(40)
Prior service cost amortization		0	0
Amortization of actuarial losses	6	6	11
Settlement loss		7	16
Curtailment		0	6
Net periodic benefit cost	(13)	4	36
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	3	3
Interest cost	6	8	9
Prior service cost amortization	0
Amortization of actuarial losses			0
Settlement loss	0	0
Curtailment	0	0	3
Net periodic benefit cost	$ 7	$ 11	$ 15

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Employee Benefit Plans and Equity Compensation Plan (Schedule of Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income (Loss)) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Current year actuarial (gain) loss	$ (3)	$ 2	$ (1)
Total recognized in other comprehensive income	$ (3)	2	(1)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Current year actuarial (gain) loss		(2)	1
Total recognized in other comprehensive income		$ (2)	$ 1

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Employee Benefit Plans and Equity Compensation Plan (Schedule of Defined Benefit Plan Amounts Recognized in Regulatory Assets) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax	$ (39)	$ 1	$ (51)
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax	(5)	(6)	(11)
Regulatory assets, settlement loss, pension and other postretirement benefit plans, net of tax		(6)	(16)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax	(44)	(11)	(78)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax	(6)	(27)	20
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(1)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax	$ (6)	$ (28)	$ 20

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Employee Benefit Plans and Equity Compensation Plan (Schedule of Assumptions Used in Determining Net Periodic Benefit Cost) (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	7.00%
Ultimate health care cost trend rate	5.00%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.73%	3.47%
Expected return on plan assets	7.00%	7.00%	7.00%
Rate of compensation increase	4.52%	3.00%	3.00%
Crediting interest rate for cash balance plans	1.93%	2.67%
Pension Benefits | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate			3.57%
Crediting interest rate for cash balance plans			2.77%
Pension Benefits | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate			4.38%
Crediting interest rate for cash balance plans			3.58%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.80%	2.80%
Health care cost trend rate	6.25%	6.25%	6.60%
Ultimate health care cost trend rate	5.00%	5.00%	5.00%
Year achieved			2023
Other Postretirement Benefits | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate			4.08%
Year achieved	2026	2025
Other Postretirement Benefits | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate			4.41%
Year achieved	2027	2026

