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, 2019

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 is a shell company (as defined by Rule 12b-2 of the Act).

Yes ☐  No ☒

At February 15, 2020, 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	6
Item 1B.	Unresolved Staff Comments	11
Item 2.	Properties	11
Item 3.	Legal Proceedings	12
Item 4.	Mine Safety Disclosures	12
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	13
Item 6.	Selected Financial Data	13
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	17
Item 8.	Financial Statements and Supplementary Data	18
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	60
Item 9A.	Controls and Procedures	60
Item 9B.	Other Information	60
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	61
Item 11.	Executive Compensation	61
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	61
Item 13.	Certain Relationships and Related Transactions, and Director Independence	61
Item 14.	Principal Accounting Fees and Services	61
Part IV
Item 15.	Exhibits and Financial Statement Schedules	62
Item 16.	Form 10-K Summary	63

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
Consortium	A consortium consisting of Westinghouse and WECTEC
CWA	Clean Water Act
DECG	Dominion Energy Carolina Gas Transmission, LLC
DER	Distributed energy resource
DESC	The legal entity, Dominion Energy South Carolina, Inc. (formerly known as South Carolina Electric    & Gas Company), 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. (formerly known as SCANA Services, Inc.)
Dominion Energy South Carolina	Dominion Energy South Carolina operating segment
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
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
FASB	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
IAA	Interim Assessment Agreement dated March 28, 2017, as amended, among DESC, Santee Cooper,    Westinghouse and WECTEC
IRS	Internal Revenue Service
MATS	Utility Mercury and Air Toxics Standard Rule
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MGD	Million gallons a day
MGP	Manufactured gas plant
MW	Megawatt
NAV	Net asset value
NEIL	Nuclear Electric Insurance Limited
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
NSPS	New Source Performance Standards
Order 1000 ORS	Order issued by FERC adopting requirements for electric transmission planning, cost allocation and development South Carolina Office of Regulatory Staff
PGA	Purchased gas adjustment

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PHMSA	U.S. Pipeline Hazardous Materials Safety Administration
Price-Anderson	Price-Anderson Amendments Act of 1988
PSD	Prevention of significant deterioration
Reorganization Plan	Modified Second Amended Joint Chapter 11 Plan or Reorganization, filed by Westinghouse
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
SEC	U.S. Securities and Exchange Commission
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
VOC	Volatile organic compounds
WECTEC	WECTEC Global Project Services, Inc. (formerly known as Stone & Webster, Inc.), a wholly-owned    subsidiary of Westinghouse
Westinghouse	Westinghouse Electric Company LLC
Westinghouse Subcontractors	Subcontractors and suppliers to the Consortium
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, effective January 2019, is a wholly-owned subsidiary of Dominion Energy.

DESC is engaged in the generation, transmission and distribution of electricity to approximately 744,000 customers in the central, southern and southwestern portions of South Carolina. Additionally, DESC sells natural gas to approximately 392,000 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 offers to its retail electric customers several DSM programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. DESC submits annual filings to the South Carolina Commission related to these programs. As actual DSM program costs are incurred, they are deferred as regulatory assets and recovered through a rider approved by the South Carolina Commission. The rider also provides for recovery of any net lost revenues and for a shared savings incentive.

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

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.

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

EMPLOYEES

At December 31, 2019, DESC had approximately 2,500 employees, of which approximately 750 were subject to collective bargaining agreements.

WHERE YOU CAN FIND MORE INFORMATION

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

DESC makes their SEC filings available, free of charge, including the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, through Dominion Energy’s 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.

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 these businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.

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. In addition, in February 2020, legislation was introduced in the South Carolina House of Representatives of the South Carolina General Assembly proposing to amend the Code of Laws of South Carolina so as to, among other things, prevent utilities from recovering certain expenditures from ratepayers; to allow the South Carolina Commission to evaluate utility operating expenses on a case-by-case basis; to provide penalties if a public utility submits a nonallowable expense for recovery from its ratepayers; and to require a utility to pay for the cost of an audit when the South Carolina Commission determines that the utility submitted a nonallowable expense. The legislation, if enacted, could further increase costs associated with regulatory reviews.

DESC is subject to numerous legal proceedings and ongoing governmental investigations and examinations. DESC is a defendant in numerous federal and state legal proceedings and governmental investigations relating to the decision to abandon construction at the NND Project. Among other things, the lawsuits and investigations allege misrepresentation, failure to properly manage the NND Project, unfair trade practices and violation of anti-trust laws. Additionally, DESC is a defendant in federal and state legal proceedings relating to the SCANA Combination. Among other things, the lawsuits allege breaches of various fiduciary duties.

The outcome of these legal proceedings, investigations and examinations, including settlements, is uncertain and may adversely affect DESC’s financial condition or results of operation.

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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 we offer, our relationships with affiliates, protection of our critical electric infrastructure assets and pipeline safety, among other matters. These operations are also subject to legislation governing taxation at the federal, state and local level. 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, including rules to limit methane leakage. 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.

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.

Any additional federal and/or state requirements imposed on energy companies mandating limitations on GHG emissions or requiring efficiency improvements may result in compliance costs that alone or in combination could make some of DESC’s electric generation units or natural gas facilities uneconomical to maintain or operate. The ACE Rule, which became effective in September 2019, is targeted at reducing CO₂ emissions from existing coal-fired power plants. The ACE Rule requires states to develop plans by July 2022 to implement CO₂ performance standards. State plans must be approved by the EPA by January 2024. States are also contemplating regulations regarding GHG emissions. Compliance with the ACE Rule or other federal or state carbon regulations is expected to require increasing the energy efficiency of equipment at facilities, committing significant capital toward carbon reduction programs, purchase of allowances and/or emission offset credits, fuel switching, and/or retirement of high-emitting generation facilities and potential replacement with lower-emitting generation facilities. Given these developments and uncertainties, DESC cannot estimate the aggregate effect of such requirements on its results of operations, financial condition or its customers. However, such expenditures, if material, could make DESC’s generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect DESC’s results of operations, financial performance or liquidity.

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

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, a decline in the credit strength of counterparties or vendors, or other factors beyond DESC’s control. Even if facility construction, electric

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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, 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.

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 our 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. 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. 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. From time to time, political and public sentiment in connection with significant transactions and infrastructure projects, such as the abandonment of the NND Project, may result in a significant amount of adverse press coverage and other adverse public statements affecting DESC. Additionally, any failure by DESC to realize voluntary targets set with respect to the reduction of GHG emissions or other long-term goals could lead to adverse press coverage and

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other adverse public statements affecting DESC. 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.

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.

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 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.

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 presidents and those responsible for financial, operational, legal, regulatory and accounting 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,

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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.

Financial, Economic and Market Risks

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.

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 our operations and ability to generate cash flow. DESC is dependent on certain financing arrangements with Dominion Energy for any borrowings necessary to meet our 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 our financial condition, cash flows, anticipated financial results or impair our 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 and other postretirement benefit plans. 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 and other postretirement benefit plans may increase the funding requirements under such plans. Additionally, changes in interest rates will affect the liabilities under DESC’s pension and other postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in mortality assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans.

If the decommissioning trust 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

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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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

DESC has approximately 3,700 miles and 26,600 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 439 substations.

DESC’s natural gas system includes approximately 500 miles of transmission pipeline and approximately 18,400 miles of distribution mains and related service facilities.

DESC owns two liquefied natural gas facilities, one located near Charleston, South Carolina, and the other in Salley, South Carolina. The Charleston facility can store the liquefied equivalent of 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 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, 2019.

Plant	Location	Net Summer Capability (MW)				Percentage Net Summer Capability
Gas
Jasper (CC)(1)	Hardeeville, SC		852
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)	Beech Island, SC		87
Parr (CT)(1)	Jenkinsville, SC		60
Williams (CT)(1)	Goose Creek, SC		40
Coit (CT)(1)	Columbia, SC		26
Total Gas(2)			2,513				40	%
Coal
Wateree	Eastover, SC		684
Williams	Goose Creek, SC		605
Cope(3)	Cope, SC		415
Total Coal			1,704				27
Hydro
Fairfield	Jenkinsville, SC		576
Saluda	Irmo, SC		190
Other	Various		18
Total Hydro			784				13
Nuclear
Summer	Jenkinsville, SC		650	(4	)
Total Nuclear			650				10
Power Purchase Agreements			596				10
Total Utility Generation			6,247				100	%

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

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

(2) Excludes the Hardeeville gas combustion turbine which currently does not have any net summer capability.

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

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

Item 3. Legal Proceedings

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

See Notes 3 and 12 to the Consolidated Financial Statements, which information is incorporated herein by reference, for a discussion of various 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 intends to pay quarterly cash dividends in 2020 but is neither required to nor restricted, except as described in Note 5 to the Consolidated Financial Statements, from making such payments.

At December 31, 2019, DESC’s retained earnings are below the balance established by the Federal Power Act as a reserve on earnings attributable to hydroelectric generation plants. As a result, DESC is prohibited from the payment of dividends without regulatory approval until the balance of its retained earnings increases. 

Item 6. Selected Financial Data

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

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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” within the meaning of the Private Securities Litigation Reform Act of 1995. 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;

• Federal, state and local legislative and regulatory developments, including changes in 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 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;

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

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• 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 financial position and the underlying value of 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,	2019			$ Change			2018
(millions)
Net loss	$	(1,222	)	$	(633	)	$	(589	)

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Overview

2019 VS. 2018

Net loss increased $633 million, primarily due to charges for refunds of amounts previously collected from retail electric customers for the NND Project, certain regulatory assets and utility plant for which DESC committed to forgo recovery, litigation and a voluntary retirement program. These decreases were partially offset by the absence of an impairment charge related to the NND Project and increased earnings under the SCANA Merger Approval Order.

Analysis of Consolidated Operations

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

Year Ended December 31,	2019			$ Change			2018
(millions)
Operating revenues	$	1,929		$	(833	)	$	2,762
Fuel used in electric generation		573			(98	)		671
Purchased power		54			(38	)		92
Gas purchased for resale		216			(23	)		239
Net revenue		1,086			(674	)		1,760
Other operations and maintenance		632			1			631
Impairment of assets and other charges		695			(681	)		1,376
Depreciation and amortization		450			123			327
Other taxes		250			(7	)		257
Other income (expense), net		(33	)		(162	)		129
Interest charges		260			(43	)		303
Income tax benefit		(12	)		404			(416	)

An analysis of DESC’s results of operations follows:

2019 VS. 2018

Net revenue decreased 38% primarily due to:

• A $1.0 billion charge to electric revenue for refunds of amounts previously collected from retail electric customers for the NND Project;

• A $17 million decrease in gas revenues due to lower South Carolina Commission approved rates and refunds of amounts previously collected from gas customers; partially offset by

• Increased revenue under the SCANA Merger Approval Order issued by the South Carolina Commission in 2019 compared to revenue under South Carolina legislation enacted in the second quarter of 2018 to temporarily reduce the amount collected from customers under the BLRA ($247 million); and

• A $114 million increase in electric revenue pursuant to a South Carolina Commission order whereby fuel cost recovery was substantially offset with gains realized upon the settlement of certain interest rate derivative contracts in 2018, as further described in other income (expense) below.

Other operations and maintenance was substantially consistent as a charge related to a voluntary retirement program ($51 million) was substantially offset by lower non-labor electric generation expenses ($19 million), lower legal and NND Project wind down costs ($17 million) and lower property insurance expenses ($4 million).

Impairment of assets and other charges decreased 49%, primarily due to the absence of $1.4 billion of impairment charges recorded in 2018 related to the NND Project, partially offset by $590 million of charges related to litigation and a $105 million charge for utility plant for which DESC committed to forgo recovery.

Depreciation and amortization increased 38%, primarily reflecting the amortization of NND Project costs.

Other income decreased $162 million, primarily due to the absence of gains realized upon the settlement of interest rate derivative contracts in 2018 ($115 million) that were mostly offset by downward adjustments to electric revenues pursuant to a previously received South Carolina Commission order related to fuel cost recovery, a charge related to a voluntary retirement program ($24 million), lower AFUDC ($10 million) and penalties related to unrecognized tax benefits in the current year ($7 million), partially offset by a gain on sale of certain warranty service contracts ($7 million).

Interest charges decreased 14%, primarily due to lower long-term debt principal balances primarily as a result of the debt tender offers completed in 2019 ($62 million), partially offset by interest charges on unrecognized tax benefits in the current year ($10 million).

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Income tax benefit decreased $404 million, primarily due to a tax charge related to regulatory assets for which DESC committed to forgo recovery ($194 million), the absence of 2017 Tax Reform Act impacts ($176 million) and changes in unrecognized tax benefits ($66 million).

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 and related financial derivative instruments are exposed to potential losses due to adverse changes in interest rates as described below. Management believes that DESC is not subject to material commodity price risk. 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.

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, 2019 or December 31, 2018.

DESC also uses interest rate derivatives, including forward-starting swaps and interest rate swaps to manage interest rate risk. As of December 31, 2019, 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 $2 million in the fair value of DESC’s interest rate derivatives at December 31, 2019. As of December 31, 2018, 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, 2018.

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 $24 million and less than $1 million for the year ended December 31, 2019 and 2018, respectively.

DESC participates in SCANA sponsored pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. DESC’s pension and other postretirement plan assets experienced aggregate actual returns (losses) $149 million and $(43) million in 2019 and 2018, respectively, versus expected returns of $40 million and $48 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 DESC’s plan assets would result in an increase in net periodic cost of $2 million at both December 31, 2019 and 2018, 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, 2019 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	19
Consolidated Balance Sheets at December 31, 2019 and 2018	20
Consolidated Statements of Comprehensive Loss for the years ended December 31, 2019, 2018 and 2017	22
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017	23
Consolidated Statements of Changes in Common Equity at December 31, 2019, 2018 and 2017 and for the years then ended	24
Notes to Consolidated Financial Statements	25

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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, 2019 and 2018, the related consolidated statements of comprehensive loss, changes in common equity, and cash flows, for each of the three years in the period ended December 31, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

February 28, 2020

We have served as DESC’s auditor since 1945.

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Dominion Energy South Carolina, Inc.

Consolidated Balance Sheets

At December 31,	2019			2018
(millions)
ASSETS
Utility plant in service	$	13,208		$	12,803
Accumulated depreciation and amortization		(4,851	)		(4,581	)
Construction work in progress		339			350
Nuclear fuel, net of accumulated amortization		219			211
Utility plant, net ($727 and $711 related to VIEs)		8,915			8,783
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation		69			72
Assets held in trust, nuclear decommissioning		214			190
Other investments		—			1
Nonutility property and investments, net		283			263
Current Assets:
Cash and cash equivalents		4			377
Receivables:
Customer, net of allowance for uncollectible accounts of $3 and $4		320			331
Affiliated and related party		14			359
Other		119			68
Inventories (at average cost):
Fuel		104			89
Materials and supplies		168			158
Prepayments		91			82
Regulatory assets		271			224
Other current assets		27			1
Total current assets ($143 and $96 related to VIEs)		1,118			1,689
Deferred Debits and Other Assets:
Regulatory assets		3,892			4,060
Other		93			168
Total deferred debits and other assets ($32 and $34 related to VIEs)		3,985			4,228
Total assets	$	14,301		$	14,963

See Notes to Consolidated Financial Statements.

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At December 31,	2019			2018
(millions)
CAPITALIZATION AND LIABILITIES
Common Stock - no par value, 40.3 million shares outstanding	$	3,695		$	2,860
Retained earnings		20			1,279
Accumulated other comprehensive loss		(3	)		(3	)
Total common equity		3,712			4,136
Noncontrolling interest		180			179
Total Equity		3,892			4,315
Long-term debt, net		3,358			5,132
Affiliated long-term debt		230			—
Finance leases		20			—
Total long-term debt		3,608			5,132
Total capitalization		7,500			9,447
Current Liabilities:
Short-term borrowings		—			73
Securities due within one year		7			14
Accounts payable		245			267
Affiliated and related party payables		624			347
Customer deposits and customer prepayments		76			73
Revenue subject to refund		4			77
Taxes accrued		218			228
Interest accrued		88			72
Regulatory liabilities		256			126
Reserves for litigation and regulatory proceedings		492			11
Other		56			42
Total current liabilities		2,066			1,330
Deferred Credits and Other Liabilities:
Deferred income taxes and investment tax credits		629			1,008
Asset retirement obligations		489			542
Pension and other postretirement benefits		203			232
Regulatory liabilities		3,210			2,264
Affiliated liabilities		15			16
Other		189			124
Total deferred credits and other liabilities		4,735			4,186
Commitments and Contingencies (see Note 12)
Total capitalization and liabilities	$	14,301		$	14,963

See Notes to Consolidated Financial Statements.

21

Dominion Energy South Carolina, Inc.

Consolidated Statements of Comprehensive Loss

Year Ended December 31,	2019			2018			2017
(millions)
Operating Revenue(1)	$	1,929		$	2,762		$	3,070
Operating Expenses:
Fuel used in electric generation(1)		573			671			594
Purchased power(1)		54			92			80
Gas purchased for resale(1)		216			239			206
Other operations and maintenance		388			449			417
Other operations and maintenance – affiliated suppliers		244			182			180
Impairment of assets and other charges		695			1,376			1,118
Depreciation and amortization		450			327			312
Other taxes(1)		250			257			246
Total operating expenses		2,870			3,593			3,153
Operating loss		(941	)		(831	)		(83	)
Other income (expense), net		(33	)		129			28
Interest charges, net of allowance for funds used during    construction of $5, $9 and $15(1)		260			303			288
Loss before income tax benefit		(1,234	)		(1,005	)		(343	)
Income tax benefit		(12	)		(416	)		(171	)
Net Loss		(1,222	)		(589	)		(172	)
Other Comprehensive Income:
Deferred cost of employee benefit plans, net of tax of $-, $- and $-		1			1			—
Total Comprehensive Loss		(1,221	)		(588	)		(172	)
Comprehensive Income Attributable to Noncontrolling Interest		18			25			13
Comprehensive Loss Attributable to Common Shareholder	$	(1,239	)	$	(613	)	$	(185	)

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

See Notes to Consolidated Financial Statements.

22

Dominion Energy South Carolina, Inc.

Consolidated Statements of Cash Flows

Year Ended December 31,	2019			2018			2017
(millions)
Operating Activities
Net loss	$	(1,222	)	$	(589	)	$	(172	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Impairment of assets and other charges		576			1,376			1,118
Provision for refunds to electric customers		800			—			—
Gain on sale of assets		(7	)		—			—
Deferred income taxes, net		(379	)		(184	)		(780	)
Depreciation and amortization		464			342			323
Amortization of nuclear fuel		53			47			44
Other adjustments		(7	)		(17	)		(49	)
Changes in certain assets and liabilities:
Receivables		(33	)		50			(32	)
Receivables – affiliated and related party		1			(2	)		12
Income tax receivable		—			198			(145	)
Inventories		(76	)		(54	)		(60	)
Prepayments		(9	)		—			6
Regulatory assets		(20	)		(179	)		185
Regulatory liabilities		265			(360	)		899
Accounts payable		(54	)		61			20
Accounts payable – affiliated and related party		(15	)		—			(28	)
Revenue subject to refund		(73	)		77			—
Unrecognized tax benefits		52			19			(241	)
Taxes accrued		(10	)		31			13
Pension and other postretirement benefits		(27	)		15			(21	)
Other assets and liabilities		169			96			(86	)
Net cash provided by operating activities		448			927			1,006
Investing Activities
Property additions and construction expenditures		(497	)		(633	)		(928	)
Proceeds from monetization of guaranty settlement		—			—			1,096
Proceeds from investments and sales of assets		39			40			118
Purchase of investments		(54	)		(29	)		(122	)
Purchase of investments – affiliate		—			(111	)		—
Payments upon interest rate derivative contract settlement		—			—			(39	)
Proceeds from interest rate derivative contract settlement		—			115			—
Investment in affiliate, net		344			(214	)		(28	)
Net cash provided by (used in) investing activities		(168	)		(832	)		97
Financing Activities
Proceeds from issuance of debt		—			795			—
Proceeds from issuance of affiliated debt		230			—			—
Repayment of long-term debt, including redemption premiums		(1,890	)		(825	)		(12	)
Dividend to parent		(30	)		(173	)		(319	)
Short-term borrowings, net		(73	)		(179	)		(552	)
Short-term borrowings – affiliated, net		292			—			—
Money pool borrowings, net		—			245			8
Contribution from parent		838			24			3
Contribution returned to parent		(20	)		—			—
Net cash used in financing activities		(653	)		(113	)		(872	)
Net increase (decrease) in cash, restricted cash and equivalents		(373	)		(18	)		231
Cash, restricted cash and equivalents at beginning of period(1)		377			395			164
Cash, restricted cash and equivalents at end of period(1)	$	4		$	377		$	395
Supplemental Cash Flow Information
Cash for:
Interest paid (net of capitalized interest of $5, $9 and $15)		220			264			269
Income taxes paid		13			3			47
Income taxes received		—			216			145
Noncash investing and financing activities:(2)
Accrued construction expenditures		120			69			99
Leases(3)		12			8			8
Contributed capital		1			6			—

(1) For the years ended December 31, 2019, 2018 and 2017 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.

(3) Includes $4 million of financing leases and $8 million of operating leases for the year ended December 31, 2019 and $8 million of capital leases for both years ended December 31, 2018 and 2017.

See Notes to Consolidated Financial Statements.

23

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, 2016		40	$	2,860	$	2,481		$	(3	)	$	134		$	5,472
Total comprehensive income (loss)    available (attributable) to common    shareholder						(185	)		(1	)		13			(173	)
Capital contribution from parent												3			3
Dividend to parent						(314	)					(8	)		(322	)
December 31, 2017		40		2,860		1,982			(4	)		142			4,980
Total comprehensive income (loss)    available (attributable) to common    shareholder						(614	)		1			25			(588	)
Capital contribution from parent												24			24
Dividend to parent						(89	)					(12	)		(101	)
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

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, effective January 2019, 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 sells natural gas to residential, commercial and industrial customers in South Carolina.

Beginning in December 2019, 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 VIE’s 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 VIE’s. 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. GENCO’s property (carrying value of $508 million) previously served as collateral for its long-term borrowings. 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, DESC purchases shared services from DESS, an affiliated VIE that provides accounting, legal, finance and certain administrative and technical services to all SCANA subsidiaries, including DESC. DESC has determined that it is not the primary beneficiary of DESS 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 2018 and 2017 Consolidated Financial Statements and Notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect DESC’s net income, total assets, liabilities, equity or cash flows.

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 4.3%, 7.0% and 3.9% for 2019, 2018 and 2017, 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:

	2019			2018
Generation		2.50	%		2.61	%
Transmission		2.57	%		2.74	%
Distribution		2.41	%		2.41	%
Storage		2.74	%		2.71	%
General and other		3.22	%		3.18	%

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 equipment and nuclear refueling outages are 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.

DESC is authorized to collect $18 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2019 and 2018, DESC incurred $10 million and $16 million, respectively, for turbine 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 scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which DESC was responsible totaled $2 million in 2019 and $29 million in 2018.

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 2016, 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 $646 million, stated in 2019 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. At December 31, 2019, there were no restricted cash and equivalent balances. At December 31, 2018, cash and cash equivalents at DESC included $115 million held in escrow pending a settlement which was contingent on the consummation of the merger with Dominion Energy. As such, DESC did not consider this amount to be restricted at December 31, 2018.

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 $114 million and $129 million at December 31, 2019 and 2018, 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 facilities at Summer. Such receivables represented approximately 10% of DESC’s accounts receivable balance at December 31, 2019.

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 was filed for SCANA, including DESC for years through 2018. Beginning in 2019, SCANA and DESC are part of Dominion Energy’s consolidated federal income tax return. 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 participated in intercompany tax sharing agreements with SCANA through the SCANA Combination, and currently participates in similar agreements with Dominion Energy. Under both SCANA and Dominion Energy’s tax sharing agreements, 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 SCANA or 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.

The 2017 Tax Reform Act included a broad range of tax reform provisions affecting DESC, including changes in corporate tax rates and business deductions. The 2017 Tax Reform Act reduces the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. Deferred tax assets and liabilities are classified as noncurrent in the Consolidated Balance Sheets and measured at the enacted tax rate expected to apply when temporary differences are realized or settled. Thus, at the date of enactment, federal deferred taxes were remeasured based upon the new 21% tax rate. The total effect of tax rate changes on deferred tax balances was recorded as a component of the income tax provision related to continuing operations for the period in which the law is enacted, even if the assets and liabilities relate to other components of the financial statements, such as items of accumulated other comprehensive income. DESC, as a rate-regulated utility, was required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, if it is probable that the effect of the change in income tax rates will be recovered or shared with customers in future rates, DESC recorded a regulatory asset or liability instead of an increase or decrease to deferred income tax expense.

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, 2019, DESC had $132 million of unrecognized tax benefits.

27

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.

Interest expense for DESC was $18 million, $8 million and less than $1 million in 2019, 2018, and 2017, respectively. Interest income for DESC was $2 million in 2019 and 2018, and less than $1 million in 2017. DESC also recorded penalty expenses of $7 million in 2019.

At December 31, 2019, DESC had an income tax-related affiliated receivable of $21 million from Dominion Energy. This balance is expected to be received from Dominion Energy.

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 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 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;

• Discussions with applicable regulatory authorities and legal counsel;

• Forecasted earnings; and

• Considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events and other natural disasters and unplanned outages of facilities.

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 Note 3 to the Consolidated Financial Statements for additional information.

Derivative Instruments

DESC uses derivative instruments such as swaps to manage interest rate risks of its business operations. Derivatives 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.

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 $19 million and $11 million associated with cash collateral at December 31, 2019 and 2018, respectively. DESC had no margin liabilities associated with cash collateral at December 31, 2019 and 2018. See Note 8 for further information about derivatives.

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 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 the Company is hedging the variability of cash flows, changes in the fair value of the derivatives are reported in regulatory

28

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. See Note 3 and Note 17 regarding the settlement gains realized in the first quarter of 2018.

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 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 Income (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, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, 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.

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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 Loss. Rent expense associated with finance leases results in the separate presentation of interest expense on the lease liability and amortization expense of the related right-of-use asset in the Consolidated Statements of Comprehensive Loss. Amortization expense and interest charges associated with finance leases are recorded in depreciation and amortization and interest charges, respectively, in the Consolidated Statements of Comprehensive Loss or deferred within regulatory assets in the Consolidated Balance Sheets.

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

REVENUE RECOGNITION

In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. DESC adopted this revised accounting guidance for interim and annual reporting periods beginning January 1, 2018 using the modified retrospective method. No cumulative effect adjustment was recognized upon adoption. For additional required disclosures, see Note 4.

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. Under this approach, DESC utilized the transition practical expedient to maintain historical presentation for periods before January 1, 2019. DESC also applied the other 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.

NET PERIODIC PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

In March 2017, the FASB issued revised accounting guidance for the presentation of net periodic pension and other postretirement benefit costs. This guidance became effective for DESC beginning January 1, 2018 and requires that the service cost component of net periodic pension and other postretirement benefit costs be classified in the same line item as other compensation costs arising from services rendered by employees, while all other components of net periodic pension and other postretirement costs are classified outside of income from operations. In addition, only the service cost component remains eligible for capitalization during construction. The standard also recognizes that in the event that a regulator continues to require capitalization of all net periodic

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benefit costs prospectively, the difference would result in recognition of a regulatory asset or liability. For costs not capitalized for which regulators are expected to provide recovery, a regulatory asset will be established.

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 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 Loss during the third quarter of 2019, to remove previously recorded reserves.

2017 Tax Reform Act

The 2017 Tax Reform Act lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the South Carolina Commission has required DESC to track and defer impacts related to the 2017 Tax Reform Act arising from customer rates in 2018 as subject to refund. In addition, as further discussed under Regulatory Assets and Regulatory Liabilities below, certain accumulated deferred income taxes contained within regulatory liabilities represent excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the 2017 Tax Reform Act. Certain of these amounts are protected under normalization rules and will be amortized at the weighted average tax rate used to build the reserves over the remaining regulatory life of the property. Other, non-plant related regulatory liabilities will be amortized to the benefit of customers, as instructed by our regulators.

As part of the SCANA Combination, the South Carolina Commission approved credits of approximately $100 million by DESC for the impact of the lower federal tax rate resulting from the 2017 Tax Reform Act. The credits included amounts which had been collected through customer rates in 2018 and January 2019 and also included the effects of the amortization of certain excess deferred taxes during the same period. These credits were included in bills rendered on and after the first billing cycle of February 2019. In addition, the South Carolina Commission approved the implementation of a tax rider whereby amounts collected though customer rates effectively would be reduced and excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the 2017 Tax Reform Act will be amortized to the benefit of customers. This tax rider reduced base rates to customers by approximately $63 million in 2019 and is expected to reduce these rates by $67 million in 2020. Unamortized excess deferred income taxes that remain at the end of 2020 will be considered in future rate proceedings.

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 will make such changes to its formula rate as part of its annual update in May 2020.

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In January 2020, GENCO filed to modify its formula rate to incorporate a mechanism to decrease or increase its income tax allowances by any excess deferred income taxes resulting from the 2017 Tax Reform Act, and future changes in tax laws. These modifications are expected to decrease charges to DESC for the power it purchases from GENCO.

Electric – BLRA

In July 2018, the South Carolina Commission issued orders implementing a legislatively-mandated temporary reduction in revenues that could be collected by DESC from customers under the BLRA. These orders reduced the portion of DESC’s retail electric rates associated with the NND Project from approximately 18% of the average residential electric customer's bill to approximately 3%, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. As a result, in 2018 DESC recorded a charge of $109 million ($82 million after-tax) to operating revenues in DESC’s Consolidated Statements of Comprehensive Loss. The temporary rate reduction remained in effect until February 2019 when rates pursuant to the SCANA Merger Approval Order became effective.

Other Regulatory Matters

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 2020, DESC filed with the South Carolina Commission a proposal to decrease the total fuel cost component of retail electric rates. DESC’s proposed decrease would reduce annual base fuel component recoveries by approximately $44 million and is projected to return to customers the existing over-collected balance while recovering DESC’s current base fuel costs over the 12-month period beginning with the first billing cycle of May 2020. In addition, DESC proposed an increase to its variable environmental and DER components. This matter is pending.

In April 2019, the South Carolina Commission approved DESC’s proposal to decrease the total fuel cost component of retail electric rates. DESC's proposal included maintaining its base fuel component at the current level to produce a projected under-recovered balance of $35 million at the end of the 12-month period beginning with the first billing cycle of May 2019 and requested carrying costs for any base fuel under-collected balances, should they occur. DESC also proposed reducing its variable environmental component and maintaining or reducing its DER components. Changes in rates became effective beginning with the first billing cycle of May 2019.

In April 2018, the South Carolina Commission approved DESC’s proposal to increase the total fuel cost component of retail electric rates. Petitions for rehearing and reconsideration were filed by various parties, and on October 30, 2018, the South Carolina Commission issued an order granting one such petition related to DESC supplying certain information as in previous years. The other petitions were denied, and certain parties have appealed the decision to deny their petitions to the South Carolina Supreme Court. These appeals primarily relate to avoided cost rates that DESC is required to pay to solar energy developers, and these appeals are pending. DESC cannot predict the outcome of these matters.

Electric Transmission Projects

In 2020, DESC expects to begin several electric transmission projects in connection with two new nuclear plants under development by Southern. These transmission projects are required to be in place prior to these plants beginning operations to maintain reliability. DESC anticipates the projects to go into service in phases, costing approximately $75 million in aggregate. In February 2020, DESC filed an application with the South Carolina Commission requesting approval to construct and operate 28 miles of 230 kV transmission lines in Aiken County, South Carolina estimated to cost approximately $30 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 2019, DESC filed an application with the South Carolina Commission seeking approval to recover $30 million of costs incurred and net lost future revenues associated with these programs, along with an incentive to invest in such programs. In April 2019, the South Carolina Commission approved the request for the rate year beginning with the first billing cycle of May 2019.

In January 2020, DESC submitted its annual DSM programs filing to the South Carolina Commission. If approved the filing would allow recovery of approximately $40 million of costs and net lost revenues associated with DSM 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. No adjustment was made in 2019. In 2020, DESC requested that the South Carolina Commission approve an adjustment to this rider to decrease annual revenue by approximately $11 million. This matter is pending.

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Gas

In June 2019, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 2019 with a total revenue requirement of $437 million. This represents a $7 million overall increase to its natural gas rates under the terms of the RSA effective for the rate year beginning November 2019. In October 2019, the South Carolina Commission approved a total revenue requirement of $436 million effective with the first billing cycle of November 2019.

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,	2019		2018
(millions)
Regulatory assets:
NND Project costs(1)	$	138		127
Deferred employee benefit plan costs(2)		13		16
Other unrecovered plant(3)		14		14
DSM programs(4)		17		14
AROs(5)		28		—
Cost of fuel under-collections(6)		13		13
Other		48		40
Regulatory assets - current		271		224
NND Project costs(1)		2,503		2,641
AROs(5)		293		380
Cost of reacquired debt(7)(8)		259		14
Deferred employee benefit plan costs(2)		196		256
Deferred losses on interest rate derivatives(9)		305		442
Other unrecovered plant(3)		69		79
DSM programs(4)		54		51
Environmental remediation costs(10)		22		24
Deferred storm damage costs(11)		44		35
Deferred transmission operating costs(12)		37		15
Other(13)		110		123
Regulatory assets - noncurrent		3,892		4,060
Total regulatory assets	$	4,163	$	4,284
Regulatory liabilities:
Monetization of guaranty settlement(14)	$	67		61
Income taxes refundable through future rates(15)		16		52
Reserve for refunds to electric utility customers(16)		143		—
Other		30		13
Regulatory liabilities - current		256		126
Monetization of guaranty settlement(14)		970		1,037
Income taxes refundable through future rates(15)		948		607
Asset removal costs(17)		552		541
Deferred gains on interest rate derivatives(9)		71		75
Reserve for refunds to electric utility customers(16)		656		—
Other		13		4
Regulatory liabilities – noncurrent		3,210		2,264
Total regulatory liabilities	$	3,466	$	2,390

(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 over the units' previous estimated remaining useful lives through 2025. 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 five years through an approved rate rider.

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(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-collected from customers pursuant to the cost of fuel components approved by the South Carolina Commission.

(7) Costs of the reacquisition of debt are deferred and amortized as interest expense over the would-be remaining life of the reacquired debt or over the life of the replacement debt if refinanced. The reacquired debt had a weighted-average life of approximately 26 years as of December 31, 2019.

(8)   During 2019, DESC purchased certain of its first mortgage bonds as discussed in Note 6. As a result of these transactions, DESC incurred net costs, including write-offs of unamortized discount, premium and debt issuance costs, of $270 million.

(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 16 years. See Note 12 for more information.

(11) Represents storm restoration costs for which DESC expects to receive future recovery through customer rates.

(12) Includes deferred depreciation and property taxes associated with certain transmission assets for which DESC expects recovery from customers through future rates. See Note 12 for more information.

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

(14) 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.

(15) 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.

(16) 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 in connection with the SCANA Merger Approval Order. See Note 12 for more information.

(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

The Company’s operating revenue, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, consists of the following:

Year Ended December 31,	2019				2018
(millions)	Electric		Gas		Electric		Gas
Customer class:
Residential	$	669	$	194	$	1,054	$	208
Commercial		507		111		744		117
Industrial		224		81		385		92
Other		116		18		132		17
Revenues from contracts with customers		1,516		404		2,315		434
Other revenues		9		—		12		1
Total Operating Revenues	$	1,525	$	404	$	2,327	$	435

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 $9 million and $4 million at December 31, 2019 and 2018, respectively. For the years ended December 31, 2019 and 2018, DESC recognized revenue of $3 million and $4 million 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.

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

	Regulatory Assets
(millions)	2019			2018
Beginning balance, January 1	$	15		$	16
Amortization		(2	)		(1	)
Ending balance, December 31	$	13		$	15

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 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, the Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At both December 31, 2019 and 2018, retained earnings of $115 million were restricted by this requirement as to payment of cash dividends on DESC’s common stock. 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, 2019, DESC’s retained earnings are below the balance established by the Federal Power Act as a reserve on earnings attributable to hydroelectric generation plants. As a result, DESC is prohibited from the payment of dividends without regulatory approval until the balance of its retained earnings increases. 

6.  LONG-TERM AND SHORT-TERM DEBT

Long-term debt by type with related weighted-average coupon rates and maturities at December 31, 2019 and 2018 is as follows:

At December 31,	2019 Weighted- average Coupon(1)			2019			2018
(millions, except percentages)
DESC:
First Mortgage Bonds, 3.22% to 6.625%, due 2021 to 2065(2)		5.42	%	$	3,267		$	4,990
Tax-Exempt Financings:
Variable rate due 2038		1.65	%		35			35
3.625% and 4.00%, due 2028 and 2033		3.90	%		54			54
Other		3.69	%		1			—
GENCO:
Tax-Exempt Financing, variable rate due 2038		1.65	%		33			33
Secured Senior Notes, 5.49% due 2024(3)					—			40
Affiliated note, 3.05% due 2024		3.05	%		230			—
Total principal					3,620			5,152
Securities due within one year					—			(14	)
Unamortized discount, premium and debt issuance costs, net					(32	)		(36	)
Finance leases					20			30
Total long-term debt				$	3,608		$	5,132

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2019.

(2) In February, March and September 2019, DESC purchased certain of its first mortgage bonds having an aggregate purchase price of $1.8 billion pursuant to tender offers. The February and March tender offers expired in the first quarter of 2019 and the September tender offer expired in the third quarter of 2019.

(3) In May 2019, GENCO redeemed its 5.49% senior secured notes due in 2024 at the remaining principal outstanding of $33 million plus accrued interest.

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, 2019, were as follows:

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(millions, except percentages)	2020		2021			2022		2023		2024			Thereafter			Total
First Mortgage Bonds	$	—	$	33		$	—	$	—	$	—		$	3,234		$	3,267
Tax-Exempt Financings		—		—			—		—		—			122			122
Other		—		—			—		—		230			1			231
Total	$	—	$	33		$	—	$	—	$	230		$	3,357		$	3,620
Weighted-average coupon				3.25	%						3.05	%		5.34	%

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 (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be issued (Bond Ratio). For the year ended December 31, 2019, the Bond Ratio was 6.88. Adjusted Net Earnings, as therein defined, excludes the impairment loss.

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

In March 2019, DESC became a co-borrower under Dominion Energy's $6.0 billion joint revolving credit facility. DESC's short-term financing is supported through its access to this joint revolving credit facility, which can be used for working capital, as support for the combined commercial paper programs of DESC, Dominion Energy and certain other of its subsidiaries (co-borrowers), 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, 2019	$	1,000	$	—	$	—

A maximum of $1.0 billion of the facility is available to DESC, less any amounts outstanding to co-borrowers. 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, 2019, 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 March 2023 and 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.

Also in March 2019, DESC canceled its previous committed long-term facility which was a revolving line of credit under a credit agreement with a syndicate of banks. This previous credit agreement was used for general corporate purposes, including liquidity support for DESC's commercial paper program and working capital needs, and was set to expire in December 2020.

(millions)	Facility Limit(1)		Outstanding Commercial Paper		Outstanding Letters of Credit
At December 31, 2018	$	1,200	$	73	$	—

(1) Included $500 million related to Fuel Company. In February 2019, Fuel Company's commercial paper program and its credit facility were terminated.

The weighted-average interest rate of the outstanding commercial paper supported by this credit facility was 3.82% at December 31, 2018.

In April 2019, DESC renewed its FERC authority through April 2020 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 April 2019, GENCO renewed its FERC authority through April 2020 to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. In January 2020, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization. The applications are pending.

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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 2020.

DESC received FERC approval to enter into an inter-company credit agreement in April 2019 with Dominion Energy under which DESC may have short-term borrowings outstanding up to $900 million. At December 31, 2019, DESC had borrowings outstanding under this credit agreement totaling $355 million, which are recorded in affiliated and related party payables in DESC’s Consolidated Balance Sheets. For the twelve months ended December 31, 2019, DESC recorded interest charges of $3 million.

DESC participated in a utility money pool with SCANA and another regulated subsidiary of SCANA through April 2019. Fuel Company and GENCO remain in the utility money pool. Money pool borrowings and investments bear interest at short-term market rates. For the years ended December 31, 2019 and 2018, DESC recorded interest income from money pool transactions of $8 million and $4 million, respectively, and for the same periods DESC recorded interest expense from money pool transactions of $8 million and $4 million, respectively. DESC had outstanding money pool borrowings due to an affiliate of $219 million and investments due from an affiliate of $9 million at December 31, 2019. At December 31, 2018, DESC had outstanding money pool borrowings due to an affiliate of $282 million and investments due from an affiliate of $353 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.