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Commitments and Contingencies (Narrative) (Detail)			1 Months Ended												3 Months Ended	12 Months Ended
	Apr. 30, 2015 Facility	Oct. 31, 2014 MGD Facility	Dec. 31, 2021 USD ($)	Aug. 31, 2021 shares	Jul. 31, 2021 USD ($) shares	Jun. 30, 2021 USD ($)	Dec. 31, 2020 USD ($)	Sep. 30, 2020 USD ($)	Aug. 31, 2020 USD ($)	Jul. 31, 2019 USD ($)	Feb. 28, 2019 USD ($)	Dec. 31, 2018 USD ($)	Jun. 30, 2018 USD ($)	Aug. 31, 2016 T	Mar. 31, 2019 USD ($)	Dec. 31, 2021 USD ($) Product	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Mar. 31, 2020 USD ($)
Loss Contingencies [Line Items]
Electric generating stations with water withdrawals under CWA | MGD		125
Electric generating stations with water withdrawals with heightened entrainment analysis under CWA | MGD		2
Number of DESC facilities subject to final regulations | Facility		5
Number of DESC hydroelectric facilities subject to regulations | Facility		5
Number of MGP decommissioned sites that contain residues of byproduct chemicals | Product																4
Estimated environmental remediation activities at MGP sites																$ 19,000,000
Estimated increase in remediation costs for Congaree River site																11,000,000
Environmental remediation costs recognized in regulatory assets			$ 31,000,000													31,000,000
Number of CCR landfills facilities subject to final rule | Facility	3
Impairment of assets and other charges															$ 105,000,000	311,000,000	$ (14,000,000)	$ 576,000,000
Impairment of assets and other charges, after-tax															79,000,000
Customer refundable fees, alternative plan			3,181,000,000				$ 3,288,000,000									3,181,000,000	3,288,000,000
Regulatory liability for refunds to natural gas customers															2,000,000
Regulatory liability for refunds to natural gas customers, after tax															2,000,000
Reserves for litigation and regulatory proceedings			211,000,000				208,000,000									211,000,000	208,000,000
Insurance receivables			85,000,000				8,000,000									85,000,000	8,000,000
Settlement payable by all																			$ 520,000,000
Settlement payable by company					$ 99,000,000						$ 100,000,000								320,000,000
Proportionate ownership share in project											100.00%		100.00%
Litigation settlement expense					$ 99,000,000						$ 100,000,000								$ 320,000,000
Proposed assessment amount from SCDOR audit													$ 410,000,000
Agreement in principle to resolve the SCDOR matter							165,000,000
Contesting Amount For Filed Liens																285,000,000
Energy payments under power purchase contracts			73,000,000				$ 64,000,000									73,000,000	64,000,000	37,000,000
Summer
Loss Contingencies [Line Items]
Proceeds from legal settlements of share of claims incurred in previous year																1,000,000	4,000,000
Nuclear Insurance
Loss Contingencies [Line Items]
Maximum liability each nuclear plant is insured against			450,000,000													$ 450,000,000
Inflation adjustment period for nuclear insurance																5 years
NEIL maximum insurance coverage to nuclear facility for property damage and outage costs			2,750,000,000													$ 2,750,000,000
NEIL maximum insurance coverage to nuclear facility for property damage and outage costs from non-nuclear event																2,330,000,000
NEIL aggregate maximum loss for any single loss occurrence			$ 2,750,000,000													2,750,000,000
NEIL maximum retrospective premium assessment																24,000,000
EMANI maximum insurance coverage for Summer station unit 1 for property damage and outage costs from non-nuclear event																415,000,000
EMANI maximum retrospective premium assessment																$ 2,000,000
N N D Project
Loss Contingencies [Line Items]
Jointly owned utility plant, proportionate ownership share			55.00%													55.00%
Common Stock | Dominion Energy
Loss Contingencies [Line Items]
Common stock issued to satisfy the settlement								$ 322,000,000
Litigation settlement through stock issuance | shares				600,000	1,400,000
Litigation settlement through cash						$ 43,000,000
SCANA
Loss Contingencies [Line Items]
Payment of civil monetary penalty																	25,000,000
SCANA and DESC
Loss Contingencies [Line Items]
Payment of disgorgement and prejudgment interest																	112,500,000
Impairment of Assets and Other Charges | Dominion Energy South Carolina, Inc.
Loss Contingencies [Line Items]
Impairment of assets and other charges																$ 70,000,000	97,000,000	590,000,000
Impairment of assets and other charges, after-tax																53,000,000	73,000,000	$ 444,000,000
SCANA Combination
Loss Contingencies [Line Items]
Regulatory asset impairment charges committed to forgo recovery															258,000,000
Tax charge related to regulatory assets committed to forgo recovery															194,000,000
DESC Ratepayer Case
Loss Contingencies [Line Items]
Customer refundable fees, alternative plan															1,000,000,000.0
Customer refund fees alternative plan after tax															$ 756,000,000
Customer refunded estimated period															11 years
Previous existing regulatory liability															$ 1,000,000,000.0
Previous existing regulatory liability, years															20 years
Escrow amount												$ 2,000,000,000.0
Credit in future electric rate relief for ratepayer case												2,000,000,000.0
Cash payment related to Ratepayer Case										$ 117,000,000		115,000,000
Property with net value transferred			$ 8,000,000						$ 22,000,000
Property with net value transferred, cash contribution								38,500,000
Conveyance of property with net recorded value								$ 3,000,000
DESC Ratepayer Case | Common Stock | Dominion Energy
Loss Contingencies [Line Items]
Common stock issued to satisfy the settlement																	$ 322,000,000
Maximum [Member] | Nuclear Insurance
Loss Contingencies [Line Items]
Maximum liability protection per nuclear incident amount																13,500,000,000
Amount that could be assessed for each licensed reactor			138,000,000													138,000,000
Amount that could be assessed for each licensed reactor per year																21,000,000
Maximum [Member] | DESC Summer | Nuclear Insurance
Loss Contingencies [Line Items]
Amount that could be assessed for each licensed reactor			$ 92,000,000													92,000,000
Amount that could be assessed for each licensed reactor per year																$ 14,000,000
Maximum [Member] | DESC Ratepayer Case
Loss Contingencies [Line Items]
Estimated aggregate fair value of certain real estate												85,000,000
Minimum [Member] | DESC Ratepayer Case
Loss Contingencies [Line Items]
Estimated aggregate fair value of certain real estate												$ 60,000,000
Carbon Regulations [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Significant emission rate per year CO2 equivalent | T														75,000