The 2017 Tax Reform Act included a broad range of tax reform provisions. The 2017 Tax Reform Act reduced the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. At the date of enactment, deferred tax assets and liabilities were remeasured based upon the new 21% enacted tax rate expected to apply when temporary differences are realized or settled. The specific provisions related to regulated public utilities in the 2017 Tax Reform Act generally allow for the continued deductibility of interest expense, changed the tax depreciation of certain property acquired after September 27, 2017, and continued certain rate normalization requirements for accelerated depreciation benefits.

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. The 2017 Tax Reform Act included provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential sharing of other deferred taxes will be determined by our regulators. See Note 3 for more information.

DESC has completed the accounting for the effects of the 2017 Tax Reform Act, although changes could occur as additional guidance is issued and finalized, particularly as it relates to the deductibility of interest expense in consolidated groups such as Dominion Energy. In addition, the major states in which DESC operates have addressed conformity with some or all of the provisions of the 2017 Tax Reform Act, although they may have modified certain provisions.

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

Year Ended December 31,	2019			2018			2017
(millions)
Current:
Federal	$	—		$	(16	)	$	(410	)
State		34			—			(18	)
Total current expense (benefit)		34			(16	)		(428	)
Deferred:
Federal
Taxes before operating loss carryforwards, investment tax credits and tax reform		(90	)		(216	)		262
2017 Tax Reform Act impact		—			(176	)		(1	)
Tax utilization expense of operating loss carryforwards		102			46			—
State		(57	)		(52	)		(2	)
Total deferred expense (benefit)		(45	)		(398	)		259
Investment tax credit-amortization		(1	)		(2	)		(2	)
Total income tax expense (benefit)	$	(12	)	$	(416	)	$	(171	)

The 2017 Tax Reform Act reduced the statutory federal income tax rate to 21% beginning in January 2018. Accordingly, current and deferred income taxes are recorded at the new 21% rate.

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 SCANA Energy Marketing, Inc.’s assets to Dominion Energy, which increased the amount of DESC’s 2019 net operating loss utilization by approximately $79 million.

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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,	2019			2018			2017
U.S. statutory rate		21.0	%		21.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		3.9			3.8			2.3
State investment tax credits		—			0.3			1.5
AFUDC - equity		—			0.2			1.5
Amortization of federal investment tax credits		0.1			0.2			0.6
Production tax credits		0.4			0.9			2.3
Domestic production activities deduction		—			—			5.2
Reversal of excess deferred income taxes		(1.4	)		—			—
Federal legislative change		—			17.5			0.3
NND Project impairment		(2.4	)		(2.3	)		—
Write-off of regulatory asset		(15.8	)		—			—
Changes in unrecognized tax benefits		(5.1	)		—			—
Other		0.2			(0.2	)		1.2
Effective tax rate		0.9	%		41.4	%		49.9	%

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 2019, and changes in estimates of amounts probable of collection from or return to customers. The reversal of these excess deferred income taxes will impact the effective tax rate, and may ultimately impact rates charged to customers. See Note 3 for current year developments.

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.

In connection with the remeasurement of federal deferred income tax assets and liabilities resulting from the lower federal income tax rate, DESC recorded a deferred income tax benefit of approximately $1 million in the statements of operations for the year ended December 31, 2017. As a result of the filing of the 2017 tax return in the fourth quarter of 2018 and the additional impairment charges recorded in 2018, adjustments to such excess deferred income taxes of approximately $176 million were recorded. Also in connection with the additional impairment charges, DESC recorded additional adjustments to deferred income taxes in the aggregate amount of approximately $23 million. In addition, certain states in which DESC operates may or may not conform to some or all of the provisions of the 2017 Tax Reform Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to results of operations and cash flows, and adjustments to tax-related assets and liabilities, and such impacts or adjustments could be material.

DESC’s deferred income taxes consist of the following:

At December 31,	2019			2018
(millions)
Deferred income taxes:
Total deferred income tax assets	$	1,258		$	971
Total deferred income tax liabilities		1,868			1,960
Total net deferred income tax liabilities	$	610		$	989
Total deferred income taxes:
Depreciation method and plant basis differences	$	1,007		$	998
Excess deferred income taxes		(231	)		(148	)
Unrecovered nuclear plant cost		553			584
DESC rate refund		(169	)		(1	)
Toshiba settlement		(219	)		(231	)
Nuclear decommissioning		(43	)		(9	)
Deferred state income taxes		200			296
Federal benefit of deferred state income taxes		(42	)		(62	)
Deferred fuel, purchased energy and gas costs		7			1
Pension benefits		46			46
Other postretirement benefits		(35	)		(35	)
Loss and credit carryforwards		(391	)		(520	)
Other		(73	)		70
Total net deferred income tax liabilities	$	610		$	989
Deferred Investment Tax Credits-Regulated Operations		19			19
Total Deferred Taxes and Deferred Investment Tax Credits	$	629		$	1,008

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At December 31, 2019, DESC had the following deductible loss and credit carryforwards:

(millions)	Deductible Amount		Deferred Tax Asset		Expiration Period
Federal losses	$	1,207	$	254	2037
Federal production and other credits		—		38	2031-2038
State losses		1,849		92	2037
State investment and other credits		—		31	2026-2031
Total	$	3,056	$	415

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

(millions)	2019			2018		2017
Balance at January 1	$	106		$	98	$	350
Increases-prior period positions		76			8		—
Decreases-prior period positions		(53	)		—		(273	)
Increases-current period positions		3			—		21
Balance at December 31	$	132		$	106	$	98

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 2010, except for certain outstanding refund claims. The IRS has completed examinations of DESC’s federal returns through 2012. The IRS is currently examining DESC’s federal returns from 2013 through 2017. With few exceptions, DESC is no longer subject to state and local income tax examinations by tax authorities for years prior to 2012.

It is reasonably possible that these unrecognized tax benefits may decrease by $65 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 up to $4 million. Otherwise, with regard to 2019 and prior years, DESC cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2020.

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 the Company’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 the Company’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 DESC 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. DESC’s derivatives with credit-related contingent provisions that were in a liability position were fully collateralized with cash at December 31, 2019 and 2018.

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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:

	December 31, 2019								December 31, 2018
			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	$	—	$	19	$	—	$	11	$	—	$	11	$	—
Total derivatives	$	19	$	—	$	19	$	—	$	11	$	—	$	11	$	—

Volumes

The following table presents the volume of derivative activity at December 31, 2019. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions.

	Current		Noncurrent
Interest rate(1)	$	—	$	71,400,000

(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, 2019
Current Liabilities
Interest rate	$	1	$	1	$	2
Total current derivative liabilities(1)		1		1		2
Noncurrent Liabilities
Interest rate		11		6		17
Total noncurrent derivative liabilities(2)		11		6		17
Total derivative liabilities	$	12	$	7	$	19
At December 31, 2018
Current Liabilities
Interest rate	$	1	$	—	$	1
Total current derivative liabilities(1)		1		—		1
Noncurrent Liabilities
Interest rate		7		3		10
Total noncurrent derivative liabilities(2)		7		3		10
Total derivative liabilities	$	8	$	3	$	11

(1) Current derivative liabilities are presented in other current liabilities in the Consolidated Balance Sheets.

(2) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in the 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):

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Derivatives in Cash Flow Hedging Relationships

(millions)	Gain (loss) Reclassified from Deferred Accounts into Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(1)
Year Ended December 31, 2019
Derivative type and location of gains (losses):
Interest rate(2)	$	—		$	1
Total	$	—		$	1
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Interest rate(2)	$	(1	)	$	1
Total	$	(1	)	$	1
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Interest rate(2)	$	(2	)	$	(2	)
Total	$	(2	)	$	(2	)

(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 Loss.

(2) Amounts recorded in DESC’s Consolidated Statements of Comprehensive Loss are classified in interest charges.

Derivatives Not designated as Hedging Instruments

(millions)	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2019			2018			2017
Derivative type and location of gains (losses):
Interest rate contracts:
Interest charges	$	(1	)	$	(2	)	$	(3	)
Other income		—			115			—
Impairment loss		—			—			(173	)
Total	$	(1	)	$	113		$	(176	)

(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 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. 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 their 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 interest rate assets and liabilities. DESC’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. 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. The inputs and assumptions used in measuring fair value for interest rate derivative contracts include the following:

• 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.

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.

Recurring Fair Value Measurements

Fair value disclosures for assets held in DESC’s pension and other postretirement benefit plans are presented in Note 11.

The following table presents DESC’s 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, 2019
Liabilities
Interest rate	$	—	$	19	$	—	$	19
Total liabilities	$	—	$	19	$	—	$	19
At December 31, 2018
Liabilities
Interest rate	$	—	$	11	$	—	$	11
Total liabilities	$	—	$	11	$	—	$	11

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,	2019				2018
(millions)	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(2)
Long-term debt(3)	$	3,358	$	4,262	$	5,146	$	5,470
Affiliated long-term debt		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) Fair value is estimated based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. 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.

(3) 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, 2019, DESC has recorded AROs of $177 million for nuclear plant decommissioning. At December 31, 2019, DESC had $214 million in a trust for its two-thirds share of decommissioning activities. In addition, DESC has recorded AROs of $312 million for other conditional obligations primarily related to other generation, transmission and distribution properties, including gas pipelines. All of the amounts

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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)	2019			2018
Beginning balance	$	541		$	529
Liabilities settled		(29	)		(15	)
Accretion expense		23			23
Revisions in estimated cash flows(1)		(46	)		4
Ending balance	$	489		$	541

(1)   The decrease in 2019 reflects a change in the estimated timing of cash flows for interim pipeline replacements and DOE recoveries.

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 will continue to accrue through December 31, 2020, after which date no benefits will be accrued except that participants under the cash balance formula will 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 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. The voluntary retirement program will not compromise safety or DESC’s ability to comply with applicable laws and regulations. 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.

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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)	2019			2018			2019			2018
Benefit obligation, January 1	$	732		$	793		$	187		$	217
Service cost		15			17			3			4
Interest cost		28			29			9			8
Plan participants’ contributions		—			—			1			1
Actuarial (gain) loss		47			(46	)		22			(31	)
Benefits paid		(21	)		(19	)		(13	)		(11	)
Settlements		(80	)		(42	)		—			—
Curtailment		6			—			3			—
Amounts funded to parent		—			—			2			(1	)
Benefit obligation, December 31	$	727		$	732		$	214		$	187

The accumulated benefit obligation for pension benefits for DESC was $711 million at the end of 2019 and $714 million at the end of 2018. 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
	2019			2018			2019			2018
Annual discount rate used to determine benefit obligation		3.47	%		4.35	%		3.52	%		4.38	%
Assumed annual rate of future salary increases for projected    benefit obligation		3.00	%		3.00	%	N/A			N/A

A 6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2019. The rate was assumed to decrease gradually to 5.0% for 2023 and to remain at that level thereafter.

A one percent increase in the assumed health care cost trend rate for DESC would increase the postretirement benefit obligation by less than $1 million at December 31, 2019 and by $1 million at December 31, 2018. A one percent decrease in the assumed health care cost trend rate for DESC would decrease the postretirement benefit obligation by less than $1 million at December 31, 2019 and by $1 million at December 31, 2018.

Funded Status

	Pension Benefits						Other Postretirement Benefits
At December 31,	2019			2018			2019			2018
(millions)
Fair value of plan assets	$	725		$	676		$	—		$	—
Benefit obligation		727			732			214			187
Funded status	$	(2	)	$	(56	)	$	(214	)	$	(187	)

Amounts recognized on the consolidated balance sheets were as follows:

	Pension Benefits						Other Postretirement Benefits
At December 31,	2019			2018			2019			2018
(millions)
Current liability	$	—		$	—		$	(13	)	$	(11	)
Noncurrent liability		(2	)		(56	)		(201	)		(177	)

Amounts recognized in accumulated other comprehensive loss were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2019		2018		2019		2018
(millions)
Net actuarial loss	$	2	$	3	$	2	$	1

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Amounts recognized in regulatory assets were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2019		2018		2019		2018
(millions)
Net actuarial loss	$	125	$	202	$	29	$	9
Prior service cost		—		1		—		—
Total	$	125	$	203	$	29	$	9

In connection with the joint ownership of Summer, costs related to pensions attributable to Santee Cooper as of December 31, 2019 and 2018 totaled $19 million and $25 million, respectively, and were recorded within deferred debits. Costs related to other postretirement benefits attributable to Santee Cooper as of December 31, 2019 and 2018 totaled $15 million and $12 million, respectively, and was recorded within deferred debits.

Changes in Fair Value of Plan Assets

Pension Benefits
(millions)	2019			2018
Fair value of plan assets, January 1	$	677		$	781
Actual return (loss) on plan assets		149			(43	)
Benefits paid		(21	)		(61	)
Settlements		(80	)		—
Fair value of plan assets, December 31	$	725		$	677

Investment Policies and Strategies

The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the obligations of the pension plan, (2) overseeing the plan's investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and liabilities, and overall risk associated with assets as compared to liabilities, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. DESC uses a dynamic investment strategy for the management of the pension plan assets. This strategy will lead to a reduction in equities and an increase in long duration fixed income allocations over time with the intention of reducing volatility of funded status and pension costs.

The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, levels of diversification, investment managers and performance expectations. The total portfolio is constructed and maintained to provide prudent diversification with regard to the concentration of holdings in individual issues, corporations, or industries.

Transactions involving certain types of investments are prohibited. These include, except where utilized by a hedge fund manager, any form of private equity; commodities or commodity contracts (except for unleveraged stock or bond index futures and currency futures and options); ownership of real estate in any form other than publicly traded securities; short sales, warrants or margin transactions, or any leveraged investments; and natural resource properties. Investments made for the purpose of engaging in speculative trading are also prohibited.

The pension plan asset allocation at December 31, 2019 and 2018 and the target allocation for 2020 are as follows:

	Percentage of Plan Assets
	Target Allocation			December 31,
Asset Category	2020			2019			2018
Equity Securities		45	%		64	%		55	%
Fixed Income		50	%		35	%		34	%
Cash		5	%		1	%		—	%
Hedge Funds		—	%		—	%		11	%

For 2020, the expected long-term rate of return on assets will be 7%. In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, considers the expected active and passive returns across various asset classes and assumes the target allocation is achieved. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment strategy described previously.

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, 2019 and 2018, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

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At December 31,	2019		2018
(millions)
Investments with fair value measure at Level 2:
Mutual funds	$	152	$	99
Short-term investment vehicles		—		19
US Treasury securities		3		7
Corporate debt instruments		233		86
Government and other debt instruments		26		16
Total assets in the fair value hierarchy		414		227
Investments at net asset value:
Common collective trust		311		373
Joint venture interests		—		77
Total investments	$	725	$	677

For all periods presented, assets with fair value measurements classified as Level 1 were insignificant, and there were no assets with fair value measurements classified as Level 3. There were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during 2019 or 2018.

Mutual funds held by the plan are open-end mutual funds registered with the SEC. The price of the mutual funds' shares is based on its NAV, which is determined by dividing the total value of portfolio investments, less any liabilities, by the total number of shares outstanding. 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. US 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. 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
2020	$	70	$	13
2021		37		13
2022		48		13
2023		46		13
2024		46		13
2025 - 2029		210		69

Pension Plan Contributions

The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and as a result of closing the plan to new entrants and freezing benefit accruals at the end of 2023, no significant contributions to the pension trust are expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply.

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.

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Components of Net Periodic Benefit Cost

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2019			2018			2017			2019		2018		2017
(millions)
Service cost	$	15		$	17		$	18		$	3	$	4	$	4
Interest cost		28			29			32			9		8		9
Expected return on assets		(40	)		(48	)		(46	)		—		—		—
Prior service cost amortization		—			—			1			—		—		—
Amortization of actuarial losses		11			11			14			—		—		1
Settlement loss		16			—			—			—		—		—
Curtailment		6			—			—			3		—		—
Net periodic benefit cost	$	36		$	9		$	19		$	15	$	12	$	14

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,	2019			2018		2017		2019		2018			2017
(millions)
Current year actuarial (gain) loss	$	(1	)	$	1	$	—	$	1	$	(1	)	$	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,	2019			2018			2017			2019		2018			2017
(millions)
Current year actuarial (gain) loss	$	(51	)	$	41		$	(25	)	$	20	$	(26	)	$	7
Amortization of actuarial losses		(11	)		(10	)		(13	)		—		(1	)		—
Amortization of prior service cost		—			—			(1	)		—		—			—
Settlement loss		(16	)		—			—			—		—			—
Total recognized in regulatory assets	$	(78	)	$	31		$	(39	)	$	20	$	(27	)	$	7

Significant assumptions used in determining net periodic benefit cost:

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2019			2018			2017			2019			2018			2017
Discount rate	3.57/4.38%				3.71	%		4.22	%	4.08/4.41%				3.74	%		4.30	%
Expected return on plan assets		7.00	%		7.00	%		7.25	%	n/a			n/a			n/a
Rate of compensation increase		3.00	%		3.00	%		3.00	%	n/a			n/a			n/a
Health care cost trend rate											6.60	%		7.00	%		6.60	%
Ultimate health care cost trend rate											5.00	%		5.00	%		5.00	%
Year achieved										2023			2023			2021

The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2020 are as follows:

(millions)	Pension Benefits		Other Postretirement Benefits
Actuarial loss	$	6	$	1

Other postretirement benefit costs are subject to annual per capita limits pursuant to the plan's design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is not significant.

401(k) Retirement Savings Plan

SCANA sponsors a defined contribution plan in which eligible employees may defer up to 75% of eligible earnings subject to certain limits and may diversify their investments. DESC participates in this plan. Contributions are matched 100% up to 6% of an employee’s eligible earnings. The matching contributions made by DESC totaled $14 million in 2019, $20 million in 2018 and $23 million in 2017. Employee deferrals, matching contributions, and earnings on all contributions are fully vested and non-forfeitable at all times.

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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. 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 and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. DESC and GENCO participate in the SO₂ and NO_X emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at their coal-fired electric generating plants. These actions are expected to address many of the rules and regulations discussed herein.

Air

CAA

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 address all 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.

MATS

In February 2019, the EPA published a proposed rule to reverse its previous finding that it is appropriate and necessary to regulate toxic emissions from power plants. However, the emissions standards and other requirements of the MATS rule would remain in place as the EPA is not proposing to remove coal and oil-fired power plants from the list of sources that are regulated under MATS. Although litigation of the MATS rule and the outcome of the EPA’s rulemaking are still pending, the regulation remains in effect and DESC is complying with the applicable requirements of the rule and does not expect any adverse impacts to its operations at this time.

Ozone Standards

The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018. States have until August 2021 to develop plans to address the new standard. Until the states have developed implementation plans for the standard, DESC is unable to predict whether or to what extent the new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact on DESC’s results of operations and 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 applies to existing coal-fired power plants. The final rule includes unit-specific performance standards based on the degree of emission reduction levels achievable from unit efficiency improvements to be determined by the permitting agency. The ACE Rule requires states to develop plans by July 2022 to implement these performance standards. These state plans must be approved by the EPA by January 2024. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina provide rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

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 to set a significant emissions rate at 75,000 tons per year of CO2 equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, DESC cannot predict the impact to their results of operations, financial condition and/or cash flows.

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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 the best operating practices.

Oil and Gas NSPS

In August 2012, the EPA issued an NSPS impacting new and modified facilities in the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In June 2016, the EPA issued another NSPS regulation, for the oil and natural gas sector, to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. All projects which commenced construction after September 2015 are required to comply with this regulation. In October 2018, the EPA published a proposed rule reconsidering and amending portions of the 2016 rule, including but not limited to, the fugitive emissions requirements at well sites and compressor stations. The amended portions of the 2016 rule were effective immediately upon publication. Until the proposed rule regarding reconsideration is final, DESC is implementing the 2016 regulation. DESC is still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.

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 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, technology, cost and 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 establishes 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 remains December 2023. 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 will be required at Williams and Wateree generating stations, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

In December 2019, the EPA released proposed revisions to the ELG Rule that, if adopted, could extend the deadlines for compliance with certain standards at several facilities. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina provide rate recovery mechanisms that could substantially mitigate any such impacts for the regulated electric utilities.