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Commitments and Contingencies (Schedule of Long-Term Purchase Agreements) (Detail) $ in Millions	Dec. 31, 2021 USD ($)	[1]
Commitments And Contingencies Disclosure [Abstract]
Purchased electric capacity, 2022	$ 83
Purchased electric capacity, 2023	82
Purchased electric capacity, 2024	82
Purchased electric capacity, 2025	83
Purchased electric capacity, 2026	86
Purchased electric capacity, Thereafter	834
Purchased electric capacity, Total	$ 1,250

[1] Includes affiliated amounts with certain solar facilities of $238 million

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Commitments and Contingencies (Schedule of Long-Term Purchase Agreements) (Parenthetical) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Solar Affiliates [Member]
Long Term Purchase Commitment [Line Items]
Affiliated amount for long term commitments	$ 238

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Leases (Schedule of Lease Assets and Liabilities Recorded in Consolidated Balance Sheets) (Detail) - USD ($) $ in Millions		Dec. 31, 2021		Dec. 31, 2020		Jan. 01, 2019
Leases [Abstract]
Operating lease assets		$ 19	[1]	$ 21	[1]	$ 19
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]		us-gaap:OtherAssets		us-gaap:OtherAssets
Finance lease assets	[2]	$ 13		$ 20
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]		Utility plant, net		Utility plant, net
Total lease assets		$ 32		$ 41
Operating lease liabilities - current	[3]	2		3
Operating lease liabilities - noncurrent	[4]	17		18
Finance lease liabilities - current	[5]	$ 5		$ 6
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]		Liabilities Current		Liabilities Current
Finance lease liabilities - noncurrent		$ 10		$ 15
Total lease liabilities		$ 34		$ 42

[1] Included in other deferred debits and other assets in the Consolidated Balance Sheets.

[2] Included in utility plant, net, in the Consolidated Balance Sheets, net of $20 million and $24 million of accumulated amortization at December 31, 2021 and December 31, 2020, respectively.

[3] Included in other current liabilities in the Consolidated Balance Sheets.

[4] Included in other deferred credits and other liabilities in the Consolidated Balance Sheets.

[5] Included in securities due within one year in the Consolidated Balance Sheets.

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Leases (Schedule of Lease Assets and Liabilities Recorded in Consolidated Balance Sheets) (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Utility Plant, Net
Finance lease assets, accumulated amortization	$ 20	$ 24

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Leases (Summary of Total Lease Cost) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Finance lease cost, amortization	$ 6	$ 8	$ 7
Finance lease cost, interest	1	1	1
Operating lease cost	4	4	4
Short-term lease cost	2	2	1
Total lease cost	$ 13	$ 15	$ 13

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Leases (Cash Paid for Amounts Included in Measurement of Lease Liabilities) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating cash flows from finance leases	$ 1	$ 1	$ 1
Operating cash flows from operating leases	4	4	3
Financing cash flows from finance leases	$ 6	$ 8	$ 7

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Leases (Summary of Weighted Average Remaining Lease Term And Discount Rate for Operating and Finance Leases) (Detail)	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Weighted average remaining lease term - finance leases	4 years	4 years
Weighted average remaining lease term - operating leases	20 years	19 years
Weighted average discount rate - finance leases	2.91%	2.92%
Weighted average discount rate - operating leases	3.97%	3.95%

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Leases (Schedule of Maturity Analysis of Operating and Finance Lease Liabilities) (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Jan. 01, 2019
Operating Lease Liabilities, Payments Due [Abstract]
Maturity of operating lease liabilities, 2022	$ 3
Maturity of operating lease liabilities, 2023	2
Maturity of operating lease liabilities, 2024	2
Maturity of operating lease liabilities, 2025	1
Maturity of operating lease liabilities, 2026	1
Maturity of operating lease liabilities, after 2026	21
Maturity of operating lease liabilities, total undiscounted lease payments	30
Operating lease liabilities, present value adjustment	(11)
Present value of operating lease liabilities	19	$ 19
Finance Lease Liabilities, Payments, Due [Abstract]
Maturity of finance lease liabilities, 2022	5
Maturity of finance lease liabilities, 2023	4
Maturity of finance lease liabilities, 2024	3
Maturity of finance lease liabilities, 2025	1
Maturity of finance lease liabilities, 2026	1
Maturity of finance lease liabilities, after 2026	1
Maturity of finance lease liabilities, total undiscounted lease payments	15
Finance lease liabilities, present value adjustment	(1)
Present value of finance lease liabilities	$ 14

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Operating Segments (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Charge for refund of amounts from customers	$ 73	$ 70
Operating Segment | Corporate and Other
Segment Reporting Information [Line Items]
After- tax net expenses	212	104	$ 1,600
Operating Segment | Dominion Energy South Carolina [Member]
Segment Reporting Information [Line Items]
After- tax net expenses	208
Litigation charges	70	99	590
Litigation charges, after tax	53	$ 74	444
Charge for refund of amounts from customers			1,000
Charge for refund of amounts from customers, after tax			756
Income tax related to regulatory assets acquired			194
Income tax related to regulatory assets acquired, after tax			258
Charge for utility plant but committed to forgo recovery			114
Charge for utility plant but committed to forgo recovery, after tax			86
Merger-related costs			100
Merger-related costs, after tax			76
Charge related to a voluntary retirement program			79
Charge related to a voluntary retirement program, after-tax			59
Changes in unrecognized tax benefits			$ 66
Operating Segment | South Carolina Electric Base Rate Case
Segment Reporting Information [Line Items]
Settlement charges	266
Settlement charges net of tax	$ 199

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Operating Segments - Schedule of Segment Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Operating Revenue	[1]	$ 3,146	$ 2,739	$ 1,929
Depreciation and amortization		486	474	450
Interest charges	[1]	192	229	260
Income tax expense (benefit)		9	71	(12)
Comprehensive income (loss) available (attributable) to common shareholder		209	297	(1,239)
Capital expenditures		758	742	497
Total assets		14,927	14,479
Operating Segment | Dominion Energy South Carolina [Member]
Segment Reporting Information [Line Items]
Operating Revenue		3,146	2,739	2,937
Depreciation and amortization		486	474	452
Interest charges		215	223	247
Income tax expense (benefit)		125	107	163
Comprehensive income (loss) available (attributable) to common shareholder		421	410	408
Capital expenditures		758	742	497
Total assets		14,900	14,500
Operating Segment | Corporate and Other
Segment Reporting Information [Line Items]
Operating Revenue		0	0	(1,008)
Depreciation and amortization		0	0	(2)
Interest charges		(23)	6	13
Income tax expense (benefit)		(116)	(36)	(175)
Comprehensive income (loss) available (attributable) to common shareholder		(212)	(113)	(1,647)
Capital expenditures		0	0	$ 0
Total assets		$ 0	$ 0

[1] See Note 16 for amounts attributable to affiliates.

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Utility Plant and Nonutility Property - Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Property Plant And Equipment [Line Items]
Gross nonutility property	$ 44	$ 45
Generation
Property Plant And Equipment [Line Items]
Utility plant in service	6,053	5,921
Transmission
Property Plant And Equipment [Line Items]
Utility plant in service	2,037	1,963
Distribution
Property Plant And Equipment [Line Items]
Utility plant in service	5,191	4,909
Storage
Property Plant And Equipment [Line Items]
Utility plant in service	76	74
General and other
Property Plant And Equipment [Line Items]
Utility plant in service	601	563
Intangible
Property Plant And Equipment [Line Items]
Utility plant in service	242	250
Construction Work In Progress
Property Plant And Equipment [Line Items]
Utility plant in service	481	460
Nuclear Fuel
Property Plant And Equipment [Line Items]
Utility plant in service	603	575
Total Gross Utility Plant
Property Plant And Equipment [Line Items]
Utility plant in service	$ 15,284	$ 14,715