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

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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 2024 at an estimated cost of $10 million. In September 2018, DESC submitted an updated remediation work plan for one site to SCDHEC, which if approved, would increase costs by approximately $8 million. DESC expects to recover costs arising from the remediation work at all four sites through rate recovery mechanisms and as of December 31, 2019, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $23 million and are included in regulatory assets. Due to the uncertainty surrounding the other sites, DESC is unable to make an estimate of the potential financial statement impacts.

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 flexibilities in implementing their programs. In July 2018, the EPA promulgated the first phase of changes to the CCR rule. Until all phases of the CCR rule are promulgated, DESC cannot forecast potential incremental impacts or costs related to existing coal ash sites in connection with future implementation of the 2016 CCR legislation and reconsideration of 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 regulatory action is taken to incorporate the U.S. Court of Appeals for the D.C. Circuit’s decision, DESC is unable to make an estimate of the potential financial statement impacts associated with any future changes to the CCR rule in connection with the court’s remand.

Abandoned NND Project

DESC, on behalf of itself and as agent for Santee Cooper, entered into an engineering, construction and procurement contract with the Consortium in 2008 for the design and construction of the NND Project. DESC’s ownership share in the NND Project is 55%. Various difficulties were encountered in connection with the project. The ability of the Consortium 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 the Consortium on March 29, 2017 (see Contractor Bankruptcy Proceedings below) and were the subject of comprehensive analyses performed by SCANA, DESC and Santee Cooper.

Santee Cooper decided to suspend construction on the NND Project, on July 31, 2017, and in light of this decision and based on the results of SCANA and DESC’s analysis, SCANA and DESC 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 BLRA or through other means. This decision by SCANA became the focus of numerous legislative, regulatory and legal proceedings, and led to DESC recording pre-tax impairment charges in 2017 totaling approximately $1.1 billion (approximately $690 million after-tax). An additional pre-tax impairment loss was recorded in the first quarter of 2018 of approximately $4 million (approximately $3 million after-tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in the NND Project. These proceedings continued in 2018, and some of them remain unresolved and are described below under Claims and Litigation. On December 21, 2018, the South Carolina Commission issued the SCANA Merger Approval Order, which, among other things, limited recovery of capital costs related to the NND Project to $2.8 billion. As a result, DESC concluded that the NND Project capital costs exceeding the amounts established in the SCANA Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed, and recorded an impairment charge of $1.4 billion ($870 million after-tax) in the fourth quarter of 2018.

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On January 2, 2018, SCANA and Dominion Energy entered into the SCANA Merger Agreement and sought the consents and approvals from governmental entities and the shareholders of SCANA required to consummate the merger. After all consents and approvals were obtained, the SCANA Combination was effective January 1, 2019.

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. In addition, a previously existing regulatory liability of $1.0 billion will be credited to customers over 20 years, 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.

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. As of December 31, 2019, such investment in these assets included $345 million within utility plant, net and $37 million within regulatory assets, which amount represents certain deferred operating 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 is addressed in a future rate proceeding. DESC believes these transmission capital and deferred operating costs are probable of recovery; however, if the South Carolina Commission were to disallow recovery of or a reasonable return on all or a portion of them, an impairment charge up to the disallowed costs may be required.

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 to events occurring before closing of the SCANA Combination. Dominion Energy intends to vigorously contest the lawsuits, claims and assessments which have been filed or initiated against DESC. 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 include reserves of $492 million and insurance receivables of $6 million included within other receivables at December 31, 2019. During the twelve months ended December 31, 2019, the Consolidated Statements of Comprehensive Loss includes charges of $590 million ($444 million after-tax), included within 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). In September 2018, the court certified this case as a class action. The plaintiffs allege, 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. The plaintiffs sought a declaratory judgment that DESC may not charge its customers for any past or continuing costs of the NND Project, sought to have SCANA and DESC’s assets frozen and all monies recovered from Toshiba and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the NND Project.

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In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the DESC Ratepayer Case. The settlement agreement, contingent upon the closing of the SCANA Combination, provided that SCANA and DESC would establish an escrow account and proceeds from the escrow account would be distributed to the class members, 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 DESC Ratepayer Class estimate 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. The court held a fairness hearing on the settlement in May 2019. In June 2019, the court entered an order granting final approval of the settlement, which order became effective July 2019. In July 2019, DESC transferred $117 million representing the cash payment, plus accrued interest, to the plaintiffs. In addition, property with a net recorded cost of $42 million is in the process of being transferred to the plaintiffs in coordination with the court-appointed real estate trustee to satisfy the settlement agreement.

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 are substantially similar to those in the DESC Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the NND Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina which was denied. In December 2018, Santee Cooper filed its answer to the plaintiffs' fourth amended complaint and filed cross claims against DESC. In October 2019, Santee Cooper voluntarily consented to stay its cross claims against DESC pending the outcome of the trial of the underlying case. In November 2019, DESC removed the case to the U.S. District Court for the District of South Carolina. In December 2019, the plaintiffs and Santee Cooper filed a motion to remand the case to state court. In January 2020, the case was remanded to state court. In February 2020, the parties executed a preliminary settlement term sheet relating to this matter as well as the Luquire Case and the Glibowski Case described below. The proposed settlement is expected to be $520 million, of which DESC’s portion is $320 million. The parties are currently negotiating a settlement agreement based on the preliminary settlement term sheet that will be presented to the court for preliminary approval. This case is pending.

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 are similar to the Santee Cooper Ratepayer Case. In February 2020, the parties executed a preliminary settlement term sheet as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Glibowski Case. This case is pending.

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 alleges, 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. The DESC Ratepayer Class Action settlement described previously contemplates dismissal of claims by DESC ratepayers in this case against DESC, SCANA and their officers. In August 2019, the individual defendants filed motions to dismiss. In February 2020, the parties executed a preliminary settlement term sheet as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Luquire Case. This case is pending.

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 August 2018, the case was remanded back to the State Court of Common Pleas in Richland County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal was consolidated with another lawsuit regarding the SCANA Merger Agreement to which DESC is not a party. In June 2019, the U.S. Court of Appeals for the Fourth Circuit reversed the order remanding the case to state court. The case is pending in the U.S. District Court for the District of South Carolina.

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

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defendants failed to provide adequate advance written notice of their terminations of employment and are seeking damages, which are estimated to be as much as $100 million for 100% of the NND Project.

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. These cases are 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. This case is pending.

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. DESC has protested the proposed assessment, which remains pending.

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 addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and DESC. These matters are pending. SCANA and DESC are cooperating fully with the investigations, including responding to additional subpoenas and document requests; however, Dominion Energy cannot currently predict whether or to what extent SCANA or DESC may incur a material liability.

Other Litigation

In December 2018, arbitration proceedings commenced between DESC and Cameco Corporation related to a supply agreement signed in May 2008. This agreement provides the terms and conditions under which DESC agreed to purchase uranium hexafluoride from Cameco Corporation over a period from 2010 to 2020. Cameco Corporation alleges that DESC violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for the 2017 and 2018 delivery years. DESC denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement. This matter is pending.

In September 2019, a South Carolina state court jury awarded a judgment to the estate of Jose Larios in a wrongful death suit filed in June 2017 against DESC, of which DESC was apportioned $19 million. DESC holds general liability insurance coverage which is expected to provide payment for substantially all DESC’s liability in this matter. In October 2019, DESC filed a motion requesting a reduction in the judgment or, in the alternative, a new trial. In November 2019, DESC’s motion for a new trial was granted, setting aside the entire verdict amount. This matter is pending.

Contractor Bankruptcy Proceedings

Westinghouse’s Reorganization Plan became effective August 1, 2018. Initially, Westinghouse had projected that its Reorganization Plan would pay in full or nearly in full its pre-petition trade creditors, including several of the Westinghouse Subcontractors which have alleged non-payment by the Consortium for amounts owed for work performed on the NND Project and have filed liens on related property in Fairfield County, South Carolina. DESC is contesting approximately $285 million of such filed liens. Most of these asserted liens are “pre-petition” claims that relate to work performed by Westinghouse Subcontractors before the Westinghouse bankruptcy, although some of them are “post-petition” claims arising from work performed after the Westinghouse bankruptcy. It is possible that the Reorganization Plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant. In addition, payments under the Toshiba Settlement are subject to reduction if Westinghouse pays Westinghouse Subcontractors holding pre-petition liens directly. Under these circumstances, DESC and Santee Cooper, each in its pro rata share, would be required to make Citibank, N.A., which purchased the scheduled payments under the Toshiba Settlement, whole for reductions related to valid subcontractor and vendor pre-petition liens up to $60 million ($33 million for DESC's 55% share).

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 (i.e., post-petition) until termination of the IAA (the IAA Period). In the Westinghouse bankruptcy proceeding, deadlines were established for creditors of Westinghouse to assert the amounts owed to such creditors prior to the Westinghouse bankruptcy filing and during the IAA Period. Many of the Westinghouse Subcontractors have filed such claims. In December 2019, DESC and Santee Cooper entered into a confidential settlement agreement with W Wind Down Co LLC resolving claims relating to the IAA.

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Further, some Westinghouse Subcontractors who have made claims against Westinghouse in the bankruptcy proceeding also filed against DESC and Santee Cooper in South Carolina state court for damages. The Westinghouse Subcontractor claims in South Carolina state court include common law claims for pre-petition work, IAA Period work, and work after the termination of the IAA. Many of these claimants have also asserted construction liens against the NND Project site. While DESC cannot be assured that it will not have any exposure on account of unpaid Westinghouse Subcontractor claims, which claims DESC is presently disputing, DESC believes it is unlikely that it will be required to make payments on account of such claims.

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 $14.0 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. As of December 31, 2019, 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, 2019, 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)	2020		2021		2022		2023		2024		Thereafter		Total
Purchased electric capacity(1)	$	59	$	58	$	57	$	57	$	57	$	661	$	949

(1) Includes affiliated amounts with certain solar facilities of $234 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 $37 million in 2019 and $24 million in 2018.

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13. LEASES

At December 31, 2019, DESC had the following lease assets and liabilities recorded in the Consolidated Balance Sheets:

At December 31,	2019
(millions)
Lease assets:
Operating lease assets(1)	$	23
Finance lease assets(2)		26
Total lease assets	$	49
Lease liabilities:
Operating lease - current(3)	$	3
Operating lease - noncurrent(4)		20
Finance lease - current(5)		7
Finance lease - noncurrent		20
Total lease liabilities	$	50

(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 $24 million of accumulated amortization at December 31, 2019.

(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 current portion of long-term debt in the Consolidated Balance Sheets.

For the year ended December 31, 2019, total lease cost consisted of the following:

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

For the year ended December 31, 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,	2019
(millions)
Operating cash flows from finance leases	$	1
Operating cash flows from operating leases		3
Financing cash flows from finance leases		7

At December 31, 2019, the weighted average remaining lease term and weighted average discount rate for finance and operating leases were as follows:

At December 31,	2019
Weighted average remaining lease term - finance leases	5 years
Weighted average remaining lease term - operating leases	18 years
Weighted average discount rate - finance leases		2.94	%
Weighted average discount rate - operating leases		3.94	%

Lease liabilities have the following scheduled maturities:

(millions)	Operating			Finance
2020	$	4		$	8
2021		3			7
2022		2			5
2023		2			4
2024		1			2
After 2024		23			3
Total undiscounted lease payments		35			29
Present value adjustment		(12	)		(2	)
Present value of lease liabilities	$	23		$	27

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14.  OPERATING SEGMENTS

In December 2019, DESC realigned its segments which resulted in the formation of a single primary operating segment. The historical information presented herein has been recast to reflect the current segment presentation.

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 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.

In 2018, DESC reported after-tax net expenses of $917 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 2018 primarily related to a $1.4 billion ($870 million after-tax) impairment charge associated with the NND Project.

In 2017, DESC reported after-tax net expenses of $690 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 2017 related to a $1.1 billion ($690 million after-tax) impairment charge associated with the NND Project.

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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)
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
Total assets (billions)		14.3		—			14.3
2018
External revenue	$	2,763	$	(1	)	$	2,762
Depreciation and amortization		327		—			327
Interest and related charges		306		(3	)		303
Income tax expense (benefit)		98		(514	)		(416	)
Comprehensive income (loss) available (attributable) to    common shareholder		304		(917	)		(613	)
Capital expenditures		633		—			633
Total assets (billions)		15.0		—			15.0
2017
External revenue	$	3,070	$	—		$	3,070
Depreciation and amortization		312		—			312
Interest and related charges		288		—			288
Income tax expense (benefit)		257		(428	)		(171	)
Comprehensive income (loss) available (attributable) to    common shareholder		505		(690	)		(185	)
Capital expenditures		928		—			928

15.  UTILITY PLANT AND NONUTILITY PROPERTY

Major classes of utility plant and other property and their respective balances at December 31, 2019 and 2018 were as follows:

At December 31,	2019		2018
(millions)
Gross utility plant:
Generation	$	5,765	$	5,751
Transmission		1,905		1,758
Distribution		4,685		4,456
Storage		73		74
General and other		549		535
Intangible		231		229
Construction work in progress		339		350
Nuclear fuel		608		611
Total gross utility plant	$	14,155	$	13,764
Gross nonutility property	$	75	$	73

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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 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,	2019			2018
	Summer Unit 1			Summer Unit 1
Percent owned	66.7%			66.7%
Plant in service	$	1.4	billion	$	1.5	billion
Accumulated depreciation	$	684	million	$	644	million
Construction work in progress	$	79	million	$	128	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 $50 million at December 31, 2019 and $46 million at December 31, 2018.

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 income (expense), net in DESC’s Consolidated Statements of Comprehensive 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 is involved in the manufacturing and sale of refined coal to reduce emissions at certain 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 Loss.

DESC purchases natural gas and related pipeline capacity from SCANA Energy Marketing, Inc. to service its retail gas customers and to satisfy certain electric generation requirements. These purchases are included within gas purchased for resale or fuel used in electric generation, as applicable in the Consolidated Statements of Comprehensive Loss.

DESS, on behalf of itself and its parent company, provides the following services to DESC, which are 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 processes and pays invoices for DESC and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in other operations and maintenance – affiliated suppliers and other income (expense), net in the Consolidated Statements of Comprehensive Loss.

Year Ended December 31,	2019		2018		2017
(millions)
Purchases of coal from affiliate	$	121	$	150	$	162
Sales of coal to affiliate		120		149		161
Purchases of fuel used in electric generation from affiliate		43		139		127
Direct and allocated costs from services company affiliate(1)		297		283		303
Operating Revenues – Electric from sales to affiliate		4		5		5
Operating Revenues – Gas from sales to affiliate		1		1		1
Operating Expenses – Other taxes from affiliate		6		6		5

(1) Includes capitalized expenditures of $53 million, $41 million and $82 million for the years ended December 31, 2019, 2018 and 2017, respectively.

At December 31,	2019		2018
(millions)
Receivable from Canadys Refined Coal, LLC	$	2	$	7
Payable to Canadys Refined Coal, LLC		2		7
Payable to SCANA Energy Marketing, Inc		—		14
Payable to DESS		76		38
Payable to Public Service Company of North Carolina, Incorporated		8		7

In connection with the SCANA Combination, purchases from certain entities owned by Dominion Energy became affiliated transactions. During the year ended December 31, 2019, DESC purchased electricity generated by certain solar facilities, totaling $8 million, which is recorded as purchased power in the Consolidated Statements of Comprehensive Loss. At December 31, 2019, DESC

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had accounts payable balances to these affiliates totaling less than $1 million. In addition, during the year ended December 31, 2019, DESC incurred demand and transportation charges from DECG totaling $63 million, of which $19 million is recorded as fuel used in electric generation and $44 million is recorded as gas purchased for resale in the Consolidated Statements of Comprehensive Loss. At December 31, 2019, DESC had an accounts payable balance due to this affiliate totaling $5 million and an accounts receivable to this affiliate totaling $1 million.

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,	2019			2018			2017
(millions)
Revenues from contracts with customers	$	4		$	5		$	—
Other income		19			141			45
Other expense		(57	)		(28	)		(32	)
Allowance for equity funds used during construction		1			11			15
Other income (expense), net	$	(33	)	$	129		$	28

The recording of revenue from contracts with customers within other income (expense) arose upon the adoption of related accounting guidance described in Note 1 and Note 4, and as permitted, periods prior to adoption have not been restated. Other income in 2018 includes gains from the settlement of interest rate derivatives of $115 million (see Note 8). Non-service cost components of pension and other postretirement benefits are included in other expense.

18.  QUARTERLY FINANCIAL DATA (UNAUDITED)

A summary of DESC’s quarterly results of operations for the years ended December 31, 2019 and 2018 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

(millions)	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
2019
Operating revenue	$	(335	)	$	698		$	795	$	771
Operating income (loss)		(1,143	)		17			261		(76	)
Total comprehensive income (loss)		(1,103	)		(70	)		143		(191	)
Comprehensive income (loss) available (attributable) to    common shareholder		(1,109	)		(78	)		143		(195	)
2018
Operating revenue	$	702		$	632		$	739	$	689
Operating income (loss)		121			107			212		(1,271	)
Total comprehensive income (loss)		128			31			104		(852	)
Comprehensive income (loss) available (attributable) to    common shareholder		124			26			98		(861	)

DESC’s 2019 results include the impact of the following significant items:

• Fourth quarter results include a $240 million after-tax charge related to litigation.

• Second quarter results include a $75 million after-tax charge related to litigation and a $47 million after-tax charge related to a voluntary retirement program.

• First quarter results include a $756 million after-tax charge for refunds of amounts previously collected from retail electric customers for the NND Project, a $198 million tax charge for $264 million of income tax-related regulatory assets for which DESC committed to forgo recovery, a $118 million after-tax charge for a settlement agreement of a DESC ratepayer class action lawsuit and an $86 million after-tax charge for property, plant and equipment for which DESC committed to forgo recovery.

DESC’s 2018 results include the impact of the following significant item:

• Fourth quarter results include a $870 million after-tax impairment charge related to the NND Project.

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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 2019 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, 2019, 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, 2019. 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, 2019.

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 28, 2020

Item 9B. Other Information

None.

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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, 2019 and 2018.

Type of Fees	2019		2018
(millions)
Audit fees	$	1.92	$	2.62
Audit-related fees		—		0.10
Total Fees	$	1.92	$	2.72

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 2019 meeting, the Dominion Energy Audit Committee approved schedules of services and fees for 2020 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.

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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 18.

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 from South Carolina Electric & Gas Company to The Bank of New York Mellon Trust Company, N. A. (as successor to NationsBank of Georgia, National Association), as Trustee (Filed as Exhibit 4-F to Registration Statement No. 33-49421). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
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 filed October 3, 2013, File No. 333-184426).
4.06	Description of Series A Nonvoting Preferred Shares (filed herewith).
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 Fourth Amended and Restated Revolving Credit Agreement, dated March 22, 2019, among Dominion Energy, Inc., Virginia Electric and Power Company, Dominion Energy Gas Holdings, LLC, Questar Gas Company, South Carolina Electric & Gas Company, 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, and other lenders named therein (Exhibit 10.1, Form 8-K filed March 26, 2019, File No. 1-3375).
10.03	Service Agreement, dated January 1, 2004, by and between South Carolina Electric & Gas Company and SCANA Services, Inc. (Exhibit 99.10, Form S-8 filed June 9, 2011, File No. 333-174796).
10.04	DES Services Agreement, dated February 20, 2019, by and between South Carolina Electric & Gas Company and Dominion Energy Services, Inc. (filed herewith).
10.05	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).
10.06	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).

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10.07	Settlement Agreement and an Addendum dated as of November 24, 2018, by and among SCANA Corporation, South Carolina Electric & Gas Company, Richard Lightsey, LeBrian Cleckley, Phillip Cooper and the State of South Carolina (Exhibit 10.08, Form 10-K for the fiscal year ended December 31, 2018 filed February 28, 2019, File No. 1-3375).
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).
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, 2019, filed on February 28, 2020, formatted in iXBRL (Inline eXtensible Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Comprehensive 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.

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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/ Thomas F. Farrell, II
		(Thomas F. Farrell, II, Chairman of the Board of Directors)
DATE: February 28, 2020

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 28^th day of February, 2020.

Signature	Title
/s/ Thomas F. Farrell, II	Chairman of the Board of Directors
Thomas F. Farrell, II
/s/ Diane Leopold	Director and Chief Executive Officer
Diane Leopold
/s/ James R. Chapman	Director, Executive Vice President and Chief Financial Officer
James R. Chapman
/s/ Michele L. Cardiff	Vice President, Controller and Chief Accounting Officer
Michele L. Cardiff

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EX-4.06

EXHIBIT 4.06

DESCRIPTION OF DOMINION ENERGY SOUTH CAROLINA, INC.

SERIES A NONVOTING PREFERRED SHARES

The following description of our Series A Nonvoting Preferred Shares, which are registered under Section 12(g) of the Securities Exchange Act of 1934, as amended, is a summary and is qualified in its entirety by reference to our articles of incorporation and bylaws, which are incorporated by reference as exhibits to the Annual Report on Form 10-K of which this exhibit is a part.  We encourage you to read our articles of incorporation and bylaws, as well as applicable provisions of the South Carolina Business Corporation Act of 1988, as amended, for more information.

Authorized Shares

Dominion Energy South Carolina (“DESC”) is authorized to issue 20,000,000 shares of Preferred Shares and has issued one series of Preferred Shares, its Series A Nonvoting Preferred Shares.  There are 1,000 shares of Series A Nonvoting Preferred Shares issued and outstanding, each of which is held by SCANA Corporation, a wholly-owned subsidiary of Dominion Energy, Inc. The Series A Nonvoting Preferred Shares do not have a par value.

Ranking and Liquidation Rights

The Series A Nonvoting Preferred Shares rank, with respect to distributions and rights on liquidation, dissolution and winding-up: (i) on a parity with the DESC’s common shares and each other class and series of shares of DESC, the terms of which expressly provide that such class or series ranks on a parity with the Series A Nonvoting Preferred Shares as to distributions or rights on liquidation, dissolution and winding-up (collectively referred to as “Parity Securities”); and (ii) junior to each class or series of shares of DESC, the terms of which expressly provide that such class or series ranks senior to the Series A Nonvoting Preferred Shares as to dividend rights and rights on liquidation, dissolution and winding-up of DESC.

Subject to the rights of any other series of preferred shares of DESC then outstanding, in the event of any liquidation, dissolution or winding up of DESC, whether voluntary or involuntary, the remaining assets and funds of DESC available for distribution, if any, will be distributed among the holders of Series A Nonvoting Preferred Shares and Parity Securities in proportion to the number of Series A Nonvoting Preferred Shares and Parity Securities held by each of them.

Distribution Rights

Holders of Series A Nonvoting Preferred Shares are entitled to receive distributions only when, as and if declared by DESC’s board of directors out of funds legally available therefor, whether in the form of cash, property or securities of DESC, ratably on a per-share basis. The rights of the holders of Series A Nonvoting Preferred Shares to receive distributions are subject to the rights of each other series of preferred shares of DESC then outstanding.

Voting Rights

Except as otherwise required by South Carolina law, holders of Series A Nonvoting Preferred Shares are not entitled to any voting rights.

Preemptive and Other Rights

The Series A Nonvoting Preferred Shares are not convertible and are not entitled to any preemptive rights. The Series A Nonvoting Preferred Shares are not subject to any redemption rights or sinking fund provisions. There is no restriction on the repurchase or redemption of shares by the Company while there is any arrearage in the payment of dividends or sinking fund installments. 

EX-10.04

Exhibit 10.04

DES Services Agreement

This DES Services Agreement (this “Agreement”) is entered into as of February 20, 2019, by and between South Carolina Electric & Gas Company, a South Carolina corporation (the “Company”), and DOMINION ENERGY SERVICES, INC., a Virginia corporation (“DES”), for the benefit of the Company.  DES is sometimes referred to herein as “Service Company.”

WHEREAS, each of the Company and DES is a direct or indirect wholly-owned subsidiary of Dominion Energy, Inc., a Virginia corporation and a “holding company” as defined in the Public Utility Holding Company Act of 2005 that is subject to regulation as such under that Act by the Federal Energy Regulatory Commission (“Dominion”);

WHEREAS, DES has been formed for the purpose of providing administrative, management and other services to Dominion and its subsidiaries (“Dominion Companies”) as a subsidiary service company;

WHEREAS, the Company believes that it is in the interest of the Company to provide for an arrangement whereby the Company may, from time to time and at the option of the Company, agree to purchase such administrative, management and other services as set forth in Exhibit I hereto from DES for its benefit.

NOW, THEREFORE, in consideration of the mutual covenants contained herein and other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound, hereby agree as follows:

I.  SERVICES OFFERED.  Exhibit I hereto lists and describes all of the services that are available from DES. DES hereby offers to supply those services to the Company for the benefit of the Company.  Such services are and will be provided to the Company only at the request of the Company.  DES will provide such requested services using personnel from DES and, if necessary, from non-affiliated third parties in accordance with Section III herein.

II.  INITIAL SERVICES SELECTED.  Exhibit II lists the services from Exhibit I that (i) the Company hereby agrees to receive from DES, and (ii) DES hereby agrees to provide to the Company.

III.  PERSONNEL.  DES will provide services by utilizing the services of such executives, accountants, financial advisers, technical advisers, attorneys, engineers, geologists and other persons as have the necessary qualifications.

If necessary, DES, after consultation with the Company, may also arrange for the services of non-affiliated experts, consultants and attorneys in connection with the performance of any of the services supplied under this Agreement.

IV.  COMPENSATION AND ALLOCATION.  As and to the extent required by law, DES will provide such services at cost.  Exhibit III hereof contains rules and methods for determining and allocating costs for DES.

V.  EFFECTIVE DATE.  This Agreement is effective as of January 2, 2019 (the “Effective Date”).

VI.  TERM.  This Agreement shall commence on the Effective Date and shall remain in effect unless terminated earlier pursuant to Section VII(C).

VII.  TERMINATION AND MODIFICATION.

A.Modification of Services.  The Company may modify its selection of services at any time during the calendar year by giving DES written notice of the additional services it wishes to receive, and/or the services it no longer wishes to receive, in Exhibit I from DES.  The requested modification in services shall take effect on the first day of the first calendar month beginning at least thirty (30) days after the Company sent written notice to DES.

B.Modification of Other Terms and Conditions.   No other amendment, change or modification of this Agreement shall be valid, unless made in writing and signed by all parties hereto.

C.Termination of this Agreement.  The Company may terminate this Agreement by providing sixty (60) days advance written notice of such termination to DES.  DES may terminate this Agreement by providing sixty (60) days advance written notice of such termination to the Company.

This Agreement shall be subject to the approval of any state commission or other state regulatory body whose approval is, by the laws of said state, a legal prerequisite to the execution and delivery or the performance of this Agreement.

VIII.  NOTICE.  Where written notice is required by this Agreement, said notice shall be deemed given when mailed by United States registered or certified mail, postage prepaid, return receipt requested, addressed as follows:

a.To the Company:

South Carolina Electric & Gas Company

100 SCANA Parkway

Cayce, South Carolina 29033

With a Copy to:

Dominion Energy Services, Inc.

Law Department

120 Tredegar Street

Richmond, Virginia 23219

Attention:  Managing Counsel and State Regulatory Team

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b.To DES:

Dominion Energy Services, Inc.

120 Tredegar Street

Richmond, Virginia 23219

With a Copy to:

Dominion Energy Services, Inc.

Law Department

120 Tredegar Street

Richmond, Virginia 23219

Attention:  Managing Counsel and State Regulatory Team

IX.  GOVERNING LAW.  This Agreement shall be governed by and construed in accordance with the laws of Virginia, without regard to its conflict of laws provisions.

X.  ENTIRE AGREEMENT.  This Agreement, together with its exhibits, constitutes the entire understanding and agreement of the parties with respect to its subject matter, and effective upon the execution of this Agreement by the respective parties hereof and thereto, any and all prior agreements, understandings or representations with respect to this subject matter are hereby terminated and cancelled in their entirety and are of no further force and effect.

XI.  WAIVER.  No waiver by any party hereto of a breach of any provision of this Agreement shall constitute a waiver of any preceding or succeeding breach of the same or any other provision hereof.

XII.  ASSIGNMENT.  This Agreement shall inure to the benefit of and shall be binding upon the parties and their respective successors and assigns.  No assignment of this Agreement or any party’s rights, interests or obligations hereunder may be made without the other party’s consent, which shall not be unreasonably withheld, delayed or conditioned; provided, however, that, subject to the requirements of applicable state and federal regulatory law, either party may assign its rights, interests or obligations under this Agreement to an “affiliated interest,” without the consent of the other party.

XIII.  SEVERABILITY.  If any provision or provisions of this Agreement shall be held to be invalid, illegal, or unenforceable, the validity, legality, and enforceability of the remaining provisions shall in no way be affected or impaired thereby.

XIV.CONFIDENTIALITY.

a. For purposes of this Agreement, “Confidential Information” is information provided by the Company, or created or discovered by, for, or on behalf of the Company including, but not limited to information relating to products, processes, techniques, formulas, ideas, know-how, works of authorship, copyrightable works, inventions (whether patentable or not), technical information, trade secrets, computer programs, computer code, designs, technology, compositions, data, drawings, schematics,

3

customers, product development, plans, and other business, technical, and financial information.  

b. At all times, both during this Agreement and after its termination, DES will protect Confidential Information from unauthorized dissemination and use with the same degree of care that DES uses to protect its own confidential information, but with not less than reasonable care and diligence, and will not disclose any Confidential Information unless necessary to perform services hereunder and reasonable measures are taken to avoid wrongful disclosures.  DES may use such Confidential Information solely for performing the services under this Agreement and for no other purpose.

c. DES will not be obligated under this Agreement with respect to information that DES can document : (1) is or has become publicly known through no fault of DES or its employees or agents; (2) is or was received without restriction from a third party lawfully in possession of such information and lawfully empowered to disclose such information; (3) was rightfully in the possession of DES without restriction prior to its disclosure by the Company; or (4) is or was independently developed by or on behalf of DES.

d. DES acknowledges that any disclosure or unauthorized use of Confidential Information will constitute a material breach of this Agreement and cause substantial and irreparable harm to the Company for which damages would not be a fully adequate remedy and, therefore, in the event of any such breach, in addition to other available remedies, the Company will have the right to obtain appropriate injunctive relief.

IN WITNESS WHEREOF, the parties have caused this Agreement to be duly executed as ofthe date first above mentioned.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

By:/s/ P. Rodney Blevins

Name:P. Rodney Blevins

Title:President and Chief Executive Officer

Southeast Energy Group

DOMINION ENERGY SERVICES, INC.

By:/s/ Carter M. Reid

Name:Carter M. Reid

Title:Executive Vice President, Chief

Administrative & Compliance

Officer and Corporate Secretary

4

EXHIBIT I

DESCRIPTION OF SERVICES OFFERED BY DES
UNDER THIS DES SERVICES AGREEMENT

1.Accounting.  Provide advice and assistance to Dominion Companies in accounting matters (development of accounting practices, procedures and controls, the maintenance of the general ledger and related subsidiary systems, the preparation and analysis of financial reports, and the processing of certain accounts such as accounts payable, accounts receivable, and payroll).

2.Auditing.  Periodically audit the accounting records and other records maintained by Dominion Companies and coordinate their examination, where applicable, with that of independent public accountants.  The audit staff will report on their examination and submit recommendations, as appropriate, on improving methods of internal control and accounting procedures.

3.Legal.  Provide advice and assistance with respect to legal and regulatory issues as well as regulatory compliance and matters under federal and state laws.

4.Information Technology, Electronic Transmission and Computer Services.  Provide the organization and resources for the operation of an information technology function (development, implementation and operation of a centralized data processing facility and the management of a telecommunications network, and the central processing of computerized applications and support of individual applications in Dominion Companies).  Develop, implement, and process those computerized applications for Dominion Companies that can be economically best accomplished on a centralized basis.  Develop, implement, and process information technology risk management services and services for the secure protection and transmission of critical and sensitive data.

5.Software/Hardware Pooling.  Accept from Dominion Companies ownership of and rights to use, assign, license or sub-license all software owned, acquired or developed by or for Dominion Companies which Dominion Companies can and do transfer or assign to it and computer system hardware used with software and enhancements to which DES has legal right.  Preserve and protect the rights to all such software to the extent reasonable and appropriate under the circumstances; licenseDominion Companies, on a non-exclusive, no-charge or at-cost basis, to use all software which DES has the right to sell, license or sub-license; and, at the relevant Dominion Companies’ expense, permit Dominion Companies to enhance any such software and license others to use all such software and enhancements to the extent that DES shall have the legal right to so permit.

6.Human Resources.  Advise and assist Dominion Companies in the formulation and administration of human resources policies and programs relating to the relevant

Dominion Companies’ labor relations, personnel administration, training, wage and salary administration, staffing and safety.  Direct and administer all medical, health, and employee benefit and pension plans of Dominion Companies.  Provide systems of physical examination for employment and other purposes and direct and administer programs for the prevention of sickness.  Advise and assist Dominion Companies in the administration of such plans and prepare and maintain records of employee and company accounts under the said plans, together with such statistical data and reports as are pertinent to the plans.  

7.Operations.  Advise and assist Dominion Companies in the following matters relating to operational capacity: (i) the preparation and coordination of studying, consulting, planning, designing, inspecting and engineering and construction of facilities of Dominion Companies, (ii) the planning, engineering (including maps and records) and construction operations of Dominion Companies, (iii) the performance of operations support services, plant and facilities operation, generation outage support, and maintenance and management services, and (iv) the planning, formulation and implementation of load retention, load shaping and conservation and efficiency programs, and integrated resource planning for supply-side plans and demand-side management programs.  Develop long-range operational programs for Dominion Companies and advise and assist each such Company in the coordination of such programs with the programs of the other Dominion subsidiaries, subject to federal and state codes and standards of conduct, as applicable.  Manage Dominion Companies’ purchase, movement, transfer, and accounting of fuel and gas volumes.

8.Executive and Administrative.  Advise and assist Dominion Companies in the solution of major problems and in the formulation and execution of the general plans and policies of Dominion Companies.  Advise and assist Dominion Companies as to operations, the issuance of securities, the preparation of filings arising out of or required by the various federal and state securities, business, public utilities and corporation laws, the selection of executive and administrative personnel, the representation of Dominion Companies before regulatory bodies, proposals for capital expenditures, budgets, financing, acquisition and disposition of properties, expansion of business, rate structures, public relationships and related matters.

9.Business Services.  Perform: (i) general business support services (printing, mailing, records management and maintenance, and administrative and office services across the enterprise), (ii) office facilities operation (building maintenance and property management, lease/sublease management, and property sales services across the enterprise),
(iii) security (physical security support, background investigations, and investigative services across the enterprise), (iv) travel (business-related ticketing, itinerary coordination, and reservations for airlines, train, rental cars, and hotels/lodging for Dominion employees),
(v) aviation (maintenance, operations, and aviation-related services for corporate-owned aircraft), and (vi) fleet services (fleet systems support, management of the acquisition/disposal function, maintenance functions, and fleet management across the entire enterprise).  

10.Risk Management.  Advise and assist Dominion Companies in securing requisite insurance, in the purchase and administration of all property, casualty and marine insurance, in the settlement of insured claims and in providing risk prevention advice.

2

11.Corporate Planning.  Advise and assist Dominion Companies in the study and planning of operations, budgets, economic forecasts, capital expenditures and special projects.

12.Supply Chain.  Advise and assist Dominion Companies in the procurement of real and personal property, materials, supplies and services, conduct purchase negotiations, prepare procurement agreements and administer programs of material control.

13.Rates and Regulatory.  Advise and assist Dominion Companies in the analysis of their rate structure in the formulation of rate policies, and in the negotiation of large contracts.  Advise and assist Dominion Companies in proceedings before regulatory bodies involving the rates and operations of Dominion Companies and of other competitors where such rates and operations directly or indirectly affect Dominion Companies.

14.Tax.  Advise and assist Dominion Companies in the preparation of federal, state and other tax returns, generally advise Dominion Companies as to any problems involving taxes, and provide due diligence in connection with acquisitions.

15.Corporate Secretary.  Provide all necessary functions required of a publicly traded company.  Coordinate information and activities among owners, the transfer agent, and Board of Directors.  Provide direct services to security holders. Prepare and file required annual and interim reports to owners and the U.S. Securities and Exchange Commission. Conduct director meetings and ensure proper maintenance of corporate records.

16.Investor Relations.  Provide fair and accurate analysis of Dominion Companies and an outlook within the financial community. Enhance Dominion Companies’ position in the energy industry. Balance and diversify owner investment in Dominion Companies through a wide range of activities. Provide feedback to Dominion Companies regarding investor concerns, trading and ownerships. Hold periodic analysts meetings, and provide various operating data as requested or required by investors.

17.Environmental Compliance.  Provide consulting, cleanup, environmental permitting, environmental compliance support, biological and chemical services, environmental reporting, and environmental compliance plan preparation as required by Dominion Companies to ensure full compliance with applicable environmental statutes and regulations.  Track state and federal environmental regulations.  Provide summaries and guidance for Company personnel to ensure ongoing compliance.

18.Customer Services.  Provide services and systems dedicated to customer service, billing, remittance, credit, collections, customer relations, call centers, energy conservation support and metering.

19.Energy Marketing.  Provide services and systems dedicated to energy marketing and trading of energy commodities, specifically the provision of all services related to emissions products, renewable energy products, environmental commodities (commodities derived from environmental attributes associated with qualifying types of generation that are

3

required for compliance with applicable federal, state and local laws, as well as any voluntary additional reductions that the Company has elected to complete).  Provide market, credit and operational risk management services and development of marketing and sales programs in physical and financial markets.

20.Treasury/Finance.  Provide services related to managing all administrative activities associated with financing and the management of capital structure; cash, credit and risk management activities; investment and commercial banking relationships; oversight of decommissioning trust funds and general financing activities.

21.External Affairs.  Provide services in support of corporate strategies for managing relationships with federal, state and local governments, agencies and legislative bodies.  Formulate and assist with public relations, advertising, and external/internal communications programs and with the administration of corporate contribution and community affairs programs.

22.Office Space and Equipment.  Provide use of land, buildings, furnishings, and equipment, and all costs related to these assets – i.e., property taxes, utilities, and maintenance.  

4

EXHIBIT II

SERVICES THE COMPANY AGREES TO RECEIVE FROM DES

SERVICE		YES	NO
1.	Accounting	X
2.	Auditing	X
3.	Legal	X
4.	Information Technology, Electronic Transmission and Computer Services	X
5.	Software/Hardware Pooling	X
6.	Human Resources	X
7.	Operations	X
8.	Executive and Administrative	X
9.	Business Services	X
10.	Risk Management	X
11.	Corporate Planning	X
12.	Supply Chain	X
13.	Rates and Regulatory	X
14.	Tax	X
15.	Corporate Secretary	X
16.	Investior Relations	X
17.	Environmental Compliance	X
18.	Customer Services	X
19.	Energy Marketing	X
20.	Treasury/Finance	X
21.	External Affairs	X
22.	Office Space and Equipment	X

EXHIBIT III

METHODS OF ALLOCATION FOR DES

DES shall allocate costs among companies receiving service from it under this and similar service contracts using the following methods:

I. The costs of rendering service by DES will include all costs of doing business including interest on debt but excluding a return for the use of equity capital for which no charge will be made to Dominion Companies.

II. A.DES will maintain a separate record of the expenses of each department.  The expenses of each department will include:

1. those expenses that are directly attributable to such department, and

2. an appropriate portion of those office and housekeeping expenses that are not directly attributable to a department but which are necessary to the operation of such department.

B. Expenses of the department will include salaries and wages of employees, rent and utilities, materials and supplies, depreciation, and all other expenses attributable to the department.  The expenses of a department will not include:

1. those incremental out‑of‑pocket expenses that are incurred for the direct benefit and convenience of an individual Dominion Company or group of Dominion Companies,

2. DES overhead expenses that are attributable to maintaining the corporate existence of DES, and all other incidental overhead expenses including those auditing fees, internal auditing department expenses and accounting department expenses attributable to DES.

C. DES will establish annual budgets for controlling the expenses of each department and for determining estimated costs to be included in interim monthly billing.

III. A.Employees in each department will be divided into two groups:

1. Group A will include those employees rendering service to Dominion Companies, and

2. Group B will include those office and general service employees, such as secretaries, file clerks and administrative assistants, who generally assist employees in Group A or render other housekeeping services and who are not engaged directly in rendering service to each Dominion Company or a group of Dominion Companies.

B. Expenses set forth in Section II. above will be separated to show:

1. salaries and wages of Group A employees, and

2. all other expenses of the department.

C. There will be attributed to each dollar of a Group A employee’s salary or wage, that percentage of all other expenses of such employee’s department (as defined in B above), that such employee’s salary or wage is to the total Group A salaries and wages of that department.