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Utility Plant and Nonutility Property (Narrative) (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
	Aug. 31, 2019	May 31, 2019	Dec. 31, 2020	Dec. 31, 2021
Utility Plant And Non Utility Property [Line Items]
Amounts due from Santee Cooper for share of direct expenses			$ 64	$ 152
Warranty Service Contract Assets
Utility Plant And Non Utility Property [Line Items]
Total consideration from sale of assets		$ 7
Contractual term of agreement to use brand			10 years
Warranty Service Contract Assets | Other Income (Expense), Net
Utility Plant And Non Utility Property [Line Items]
Gain on sale of assets	$ 7
Gain on sale of assets, after tax	$ 5
Summer
Utility Plant And Non Utility Property [Line Items]
Percentage of ownership interest		66.70%
Amounts due from Santee Cooper for share of direct expenses			$ 28	$ 32
N N D Project | Summer
Utility Plant And Non Utility Property [Line Items]
Percentage of ownership interest		55.00%
Santee Cooper | N N D Project | Summer
Utility Plant And Non Utility Property [Line Items]
Percentage of ownership interest		11.70%
Ownership interest purchased		$ 8

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Utility Plant and Nonutility Property - Schedule of Jointly Owned Utility Plants (Details) - Summer Unit 1 - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Property Plant And Equipment [Line Items]
Jointly owned utility plant, proportionate ownership share	66.70%	66.70%
Plant in service, jointly owned utility plant	$ 1,600	$ 1,600
Accumulated depreciation, jointly owned utility plant	725	702
Construction work in progress, jointly owned utility plant	$ 76	$ 62

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Affiliated and Related Party Transactions (Narrative) (Detail)	Dec. 31, 2021
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Ownership percentage	40.00%

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Affiliated and Related Party Transactions (Schedule of Affiliated Transactions - Income Statement) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Purchases of fuel used in electric generation from affiliate			$ 0	$ 43
Operating Revenues – Electric from sales to affiliate		$ 4	4	4
Operating Revenues – Gas from sales to affiliate		1	1	1
Operating Expenses – Other taxes from affiliate		7	9	6
D E S And D E S S
Related Party Transaction [Line Items]
Direct and allocated costs	[1]	226	294	297
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Purchases from affiliate			0	121
Sales of coal to affiliate			0	120
Solar Affiliates [Member]
Related Party Transaction [Line Items]
Purchases from affiliate		$ 14	12	8
DECG [Member]
Related Party Transaction [Line Items]
Purchases of fuel used in electric generation from affiliate			16	19
Gas purchased for resale			$ 36	$ 44

[1] Includes capitalized expenditures of $37 million, $81 million and $53 million for the years ended December 31, 2021, 2020 and 2019, respectively.

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Affiliated and Related Party Transactions (Schedule of Affiliated Transactions - Income Statement) (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
DESS [Member]
Related Party Transaction [Line Items]
Capitalized expenditures	$ 37	$ 81	$ 53

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Affiliated and Related Party Transactions (Schedule of Affiliated Transactions - Balance Sheet) (Detail) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Related Party Transaction [Line Items]
Derivative assets with affiliates(1)	[1]	$ 28	$ 0
D E S And D E S S
Related Party Transaction [Line Items]
Payable to affiliates		30	59
Public Service Company Of North Carolina Incorporated
Related Party Transaction [Line Items]
Payable to affiliates		0	5
Receivable from affiliates		60	0
D E I
Related Party Transaction [Line Items]
Payable to affiliates		1	0
Solar Affiliates [Member]
Related Party Transaction [Line Items]
Payable to affiliates		1	1
Nuclear Affiliates
Related Party Transaction [Line Items]
Receivable from affiliates		$ 1	$ 0

[1] Effective in the second quarter of 2021, contracts for the future purchase of certain quantities of electricity from solar affiliates no longer met the criteria for the normal purchase normal sale exception and are accounted for as derivative contracts

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Other Income (Expense), Net (Components of Other Income (Expense), Net) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement [Abstract]
Operating revenue from contracts with customers	$ 0	$ 1	$ 4
Other income	11	13	19
Other expense	(18)	(38)	(57)
Allowance for equity funds used during construction	5	1	1
Other expense, net	$ (2)	$ (23)	$ (33)