D. Group A employees in each department will maintain a record of the time they are employed in rendering service to each Dominion Company or group of Dominion Companies.  An hourly rate will be determined by dividing the total expense attributable to a Group A employee as determined under subsection C above by the productive hours reported by such employee.

IV. The charge to the Dominion Company for a particular service will be determined by multiplying the hours reported by Group A employees in rendering such service to each Dominion Company by the hourly rates applicable to such employees.  When such employees render service to a group of Dominion Companies, the charge to each Dominion Company will be determined by multiplying the hours attributable to the Dominion Company under the allocation formulas set forth in Section IX of this Exhibit by the hourly rates applicable to such employees.

V. To the extent appropriate and practical, the foregoing computations of hourly rates and charges may be determined for groups of employees within reasonable salary range limits.

VI. Those expenses of DES that are not included in the annual expense of a department under Section II above will be charged to Dominion Companies receiving service as follows:

A. Incremental out‑of‑pocket costs incurred for the direct benefit and convenience of a Dominion Company or group of Dominion Companies will be charged directly to such Dominion Company or group of

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Dominion Companies.  Such costs incurred for a group of Dominion Companies will be allocated on the basis of an appropriate formula.

B. DES overhead expenses referred to in Section II above will be charged to the Dominion Company either on the proportion of direct charges to that Dominion Company or under the allocation formulas set forth in Section IX of this Exhibit.

VII. Notwithstanding the foregoing basis of determining cost allocations for billing purposes, cost allocations for certain services involving machine operations, production or service units, or facilities cost will be determined on an appropriate basis established by DES.

VIII. Monthly bills will be issued for the services rendered to the Dominion Company on an actual basis. However, if such actual information is not available at the time of preparation of the monthly bill, estimates may be used.  Estimates will normally be predicated on service department budgets and estimated productive hours of employees for the year.  At the end of each quarter, estimated figures will be revised and adjustments will be made in amounts billed to give effect to such revision.

IX. When Group A employees render services to a group of Dominion Companies, the following formulas shall be used to allocate the time of such employees to the individual Dominion Companies receiving such service (Each Dominion Company metric/Total Dominion Companies’ metrics):

A. The Service Department or Function formulas to be used when employees render services to all Dominion Companies participating in such service, for the services indicated are set forth below.  

Service Department or Function	Basis of Allocation
Accounting:
Payroll Processing	Number of Dominion Company employeeson the previous December 31st.
Accounts Payable Processing	Number of Dominion Company accounts payable documents processed during the preceding year ended December 31st.  [Accounts Payable Invoices]  Dollar value of Dominion Company purchases on company credit cards for the preceding year ended December 31st.  [Accounts Payable P-Card]
Fixed Assets Accounting	Dominion Company fixed assets added, retired or transferred during the preceding year ended December 31st.

3

Service Department or Function	Basis of Allocation
Information Technology, Electronic Transmission and Computer Services and Software/Hardware Pooling:
LDC/EDC  Computer Applications	Number of Dominion Company customers at the end of the preceding year ended December 31st.
Other Computer Applications, including Software/Hardware Pooling	Number of Dominion Company users or usage of specific computer systems at the end of the preceding year ended December 31st.
Telecommunications Applications	Number of Dominion Company telecommunications units at the end of the preceding year ended December 31st.
Human Resources:
Human Resources	The number of Dominion Company employees as of the preceding December 31st.
Business Services:
Facility Services	Square footage of Dominion Company office space as of the preceding year ended December 31st.
Fleet Administration	Number of Dominion Company vehicles as of the preceding December 31st.
Security	The number of Dominion Company employees as of the preceding December 31st.
Gas Supply	Throughput of gas volumes purchased for each Dominion Company for the preceding year ended December 31st.
Risk Management:
Risk Management	Dominion Company insurance premiums for the preceding year ended December 31st.
Corporate Planning:
Corporate Planning	Total Dominion Company capitalization (Debt and Equity) recorded at preceding December 31st.
Supply Chain:
Purchasing	Dollar value of Dominion Company purchases for the preceding year ended December 31st.
Tax:
Tax Accounting and Compliance	The sum of the total income and total deductions as reported for Dominion Consolidated Federal Income Tax purposes on the last return filed.

4

Service Department or Function	Basis of Allocation
Customer Services:
Customer Payment (Remittance) Processing	Number of Dominion Company customer payments processed during the preceding year ended December 31st.
Treasury/ Finance:
Treasury and Cash Management	Total Dominion Company capitalization (Debt and Equity) recorded at preceding December 31st.
Office Space and Equipment:
Corporate Office and Electricity	Headcount at corporate offices as of the previous December 31st.

B. For services not mentioned above, the method of allocation is set forth below:

Company Group	Basis of Allocation
Accounting Audit Business Planning Corporate Secretary Energy Marketing Environment Executive External Affairs General Services Legal Operations Travel Services Aviation	Total operating expenses, excluding purchased gas expense, purchased power expense (including fuel expense), other purchased products and royalties, depreciation, depletion, and amortization, and taxes other than income for the preceding year ended December 31st for the affected Dominion Companies. A combination of items immediately noted above and flight days for the previous two years.

C. If the use of a basis of allocation would result in an inequity because of a change in operations or organization, then DES may adjust the basis to effect an equitable distribution.

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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 28, 2020	/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 28, 2020	/s/ James R. Chapman
	James R. Chapman Executive Vice President and Chief Financial Officer

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, 2019 (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, 2019, and for the period then ended.

/s/ Diane Leopold

Diane Leopold
Chief Executive Officer

February 28, 2020

/s/ James R. Chapman

James R. Chapman
Executive Vice President and
Chief Financial Officer
February 28, 2020

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

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,	2019			2018			2017
(millions)
Current:
Federal	$	—		$	(16	)	$	(410	)
State		34			—			(18	)
Total current expense (benefit)		34			(16	)		(428	)
Deferred:
Federal
Taxes before operating loss carryforwards, investment tax credits and tax reform		(90	)		(216	)		262
2017 Tax Reform Act impact		—			(176	)		(1	)
Tax utilization expense of operating loss carryforwards		102			46			—
State		(57	)		(52	)		(2	)
Total deferred expense (benefit)		(45	)		(398	)		259
Investment tax credit-amortization		(1	)		(2	)		(2	)
Total income tax expense (benefit)	$	(12	)	$	(416	)	$	(171	)

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,	2019			2018			2017
U.S. statutory rate		21.0	%		21.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		3.9			3.8			2.3
State investment tax credits		—			0.3			1.5
AFUDC - equity		—			0.2			1.5
Amortization of federal investment tax credits		0.1			0.2			0.6
Production tax credits		0.4			0.9			2.3
Domestic production activities deduction		—			—			5.2
Reversal of excess deferred income taxes		(1.4	)		—			—
Federal legislative change		—			17.5			0.3
NND Project impairment		(2.4	)		(2.3	)		—
Write-off of regulatory asset		(15.8	)		—			—
Changes in unrecognized tax benefits		(5.1	)		—			—
Other		0.2			(0.2	)		1.2
Effective tax rate		0.9	%		41.4	%		49.9	%

Schedule of Deferred Income Taxes

DESC’s deferred income taxes consist of the following:

At December 31,	2019			2018
(millions)
Deferred income taxes:
Total deferred income tax assets	$	1,258		$	971
Total deferred income tax liabilities		1,868			1,960
Total net deferred income tax liabilities	$	610		$	989
Total deferred income taxes:
Depreciation method and plant basis differences	$	1,007		$	998
Excess deferred income taxes		(231	)		(148	)
Unrecovered nuclear plant cost		553			584
DESC rate refund		(169	)		(1	)
Toshiba settlement		(219	)		(231	)
Nuclear decommissioning		(43	)		(9	)
Deferred state income taxes		200			296
Federal benefit of deferred state income taxes		(42	)		(62	)
Deferred fuel, purchased energy and gas costs		7			1
Pension benefits		46			46
Other postretirement benefits		(35	)		(35	)
Loss and credit carryforwards		(391	)		(520	)
Other		(73	)		70
Total net deferred income tax liabilities	$	610		$	989
Deferred Investment Tax Credits-Regulated Operations		19			19
Total Deferred Taxes and Deferred Investment Tax Credits	$	629		$	1,008

Summary of Tax Credit Carryforwards

At December 31, 2019, DESC had the following deductible loss and credit carryforwards:

(millions)	Deductible Amount		Deferred Tax Asset		Expiration Period
Federal losses	$	1,207	$	254	2037
Federal production and other credits		—		38	2031-2038
State losses		1,849		92	2037
State investment and other credits		—		31	2026-2031
Total	$	3,056	$	415

Schedule of Unrecognized Tax Benefits Roll Forward

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

(millions)	2019			2018		2017
Balance at January 1	$	106		$	98	$	350
Increases-prior period positions		76			8		—
Decreases-prior period positions		(53	)		—		(273	)
Increases-current period positions		3			—		21
Balance at December 31	$	132		$	106	$	98

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Employee Benefit Plans and Equity Compensation Plan (Tables)

12 Months Ended

Dec. 31, 2019

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)	2019			2018			2019			2018
Benefit obligation, January 1	$	732		$	793		$	187		$	217
Service cost		15			17			3			4
Interest cost		28			29			9			8
Plan participants’ contributions		—			—			1			1
Actuarial (gain) loss		47			(46	)		22			(31	)
Benefits paid		(21	)		(19	)		(13	)		(11	)
Settlements		(80	)		(42	)		—			—
Curtailment		6			—			3			—
Amounts funded to parent		—			—			2			(1	)
Benefit obligation, December 31	$	727		$	732		$	214		$	187

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
	2019			2018			2019			2018
Annual discount rate used to determine benefit obligation		3.47	%		4.35	%		3.52	%		4.38	%
Assumed annual rate of future salary increases for projected    benefit obligation		3.00	%		3.00	%	N/A			N/A

Schedule of Net Funded Status

	Pension Benefits						Other Postretirement Benefits
At December 31,	2019			2018			2019			2018
(millions)
Fair value of plan assets	$	725		$	676		$	—		$	—
Benefit obligation		727			732			214			187
Funded status	$	(2	)	$	(56	)	$	(214	)	$	(187	)

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,	2019			2018			2019			2018
(millions)
Current liability	$	—		$	—		$	(13	)	$	(11	)
Noncurrent liability		(2	)		(56	)		(201	)		(177	)

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,	2019		2018		2019		2018
(millions)
Net actuarial loss	$	2	$	3	$	2	$	1

Schedule of Amounts Recognized in Regulatory Assets

Amounts recognized in regulatory assets were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2019		2018		2019		2018
(millions)
Net actuarial loss	$	125	$	202	$	29	$	9
Prior service cost		—		1		—		—
Total	$	125	$	203	$	29	$	9

Schedule of Changes in Fair Value of Plan Assets

Changes in Fair Value of Plan Assets

Pension Benefits
(millions)	2019			2018
Fair value of plan assets, January 1	$	677		$	781
Actual return (loss) on plan assets		149			(43	)
Benefits paid		(21	)		(61	)
Settlements		(80	)		—
Fair value of plan assets, December 31	$	725		$	677

Schedule of Allocation of Plan Assets

The pension plan asset allocation at December 31, 2019 and 2018 and the target allocation for 2020 are as follows:

	Percentage of Plan Assets
	Target Allocation			December 31,
Asset Category	2020			2019			2018
Equity Securities		45	%		64	%		55	%
Fixed Income		50	%		35	%		34	%
Cash		5	%		1	%		—	%
Hedge Funds		—	%		—	%		11	%

Schedule of Fair Value Measurements By Category

At December 31, 2019 and 2018, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

At December 31,	2019		2018
(millions)
Investments with fair value measure at Level 2:
Mutual funds	$	152	$	99
Short-term investment vehicles		—		19
US Treasury securities		3		7
Corporate debt instruments		233		86
Government and other debt instruments		26		16
Total assets in the fair value hierarchy		414		227
Investments at net asset value:
Common collective trust		311		373
Joint venture interests		—		77
Total investments	$	725	$	677

Schedule of Expected Benefit Payments

Expected Benefit Payments

(millions)	Pension Benefits		Other Postretirement Benefits
2020	$	70	$	13
2021		37		13
2022		48		13
2023		46		13
2024		46		13
2025 - 2029		210		69

Components of Net Periodic Benefit Cost

Components of Net Periodic Benefit Cost

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2019			2018			2017			2019		2018		2017
(millions)
Service cost	$	15		$	17		$	18		$	3	$	4	$	4
Interest cost		28			29			32			9		8		9
Expected return on assets		(40	)		(48	)		(46	)		—		—		—
Prior service cost amortization		—			—			1			—		—		—
Amortization of actuarial losses		11			11			14			—		—		1
Settlement loss		16			—			—			—		—		—
Curtailment		6			—			—			3		—		—
Net periodic benefit cost	$	36		$	9		$	19		$	15	$	12	$	14

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,	2019			2018		2017		2019		2018			2017
(millions)
Current year actuarial (gain) loss	$	(1	)	$	1	$	—	$	1	$	(1	)	$	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,	2019			2018			2017			2019		2018			2017
(millions)
Current year actuarial (gain) loss	$	(51	)	$	41		$	(25	)	$	20	$	(26	)	$	7
Amortization of actuarial losses		(11	)		(10	)		(13	)		—		(1	)		—
Amortization of prior service cost		—			—			(1	)		—		—			—
Settlement loss		(16	)		—			—			—		—			—
Total recognized in regulatory assets	$	(78	)	$	31		$	(39	)	$	20	$	(27	)	$	7

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,	2019			2018			2017			2019			2018			2017
Discount rate	3.57/4.38%				3.71	%		4.22	%	4.08/4.41%				3.74	%		4.30	%
Expected return on plan assets		7.00	%		7.00	%		7.25	%	n/a			n/a			n/a
Rate of compensation increase		3.00	%		3.00	%		3.00	%	n/a			n/a			n/a
Health care cost trend rate											6.60	%		7.00	%		6.60	%
Ultimate health care cost trend rate											5.00	%		5.00	%		5.00	%
Year achieved										2023			2023			2021

Schedule of Amounts in Regulatory Assets to be Recognized Over the Next Fiscal Year

The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2020 are as follows:

(millions)	Pension Benefits		Other Postretirement Benefits
Actuarial loss	$	6	$	1

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Quarterly Financial Information (Schedule of Quarterly Financial Information) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Operating revenue	$ 771	$ 795	$ 698	$ (335)	$ 689	$ 739	$ 632	$ 702
Operating income (loss)	(76)	261	17	(1,143)	(1,271)	212	107	121	$ (941)	$ (831)	$ (83)
Total comprehensive income (loss)	(191)	143	(70)	(1,103)	(852)	104	31	128	$ (1,221)	$ (588)	$ (172)
Comprehensive income (loss) available (attributable) to common shareholder	$ (195)	$ 143	$ (78)	$ (1,109)	$ (861)	$ 98	$ 26	$ 124

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Income Taxes

12 Months Ended

Dec. 31, 2019

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.

The 2017 Tax Reform Act included a broad range of tax reform provisions. The 2017 Tax Reform Act reduced the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. At the date of enactment, deferred tax assets and liabilities were remeasured based upon the new 21% enacted tax rate expected to apply when temporary differences are realized or settled. The specific provisions related to regulated public utilities in the 2017 Tax Reform Act generally allow for the continued deductibility of interest expense, changed the tax depreciation of certain property acquired after September 27, 2017, and continued certain rate normalization requirements for accelerated depreciation benefits.

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. The 2017 Tax Reform Act included provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential sharing of other deferred taxes will be determined by our regulators. See Note 3 for more information.

DESC has completed the accounting for the effects of the 2017 Tax Reform Act, although changes could occur as additional guidance is issued and finalized, particularly as it relates to the deductibility of interest expense in consolidated groups such as Dominion Energy. In addition, the major states in which DESC operates have addressed conformity with some or all of the provisions of the 2017 Tax Reform Act, although they may have modified certain provisions.

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

Year Ended December 31,	2019			2018			2017
(millions)
Current:
Federal	$	—		$	(16	)	$	(410	)
State		34			—			(18	)
Total current expense (benefit)		34			(16	)		(428	)
Deferred:
Federal
Taxes before operating loss carryforwards, investment tax credits and tax reform		(90	)		(216	)		262
2017 Tax Reform Act impact		—			(176	)		(1	)
Tax utilization expense of operating loss carryforwards		102			46			—
State		(57	)		(52	)		(2	)
Total deferred expense (benefit)		(45	)		(398	)		259
Investment tax credit-amortization		(1	)		(2	)		(2	)
Total income tax expense (benefit)	$	(12	)	$	(416	)	$	(171	)

The 2017 Tax Reform Act reduced the statutory federal income tax rate to 21% beginning in January 2018. Accordingly, current and deferred income taxes are recorded at the new 21% rate.

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 SCANA Energy Marketing, Inc.’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,	2019			2018			2017
U.S. statutory rate		21.0	%		21.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		3.9			3.8			2.3
State investment tax credits		—			0.3			1.5
AFUDC - equity		—			0.2			1.5
Amortization of federal investment tax credits		0.1			0.2			0.6
Production tax credits		0.4			0.9			2.3
Domestic production activities deduction		—			—			5.2
Reversal of excess deferred income taxes		(1.4	)		—			—
Federal legislative change		—			17.5			0.3
NND Project impairment		(2.4	)		(2.3	)		—
Write-off of regulatory asset		(15.8	)		—			—
Changes in unrecognized tax benefits		(5.1	)		—			—
Other		0.2			(0.2	)		1.2
Effective tax rate		0.9	%		41.4	%		49.9	%

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 2019, and changes in estimates of amounts probable of collection from or return to customers. The reversal of these excess deferred income taxes will impact the effective tax rate, and may ultimately impact rates charged to customers. See Note 3 for current year developments.

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.

In connection with the remeasurement of federal deferred income tax assets and liabilities resulting from the lower federal income tax rate, DESC recorded a deferred income tax benefit of approximately $1 million in the statements of operations for the year ended December 31, 2017. As a result of the filing of the 2017 tax return in the fourth quarter of 2018 and the additional impairment charges recorded in 2018, adjustments to such excess deferred income taxes of approximately $176 million were recorded. Also in connection with the additional impairment charges, DESC recorded additional adjustments to deferred income taxes in the aggregate amount of approximately $23 million. In addition, certain states in which DESC operates may or may not conform to some or all of the provisions of the 2017 Tax Reform Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to results of operations and cash flows, and adjustments to tax-related assets and liabilities, and such impacts or adjustments could be material.

DESC’s deferred income taxes consist of the following:

At December 31,	2019			2018
(millions)
Deferred income taxes:
Total deferred income tax assets	$	1,258		$	971
Total deferred income tax liabilities		1,868			1,960
Total net deferred income tax liabilities	$	610		$	989
Total deferred income taxes:
Depreciation method and plant basis differences	$	1,007		$	998
Excess deferred income taxes		(231	)		(148	)
Unrecovered nuclear plant cost		553			584
DESC rate refund		(169	)		(1	)
Toshiba settlement		(219	)		(231	)
Nuclear decommissioning		(43	)		(9	)
Deferred state income taxes		200			296
Federal benefit of deferred state income taxes		(42	)		(62	)
Deferred fuel, purchased energy and gas costs		7			1
Pension benefits		46			46
Other postretirement benefits		(35	)		(35	)
Loss and credit carryforwards		(391	)		(520	)
Other		(73	)		70
Total net deferred income tax liabilities	$	610		$	989
Deferred Investment Tax Credits-Regulated Operations		19			19
Total Deferred Taxes and Deferred Investment Tax Credits	$	629		$	1,008

At December 31, 2019, DESC had the following deductible loss and credit carryforwards:

(millions)	Deductible Amount		Deferred Tax Asset		Expiration Period
Federal losses	$	1,207	$	254	2037
Federal production and other credits		—		38	2031-2038
State losses		1,849		92	2037
State investment and other credits		—		31	2026-2031
Total	$	3,056	$	415

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

(millions)	2019			2018		2017
Balance at January 1	$	106		$	98	$	350
Increases-prior period positions		76			8		—
Decreases-prior period positions		(53	)		—		(273	)
Increases-current period positions		3			—		21
Balance at December 31	$	132		$	106	$	98

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 2010, except for certain outstanding refund claims. The IRS has completed examinations of DESC’s federal returns through 2012. The IRS is currently examining DESC’s federal returns from 2013 through 2017. With few exceptions, DESC is no longer subject to state and local income tax examinations by tax authorities for years prior to 2012.

It is reasonably possible that these unrecognized tax benefits may decrease by $65 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 up to $4 million. Otherwise, with regard to 2019 and prior years, DESC cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2020.

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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Rate and Other Regulatory Matters

12 Months Ended

Dec. 31, 2019

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 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 Loss during the third quarter of 2019, to remove previously recorded reserves.

2017 Tax Reform Act

The 2017 Tax Reform Act lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the South Carolina Commission has required DESC to track and defer impacts related to the 2017 Tax Reform Act arising from customer rates in 2018 as subject to refund. In addition, as further discussed under Regulatory Assets and Regulatory Liabilities below, certain accumulated deferred income taxes contained within regulatory liabilities represent excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the 2017 Tax Reform Act. Certain of these amounts are protected under normalization rules and will be amortized at the weighted average tax rate used to build the reserves over the remaining regulatory life of the property. Other, non-plant related regulatory liabilities will be amortized to the benefit of customers, as instructed by our regulators.

As part of the SCANA Combination, the South Carolina Commission approved credits of approximately $100 million by DESC for the impact of the lower federal tax rate resulting from the 2017 Tax Reform Act. The credits included amounts which had been collected through customer rates in 2018 and January 2019 and also included the effects of the amortization of certain excess deferred taxes during the same period. These credits were included in bills rendered on and after the first billing cycle of February 2019. In addition, the South Carolina Commission approved the implementation of a tax rider whereby amounts collected though customer rates effectively would be reduced and excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the 2017 Tax Reform Act will be amortized to the benefit of customers. This tax rider reduced base rates to customers by approximately $63 million in 2019 and is expected to reduce these rates by $67 million in 2020. Unamortized excess deferred income taxes that remain at the end of 2020 will be considered in future rate proceedings.

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 will make such changes to its formula rate as part of its annual update in May 2020.

In January 2020, GENCO filed to modify its formula rate to incorporate a mechanism to decrease or increase its income tax allowances by any excess deferred income taxes resulting from the 2017 Tax Reform Act, and future changes in tax laws. These modifications are expected to decrease charges to DESC for the power it purchases from GENCO.

Electric – BLRA

In July 2018, the South Carolina Commission issued orders implementing a legislatively-mandated temporary reduction in revenues that could be collected by DESC from customers under the BLRA. These orders reduced the portion of DESC’s retail electric rates associated with the NND Project from approximately 18% of the average residential electric customer's bill to approximately 3%, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. As a result, in 2018 DESC recorded a charge of $109 million ($82 million after-tax) to operating revenues in DESC’s Consolidated Statements of Comprehensive Loss. The temporary rate reduction remained in effect until February 2019 when rates pursuant to the SCANA Merger Approval Order became effective.

Other Regulatory Matters

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 2020, DESC filed with the South Carolina Commission a proposal to decrease the total fuel cost component of retail electric rates. DESC’s proposed decrease would reduce annual base fuel component recoveries by approximately $44 million and is projected to return to customers the existing over-collected balance while recovering DESC’s current base fuel costs over the 12-month period beginning with the first billing cycle of May 2020. In addition, DESC proposed an increase to its variable environmental and DER components. This matter is pending.

In April 2019, the South Carolina Commission approved DESC’s proposal to decrease the total fuel cost component of retail electric rates. DESC's proposal included maintaining its base fuel component at the current level to produce a projected under-recovered balance of $35 million at the end of the 12-month period beginning with the first billing cycle of May 2019 and requested carrying costs for any base fuel under-collected balances, should they occur. DESC also proposed reducing its variable environmental component and maintaining or reducing its DER components. Changes in rates became effective beginning with the first billing cycle of May 2019.

In April 2018, the South Carolina Commission approved DESC’s proposal to increase the total fuel cost component of retail electric rates. Petitions for rehearing and reconsideration were filed by various parties, and on October 30, 2018, the South Carolina Commission issued an order granting one such petition related to DESC supplying certain information as in previous years. The other petitions were denied, and certain parties have appealed the decision to deny their petitions to the South Carolina Supreme Court. These appeals primarily relate to avoided cost rates that DESC is required to pay to solar energy developers, and these appeals are pending. DESC cannot predict the outcome of these matters.

Electric Transmission Projects

In 2020, DESC expects to begin several electric transmission projects in connection with two new nuclear plants under development by Southern. These transmission projects are required to be in place prior to these plants beginning operations to maintain reliability. DESC anticipates the projects to go into service in phases, costing approximately $75 million in aggregate. In February 2020, DESC filed an application with the South Carolina Commission requesting approval to construct and operate 28 miles of 230 kV transmission lines in Aiken County, South Carolina estimated to cost approximately $30 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 2019, DESC filed an application with the South Carolina Commission seeking approval to recover $30 million of costs incurred and net lost future revenues associated with these programs, along with an incentive to invest in such programs. In April 2019, the South Carolina Commission approved the request for the rate year beginning with the first billing cycle of May 2019.

In January 2020, DESC submitted its annual DSM programs filing to the South Carolina Commission. If approved the filing would allow recovery of approximately $40 million of costs and net lost revenues associated with DSM 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. No adjustment was made in 2019. In 2020, DESC requested that the South Carolina Commission approve an adjustment to this rider to decrease annual revenue by approximately $11 million. This matter is pending.

Gas

In June 2019, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 2019 with a total revenue requirement of $437 million. This represents a $7 million overall increase to its natural gas rates under the terms of the RSA effective for the rate year beginning November 2019. In October 2019, the South Carolina Commission approved a total revenue requirement of $436 million effective with the first billing cycle of November 2019.

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,	2019		2018
(millions)
Regulatory assets:
NND Project costs(1)	$	138		127
Deferred employee benefit plan costs(2)		13		16
Other unrecovered plant(3)		14		14
DSM programs(4)		17		14
AROs(5)		28		—
Cost of fuel under-collections(6)		13		13
Other		48		40
Regulatory assets - current		271		224
NND Project costs(1)		2,503		2,641
AROs(5)		293		380
Cost of reacquired debt(7)(8)		259		14
Deferred employee benefit plan costs(2)		196		256
Deferred losses on interest rate derivatives(9)		305		442
Other unrecovered plant(3)		69		79
DSM programs(4)		54		51
Environmental remediation costs(10)		22		24
Deferred storm damage costs(11)		44		35
Deferred transmission operating costs(12)		37		15
Other(13)		110		123
Regulatory assets - noncurrent		3,892		4,060
Total regulatory assets	$	4,163	$	4,284
Regulatory liabilities:
Monetization of guaranty settlement(14)	$	67		61
Income taxes refundable through future rates(15)		16		52
Reserve for refunds to electric utility customers(16)		143		—
Other		30		13
Regulatory liabilities - current		256		126
Monetization of guaranty settlement(14)		970		1,037
Income taxes refundable through future rates(15)		948		607
Asset removal costs(17)		552		541
Deferred gains on interest rate derivatives(9)		71		75
Reserve for refunds to electric utility customers(16)		656		—
Other		13		4
Regulatory liabilities – noncurrent		3,210		2,264
Total regulatory liabilities	$	3,466	$	2,390

(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 over the units' previous estimated remaining useful lives through 2025. 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 five 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-collected from customers pursuant to the cost of fuel components approved by the South Carolina Commission.

(7) Costs of the reacquisition of debt are deferred and amortized as interest expense over the would-be remaining life of the reacquired debt or over the life of the replacement debt if refinanced. The reacquired debt had a weighted-average life of approximately 26 years as of December 31, 2019.

(8)   During 2019, DESC purchased certain of its first mortgage bonds as discussed in Note 6. As a result of these transactions, DESC incurred net costs, including write-offs of unamortized discount, premium and debt issuance costs, of $270 million.

(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 16 years. See Note 12 for more information.

(11) Represents storm restoration costs for which DESC expects to receive future recovery through customer rates.

(12) Includes deferred depreciation and property taxes associated with certain transmission assets for which DESC expects recovery from customers through future rates. See Note 12 for more information.

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

(14) 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.

(15) 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.

(16) 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 in connection with the SCANA Merger Approval Order. See Note 12 for more information.

(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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Employee Benefit Plans and Equity Compensation Plan

12 Months Ended

Dec. 31, 2019

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 will continue to accrue through December 31, 2020, after which date no benefits will be accrued except that participants under the cash balance formula will 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 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. The voluntary retirement program will not compromise safety or DESC’s ability to comply with applicable laws and regulations. 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)	2019			2018			2019			2018
Benefit obligation, January 1	$	732		$	793		$	187		$	217
Service cost		15			17			3			4
Interest cost		28			29			9			8
Plan participants’ contributions		—			—			1			1
Actuarial (gain) loss		47			(46	)		22			(31	)
Benefits paid		(21	)		(19	)		(13	)		(11	)
Settlements		(80	)		(42	)		—			—
Curtailment		6			—			3			—
Amounts funded to parent		—			—			2			(1	)
Benefit obligation, December 31	$	727		$	732		$	214		$	187

The accumulated benefit obligation for pension benefits for DESC was $711 million at the end of 2019 and $714 million at the end of 2018. 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
	2019			2018			2019			2018
Annual discount rate used to determine benefit obligation		3.47	%		4.35	%		3.52	%		4.38	%
Assumed annual rate of future salary increases for projected    benefit obligation		3.00	%		3.00	%	N/A			N/A

A 6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2019. The rate was assumed to decrease gradually to 5.0% for 2023 and to remain at that level thereafter.

A one percent increase in the assumed health care cost trend rate for DESC would increase the postretirement benefit obligation by less than $1 million at December 31, 2019 and by $1 million at December 31, 2018. A one percent decrease in the assumed health care cost trend rate for DESC would decrease the postretirement benefit obligation by less than $1 million at December 31, 2019 and by $1 million at December 31, 2018.

Funded Status

	Pension Benefits						Other Postretirement Benefits
At December 31,	2019			2018			2019			2018
(millions)
Fair value of plan assets	$	725		$	676		$	—		$	—
Benefit obligation		727			732			214			187
Funded status	$	(2	)	$	(56	)	$	(214	)	$	(187	)

Amounts recognized on the consolidated balance sheets were as follows:

	Pension Benefits						Other Postretirement Benefits
At December 31,	2019			2018			2019			2018
(millions)
Current liability	$	—		$	—		$	(13	)	$	(11	)
Noncurrent liability		(2	)		(56	)		(201	)		(177	)

Amounts recognized in accumulated other comprehensive loss were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2019		2018		2019		2018
(millions)
Net actuarial loss	$	2	$	3	$	2	$	1

Amounts recognized in regulatory assets were as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2019		2018		2019		2018
(millions)
Net actuarial loss	$	125	$	202	$	29	$	9
Prior service cost		—		1		—		—
Total	$	125	$	203	$	29	$	9

In connection with the joint ownership of Summer, costs related to pensions attributable to Santee Cooper as of December 31, 2019 and 2018 totaled $19 million and $25 million, respectively, and were recorded within deferred debits. Costs related to other postretirement benefits attributable to Santee Cooper as of December 31, 2019 and 2018 totaled $15 million and $12 million, respectively, and was recorded within deferred debits.

Changes in Fair Value of Plan Assets

Pension Benefits
(millions)	2019			2018
Fair value of plan assets, January 1	$	677		$	781
Actual return (loss) on plan assets		149			(43	)
Benefits paid		(21	)		(61	)
Settlements		(80	)		—
Fair value of plan assets, December 31	$	725		$	677

Investment Policies and Strategies

The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the obligations of the pension plan, (2) overseeing the plan's investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and liabilities, and overall risk associated with assets as compared to liabilities, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. DESC uses a dynamic investment strategy for the management of the pension plan assets. This strategy will lead to a reduction in equities and an increase in long duration fixed income allocations over time with the intention of reducing volatility of funded status and pension costs.

The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, levels of diversification, investment managers and performance expectations. The total portfolio is constructed and maintained to provide prudent diversification with regard to the concentration of holdings in individual issues, corporations, or industries.

Transactions involving certain types of investments are prohibited. These include, except where utilized by a hedge fund manager, any form of private equity; commodities or commodity contracts (except for unleveraged stock or bond index futures and currency futures and options); ownership of real estate in any form other than publicly traded securities; short sales, warrants or margin transactions, or any leveraged investments; and natural resource properties. Investments made for the purpose of engaging in speculative trading are also prohibited.

The pension plan asset allocation at December 31, 2019 and 2018 and the target allocation for 2020 are as follows:

	Percentage of Plan Assets
	Target Allocation			December 31,
Asset Category	2020			2019			2018
Equity Securities		45	%		64	%		55	%
Fixed Income		50	%		35	%		34	%
Cash		5	%		1	%		—	%
Hedge Funds		—	%		—	%		11	%

For 2020, the expected long-term rate of return on assets will be 7%. In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, considers the expected active and passive returns across various asset classes and assumes the target allocation is achieved. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment strategy described previously.

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, 2019 and 2018, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

At December 31,	2019		2018
(millions)
Investments with fair value measure at Level 2:
Mutual funds	$	152	$	99
Short-term investment vehicles		—		19
US Treasury securities		3		7
Corporate debt instruments		233		86
Government and other debt instruments		26		16
Total assets in the fair value hierarchy		414		227
Investments at net asset value:
Common collective trust		311		373
Joint venture interests		—		77
Total investments	$	725	$	677

For all periods presented, assets with fair value measurements classified as Level 1 were insignificant, and there were no assets with fair value measurements classified as Level 3. There were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during 2019 or 2018.

Mutual funds held by the plan are open-end mutual funds registered with the SEC. The price of the mutual funds' shares is based on its NAV, which is determined by dividing the total value of portfolio investments, less any liabilities, by the total number of shares outstanding. 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. US 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. 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
2020	$	70	$	13
2021		37		13
2022		48		13
2023		46		13
2024		46		13
2025 - 2029		210		69

Pension Plan Contributions

The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and as a result of closing the plan to new entrants and freezing benefit accruals at the end of 2023, no significant contributions to the pension trust are expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply.

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,	2019			2018			2017			2019		2018		2017
(millions)
Service cost	$	15		$	17		$	18		$	3	$	4	$	4
Interest cost		28			29			32			9		8		9
Expected return on assets		(40	)		(48	)		(46	)		—		—		—
Prior service cost amortization		—			—			1			—		—		—
Amortization of actuarial losses		11			11			14			—		—		1
Settlement loss		16			—			—			—		—		—
Curtailment		6			—			—			3		—		—
Net periodic benefit cost	$	36		$	9		$	19		$	15	$	12	$	14

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,	2019			2018		2017		2019		2018			2017
(millions)
Current year actuarial (gain) loss	$	(1	)	$	1	$	—	$	1	$	(1	)	$	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,	2019			2018			2017			2019		2018			2017
(millions)
Current year actuarial (gain) loss	$	(51	)	$	41		$	(25	)	$	20	$	(26	)	$	7
Amortization of actuarial losses		(11	)		(10	)		(13	)		—		(1	)		—
Amortization of prior service cost		—			—			(1	)		—		—			—
Settlement loss		(16	)		—			—			—		—			—
Total recognized in regulatory assets	$	(78	)	$	31		$	(39	)	$	20	$	(27	)	$	7

Significant assumptions used in determining net periodic benefit cost:

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2019			2018			2017			2019			2018			2017
Discount rate	3.57/4.38%				3.71	%		4.22	%	4.08/4.41%				3.74	%		4.30	%
Expected return on plan assets		7.00	%		7.00	%		7.25	%	n/a			n/a			n/a
Rate of compensation increase		3.00	%		3.00	%		3.00	%	n/a			n/a			n/a
Health care cost trend rate											6.60	%		7.00	%		6.60	%
Ultimate health care cost trend rate											5.00	%		5.00	%		5.00	%
Year achieved										2023			2023			2021

The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2020 are as follows:

(millions)	Pension Benefits		Other Postretirement Benefits
Actuarial loss	$	6	$	1

Other postretirement benefit costs are subject to annual per capita limits pursuant to the plan's design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is not significant.

401(k) Retirement Savings Plan

SCANA sponsors a defined contribution plan in which eligible employees may defer up to 75% of eligible earnings subject to certain limits and may diversify their investments. DESC participates in this plan. Contributions are matched 100% up to 6% of an employee’s eligible earnings. The matching contributions made by DESC totaled $14 million in 2019, $20 million in 2018 and $23 million in 2017. Employee deferrals, matching contributions, and earnings on all contributions are fully vested and non-forfeitable at all times.

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
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	$ (51)	$ 41	$ (25)
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax	(11)	(10)	(13)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax	0	0	(1)
Regulatory assets, settlement loss, pension and other postretirement benefit plans, net of tax	(16)	0	0
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax	(78)	31	(39)
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	20	(26)	7
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax	0	(1)	0
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax	$ 20	$ (27)	$ 7

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Employee Benefit Plans and Equity Compensation Plan (Funded Status) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 725	$ 677	$ 781
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	725	676
Benefit obligation	727	732	793
Funded status	(2)	(56)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	214	187	$ 217
Funded status	$ (214)	$ (187)

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Employee Benefit Plans and Equity Compensation Plan (Amounts Recognized in Accumulated Other Comprehensive Loss) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ 2	$ 3
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ 2	$ 1

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]	$ (1)	$ 113	$ (176)
Interest Charges [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]	(1)	(2)	(3)
Other Income [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]	0	115	0
Impairment Loss [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]	$ 0	$ 0	$ (173)

[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 Loss.

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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, 2019	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Beginning balance		$ 541	$ 529
Liabilities settled		(29)	(15)
Accretion expense		23	23
Revisions in estimated cash flows	[1]	(46)	4
Ending balance		$ 489	$ 541

[1] The decrease in 2019 reflects a change in the estimated timing of cash flows for interim pipeline replacements and DOE recoveries.

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Employee Benefit Plans (Schedule of Fair Value Measurements By Category) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Total assets in the fair value hierarchy	$ 725	$ 677	$ 781
Common collective trust	311	373
Joint venture interests	0	77
Total investments	725	677
Fair Value, Inputs, Level 2
Defined Benefit Plan Disclosure [Line Items]
Total assets in the fair value hierarchy	414	227
Fair Value, Inputs, Level 2 | Mutual Funds
Defined Benefit Plan Disclosure [Line Items]
Total assets in the fair value hierarchy	152	99
Fair Value, Inputs, Level 2 | Short-term Investments
Defined Benefit Plan Disclosure [Line Items]
Total assets in the fair value hierarchy	0	19
Fair Value, Inputs, Level 2 | US Treasury securities
Defined Benefit Plan Disclosure [Line Items]
Total assets in the fair value hierarchy	3	7
Fair Value, Inputs, Level 2 | Corporate Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total assets in the fair value hierarchy	233	86
Fair Value, Inputs, Level 2 | Government and Other Debt Instruments
Defined Benefit Plan Disclosure [Line Items]
Total assets in the fair value hierarchy	$ 26	$ 16

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Long-Term and Short-Term Debt (Narrative) (Detail) - USD ($)			1 Months Ended		12 Months Ended
		Jan. 31, 2020	May 31, 2019	Apr. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Mar. 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					6.88%
Redemption of remaining principal outstanding plus accrued interest					$ 1,890,000,000	$ 825,000,000	$ 12,000,000
Equity capital contribution returned to parent					$ 20,000,000	$ 0	0
Line of credit facility maturity date					2023-03
Weighted average interest rate, outstanding commercial paper						3.82%
Commercial paper borrowing limit				$ 2,200,000,000
Interest charges	[1]				$ 260,000,000	$ 303,000,000	$ 288,000,000
Interest income from money pool transactions					8,000,000	4,000,000
Interest expense from money pool transactions					8,000,000	4,000,000
Money pool borrowings due to affiliates					219,000,000	282,000,000
Investments due from affiliates					9,000,000	$ 353,000,000
Subsequent Event
Debt Instrument [Line Items]
Short term borrowing maturity period		2 years
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					355,000,000
Interest charges					3,000,000
Current Joint Revolving Credit Facility
Debt Instrument [Line Items]
Facility limit					1,000,000,000
Current Joint Revolving Credit Facility | Dominion Energy
Debt Instrument [Line Items]
Facility limit								$ 6,000,000,000.0
Line of Credit Facility
Debt Instrument [Line Items]
Facility limit					500,000,000
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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Equity (Narrative) (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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	$ 838	$ 24	$ 3
Retained earnings, restricted	115	$ 115
Dominion Energy
Class Of Stock [Line Items]
Contributions from SCANA	$ 835

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Leases (Schedule Of Lease Assets and Liabilities Recorded in Consolidated Balance Sheets) (Parenthetical) (Detail) $ in Millions	Dec. 31, 2019 USD ($)
Utility Plant, Net
Finance lease assets, accumulated amortization	$ 24

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Income Taxes (Reconciliation of Unrecognized Tax Benefits Roll Forward) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Balance at January 1	$ 106	$ 98	$ 350
Increases-prior period positions	76	8	0
Decreases-prior period positions	(53)	0	(273)
Increases-current period positions	3	0	21
Balance at December 31	$ 132	$ 106	$ 98

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
Current:
Federal	$ 0	$ (16)	$ (410)
State	34	0	(18)
Total current expense (benefit)	34	(16)	(428)
Deferred:
Taxes before operating loss carryforwards, investment tax credits and tax reform	(90)	(216)	262
2017 Tax Reform Act impact	0	(176)	(1)
Tax utilization expense of operating loss carryforwards	102	46	0
State	(57)	(52)	(2)
Total deferred expense (benefit)	(45)	(398)	259
Investment tax credit-amortization	(1)	(2)	(2)
Total income tax expense (benefit)	$ (12)	$ (416)	$ (171)

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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	Sep. 30, 2019 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, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2019 USD ($) Product	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Feb. 28, 2020 USD ($)
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 MGP decommissioned sites that contain residues of byproduct chemicals | Product												4
Estimated environmental remediation activities at MGP sites												$ 10,000,000
Estimated increase in remediation costs for Congaree River site												8,000,000
Environmental remediation costs recognized in regulatory assets												23,000,000
Number of CCR landfills facilities subject to final rule | Facility	3
Impairment loss, NND Project										$ 1,400,000,000	$ 4,000,000			$ 1,100,000,000
Impairment loss, NND Project, after-tax										870,000,000	$ 3,000,000			690,000,000
Maximum amount of capital cost recovery related to the NND Project										2,800,000,000
Impairment of assets and other charges									$ 105,000,000			576,000,000	$ 1,376,000,000	$ 1,118,000,000
Impairment of assets and other charges, after-tax									79,000,000
Customer refundable fees, alternative plan						$ 2,390,000,000				2,390,000,000		3,466,000,000	2,390,000,000
Regulatory liability for refunds to natural gas customers									2,000,000
Regulatory liability for refunds to natural gas customers, after tax									2,000,000
Regulatory asset impairment charges committed to forgo recovery									264,000,000
Tax charge related to regulatory assets committed to forgo recovery									198,000,000
Transmission assets related to BLRA capital costs												345,000,000
Transmission assets related to BLRA regulatory assets												37,000,000
Reserves for litigation and regulatory proceedings						11,000,000				11,000,000		492,000,000	11,000,000
Insurance receivables												6,000,000
Escrow amount						115,000,000				115,000,000			115,000,000
Proposed settlement payable by company					$ 100,000,000
Proportionate ownership share in project					100.00%		100.00%
Proposed assessment amount from SCDOR audit							$ 410,000,000
Contesting amount for filed liens in Fairfield country												285,000,000
Reduction of liens filed												$ 60,000,000
Percentage share of reduction of liens filed												55.00%
Energy payments under power purchase contracts						24,000,000				24,000,000		$ 37,000,000	24,000,000
Nuclear Insurance
Loss Contingencies [Line Items]
Maximum liability each nuclear plant is insured against												$ 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
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
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
Subsequent Event
Loss Contingencies [Line Items]
Proposed settlement payable by all															$ 520,000,000
Proposed settlement payable by company															$ 320,000,000
Maximum [Member] | Nuclear Insurance
Loss Contingencies [Line Items]
Maximum liability protection per nuclear incident amount												14,000,000,000.0
Amount that could be assessed for each licensed reactor												138,000,000
Amount that could be assessed for each licensed reactor per year												21,000,000
Dominion Energy South Carolina, Inc.
Loss Contingencies [Line Items]
Reduction of liens filed												33,000,000
DESC Summer | Maximum [Member] | Nuclear Insurance
Loss Contingencies [Line Items]
Amount that could be assessed for each licensed reactor												92,000,000
Amount that could be assessed for each licensed reactor per year												14,000,000
Impairment of Assets and Other Charges | Dominion Energy South Carolina, Inc.
Loss Contingencies [Line Items]
Impairment of assets and other charges												590,000,000
Impairment of assets and other charges, after-tax												$ 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				$ 2,000,000,000.0			$ 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				$ 42,000,000
DESC Ratepayer Case | Minimum [Member]
Loss Contingencies [Line Items]
Estimated aggregate fair value of certain real estate						60,000,000
DESC Ratepayer Case | Maximum [Member]
Loss Contingencies [Line Items]
Estimated aggregate fair value of certain real estate						$ 85,000,000
Wrongful Death Suit of Estate of Jose Larios | Dominion Energy South Carolina, Inc.
Loss Contingencies [Line Items]
Litigation settlement expense awarded			$ 19,000,000
NND Project
Loss Contingencies [Line Items]
Jointly owned utility plant, proportionate ownership share												55.00%
Carbon Regulations [Member]
Loss Contingencies [Line Items]
Significant emission rate per year CO2 equivalent | T								75,000

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Gain (loss) Reclassified from Deferred Accounts into Income		$ 0	$ (1)	$ (2)
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[1]	1	1	(2)
Interest Rate Contract [Member]
Derivative [Line Items]
Gain (loss) Reclassified from Deferred Accounts into Income	[2]	0	(1)	(2)
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[1],[2]	$ 1	$ 1	$ (2)

[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 Loss.

[2] Amounts recorded in DESC’s Consolidated Statements of Comprehensive Loss are classified in interest charges.

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Leases (Schedule of Maturity Analysis of Operating and Finance Lease Liabilities) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019
Operating Lease Liabilities, Payments Due [Abstract]
Maturity of operating lease liabilities, 2020	$ 4
Maturity of operating lease liabilities, 2021	3
Maturity of operating lease liabilities, 2022	2
Maturity of operating lease liabilities, 2023	2
Maturity of operating lease liabilities, 2024	1
Maturity of operating lease liabilities, after 2024	23
Maturity of operating lease liabilities, total undiscounted lease payments	35
Operating lease liabilities, present value adjustment	(12)
Present value of operating lease liabilities	23	$ 19
Finance Lease Liabilities, Payments, Due [Abstract]
Maturity of finance lease liabilities, 2020	8
Maturity of finance lease liabilities, 2021	7
Maturity of finance lease liabilities, 2022	5
Maturity of finance lease liabilities, 2023	4
Maturity of finance lease liabilities, 2024	2
Maturity of finance lease liabilities, after 2024	3
Maturity of finance lease liabilities, total undiscounted lease payments	29
Finance lease liabilities, present value adjustment	(2)
Present value of finance lease liabilities	$ 27

XML

Other Income (Expense), Net (Tables)

12 Months Ended

Dec. 31, 2019

Income Statement [Abstract]

Components of Other Income (Expense), Net

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

Year Ended December 31,	2019			2018			2017
(millions)
Revenues from contracts with customers	$	4		$	5		$	—
Other income		19			141			45
Other expense		(57	)		(28	)		(32	)
Allowance for equity funds used during construction		1			11			15
Other income (expense), net	$	(33	)	$	129		$	28

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Summary of Significant Accounting Policies (Schedule of Weighted Average Depreciation Rates) (Detail)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Generation
Composite weighted average depreciation rates for utility plant	2.50%	2.61%
Transmission
Composite weighted average depreciation rates for utility plant	2.57%	2.74%
Distribution
Composite weighted average depreciation rates for utility plant	2.41%	2.41%
Storage
Composite weighted average depreciation rates for utility plant	2.74%	2.71%
General and other
Composite weighted average depreciation rates for utility plant	3.22%	3.18%

XML

Affiliated and Related Party Transactions (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Purchases from affiliates, fuel used in electric generation	$ 43	$ 139	$ 127
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Ownership percentage	40.00%
Purchases from affiliates	$ 121	150	$ 162
Accounts payable to affiliates	2	7
Accounts receivable to affiliates	2	$ 7
Solar Affiliates [Member]
Related Party Transaction [Line Items]
Purchases from affiliates	234
Solar Affiliates [Member] | SCANA Combination
Related Party Transaction [Line Items]
Purchases from affiliates	8
Solar Affiliates [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Accounts payable to affiliates	1
Dominion Energy Carolina Gas Transmission LLC [Member]
Related Party Transaction [Line Items]
Purchases from affiliates	63
Accounts payable to affiliates	5
Purchases from affiliates, fuel used in electric generation	19
Purchases from affiliates, gas purchased for resale	44
Accounts receivable to affiliates	$ 1

XML

Operating Segments - Schedule of Segment Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Operating Revenue	[1]	$ 1,929	$ 2,762	$ 3,070
Depreciation and amortization		450	327	312
Interest charges	[1]	260	303	288
Income tax expense (benefit)		(12)	(416)	(171)
Comprehensive income (loss) available (attributable) to common shareholder		(1,239)	(613)	(185)
Capital expenditures		497	633	928
Total assets		14,301	14,963
Operating Segment | Dominion Energy South Carolina
Segment Reporting Information [Line Items]
Operating Revenue		2,937	2,763	3,070
Depreciation and amortization		452	327	312
Interest charges		247	306	288
Income tax expense (benefit)		163	98	257
Comprehensive income (loss) available (attributable) to common shareholder		408	304	505
Capital expenditures		497	633	928
Total assets		14,300	15,000
Operating Segment | Corporate and Other
Segment Reporting Information [Line Items]
Operating Revenue		(1,008)	(1)	0
Depreciation and amortization		(2)	0	0
Interest charges		13	(3)	0
Income tax expense (benefit)		(175)	(514)	(428)
Comprehensive income (loss) available (attributable) to common shareholder		(1,647)	(917)	(690)
Capital expenditures		0	0	$ 0
Total assets		$ 0	$ 0

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

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

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 VIE’s 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 VIE’s. 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. GENCO’s property (carrying value of $508 million) previously served as collateral for its long-term borrowings. 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, DESC purchases shared services from DESS, an affiliated VIE that provides accounting, legal, finance and certain administrative and technical services to all SCANA subsidiaries, including DESC. DESC has determined that it is not the primary beneficiary of DESS 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 2018 and 2017 Consolidated Financial Statements and Notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect DESC’s net income, total assets, liabilities, equity or cash flows.

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 4.3%, 7.0% and 3.9% for 2019, 2018 and 2017, 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:

	2019			2018
Generation		2.50	%		2.61	%
Transmission		2.57	%		2.74	%
Distribution		2.41	%		2.41	%
Storage		2.74	%		2.71	%
General and other		3.22	%		3.18	%

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 equipment and nuclear refueling outages are 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.

DESC is authorized to collect $18 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2019 and 2018, DESC incurred $10 million and $16 million, respectively, for turbine 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 scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which DESC was responsible totaled $2 million in 2019 and $29 million in 2018.

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 2016, 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 $646 million, stated in 2019 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. At December 31, 2019, there were no restricted cash and equivalent balances. At December 31, 2018, cash and cash equivalents at DESC included $115 million held in escrow pending a settlement which was contingent on the consummation of the merger with Dominion Energy. As such, DESC did not consider this amount to be restricted at December 31, 2018.

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 $114 million and $129 million at December 31, 2019 and 2018, 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 facilities at Summer. Such receivables represented approximately 10% of DESC’s accounts receivable balance at December 31, 2019.

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 was filed for SCANA, including DESC for years through 2018. Beginning in 2019, SCANA and DESC are part of Dominion Energy’s consolidated federal income tax return. 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 participated in intercompany tax sharing agreements with SCANA through the SCANA Combination, and currently participates in similar agreements with Dominion Energy. Under both SCANA and Dominion Energy’s tax sharing agreements, 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 SCANA or 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.

The 2017 Tax Reform Act included a broad range of tax reform provisions affecting DESC, including changes in corporate tax rates and business deductions. The 2017 Tax Reform Act reduces the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. Deferred tax assets and liabilities are classified as noncurrent in the Consolidated Balance Sheets and measured at the enacted tax rate expected to apply when temporary differences are realized or settled. Thus, at the date of enactment, federal deferred taxes were remeasured based upon the new 21% tax rate. The total effect of tax rate changes on deferred tax balances was recorded as a component of the income tax provision related to continuing operations for the period in which the law is enacted, even if the assets and liabilities relate to other components of the financial statements, such as items of accumulated other comprehensive income. DESC, as a rate-regulated utility, was required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, if it is probable that the effect of the change in income tax rates will be recovered or shared with customers in future rates, DESC recorded a regulatory asset or liability instead of an increase or decrease to deferred income tax expense.

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, 2019, DESC had $132 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.

Interest expense for DESC was $18 million, $8 million and less than $1 million in 2019, 2018, and 2017, respectively. Interest income for DESC was $2 million in 2019 and 2018, and less than $1 million in 2017. DESC also recorded penalty expenses of $7 million in 2019.

At December 31, 2019, DESC had an income tax-related affiliated receivable of $21 million from Dominion Energy. This balance is expected to be received from Dominion Energy.

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 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 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;

• Discussions with applicable regulatory authorities and legal counsel;

• Forecasted earnings; and

• Considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events and other natural disasters and unplanned outages of facilities.

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 Note 3 to the Consolidated Financial Statements for additional information.

Derivative Instruments

Derivative Instruments

DESC uses derivative instruments such as swaps to manage interest rate risks of its business operations. Derivatives 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.

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 $19 million and $11 million associated with cash collateral at December 31, 2019 and 2018, respectively. DESC had no margin liabilities associated with cash collateral at December 31, 2019 and 2018. See Note 8 for further information about derivatives.

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 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 the Company 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. See Note 3 and Note 17 regarding the settlement gains realized in the first quarter of 2018.

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 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 Income (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, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, 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 Loss. Rent expense associated with finance leases results in the separate presentation of interest expense on the lease liability and amortization expense of the related right-of-use asset in the Consolidated Statements of Comprehensive Loss. Amortization expense and interest charges associated with finance leases are recorded in depreciation and amortization and interest charges, respectively, in the Consolidated Statements of Comprehensive Loss or deferred within regulatory assets in the Consolidated Balance Sheets.

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

REVENUE RECOGNITION

In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. DESC adopted this revised accounting guidance for interim and annual reporting periods beginning January 1, 2018 using the modified retrospective method. No cumulative effect adjustment was recognized upon adoption. For additional required disclosures, see Note 4.

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. Under this approach, DESC utilized the transition practical expedient to maintain historical presentation for periods before January 1, 2019. DESC also applied the other 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.

NET PERIODIC PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

In March 2017, the FASB issued revised accounting guidance for the presentation of net periodic pension and other postretirement benefit costs. This guidance became effective for DESC beginning January 1, 2018 and requires that the service cost component of net periodic pension and other postretirement benefit costs be classified in the same line item as other compensation costs arising from services rendered by employees, while all other components of net periodic pension and other postretirement costs are classified outside of income from operations. In addition, only the service cost component remains eligible for capitalization during construction. The standard also recognizes that in the event that a regulator continues to require capitalization of all net periodic

benefit costs prospectively, the difference would result in recognition of a regulatory asset or liability. For costs not capitalized for which regulators are expected to provide recovery, a regulatory asset will be established.

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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Other Income (Expense), Net (Components of Other Income (Expense), Net) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Statement Of Income Captions [Line Items]
Operating revenue from contracts with customers	$ 4	$ 5	$ 0
Other income	19	141	45
Other expense	(57)	(28)	(32)
Allowance for equity funds used during construction	1	11	15
Other income (expense), net	$ (33)	129	$ 28
Other Income [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Condensed Statement Of Income Captions [Line Items]
Gains from settlement of interest rate derivatives		$ 115

XML

Utility Plant and Nonutility Property

12 Months Ended

Dec. 31, 2019

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, 2019 and 2018 were as follows:

At December 31,	2019		2018
(millions)
Gross utility plant:
Generation	$	5,765	$	5,751
Transmission		1,905		1,758
Distribution		4,685		4,456
Storage		73		74
General and other		549		535
Intangible		231		229
Construction work in progress		339		350
Nuclear fuel		608		611
Total gross utility plant	$	14,155	$	13,764
Gross nonutility property	$	75	$	73

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 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,	2019			2018
	Summer Unit 1			Summer Unit 1
Percent owned	66.7%			66.7%
Plant in service	$	1.4	billion	$	1.5	billion
Accumulated depreciation	$	684	million	$	644	million
Construction work in progress	$	79	million	$	128	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 $50 million at December 31, 2019 and $46 million at December 31, 2018.

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 income (expense), net in DESC’s Consolidated Statements of Comprehensive 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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Consolidated Statements of Comprehensive Loss (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Statement [Abstract]
Allowance for funds used during construction	$ 5	$ 9	$ 15
Deferred cost of employee benefit plans, tax	$ 0	$ 0	$ 0

XML

Document and Entity Information - shares	12 Months Ended
	Dec. 31, 2019	Feb. 15, 2020
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
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	Yes
Entity Voluntary Filers	No

XML

Nature of Operations

12 Months Ended

Dec. 31, 2019

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Nature of Operations

1.  NATURE OF OPERATIONS

DESC is a wholly-owned subsidiary of SCANA which, effective January 2019, 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 sells natural gas to residential, commercial and industrial customers in South Carolina.

Beginning in December 2019, 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.

XML

Derivative Financial Instruments (Fair Value of Derivatives) (Detail) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Derivative Liability		$ 19	$ 11
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	[1]	2	1
Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability	[2]	17	10
Interest Rate Contract [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability		2	1
Interest Rate Contract [Member] | Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability		17	10
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability		12	8
Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	[1]	1	1
Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability	[2]	11	7
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	7
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability		7	3
Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	[1]	1	0
Not Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability	[2]	6	3
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability		1	0
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability		$ 6	$ 3

[1] Current derivative liabilities are presented in other current liabilities in the Consolidated Balance Sheets.

[2] Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in the Consolidated Balance Sheets.

XML

Leases (Summary of Weighted Average Remaining Lease Term And Discount Rate for Operating and Finance Leases) (Detail)	Dec. 31, 2019
Leases [Abstract]
Weighted average remaining lease term - finance leases	5 years
Weighted average remaining lease term - operating leases	18 years
Weighted average discount rate - finance leases	2.94%
Weighted average discount rate - operating leases	3.94%

XML

Leases (Schedule Of Lease Assets and Liabilities Recorded in Consolidated Balance Sheets) (Detail) - USD ($) $ in Millions		Dec. 31, 2019		Jan. 01, 2019	Dec. 31, 2018
Leases [Abstract]
Operating lease assets		$ 23	[1]	$ 19
Finance lease assets	[2]	26
Total lease assets		49
Operating lease liabilities - current	[3]	3
Operating lease liabilities - noncurrent	[4]	20
Finance lease liabilities - current	[5]	7
Finance lease liabilities - noncurrent		20			$ 0
Total lease liabilities		$ 50

[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 $24 million of accumulated amortization at December 31, 2019.

[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 current portion of long-term debt in the Consolidated Balance Sheets.

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Income Taxes (Summary of Deductible Loss and Credit Carryforwards) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Investments Owned Federal Income Tax Note [Line Items]
Loss and Credit Carryforwards, Deductible Amount	$ 3,056
Loss and Credit Carryforwards, Deferred Tax Asset	415
Federal
Investments Owned Federal Income Tax Note [Line Items]
Loss Carryforwards, Deductible Amount	1,207
Loss Carryforwards, Deferred Tax Asset	$ 254
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	$ 38
Federal | Production and Other Credits | Minimum [Member]
Investments Owned Federal Income Tax Note [Line Items]
Credit Carryforwards, Expiration Period	2031
Federal | Production and Other Credits | Maximum [Member]
Investments Owned Federal Income Tax Note [Line Items]
Credit Carryforwards, Expiration Period	2038
State
Investments Owned Federal Income Tax Note [Line Items]
Loss Carryforwards, Deductible Amount	$ 1,849
Loss Carryforwards, Deferred Tax Asset	$ 92
Loss Carryforwards, Expiration Period	2037
State | Investment and Other Credits
Investments Owned Federal Income Tax Note [Line Items]
Credit Carryforwards, Deductible Amount	$ 0
Credit Carryforwards, Deferred Tax Asset	$ 31
State | Investment and Other Credits | Minimum [Member]
Investments Owned Federal Income Tax Note [Line Items]
Credit Carryforwards, Expiration Period	2026
State | Investment and Other Credits | Maximum [Member]
Investments Owned Federal Income Tax Note [Line Items]
Credit Carryforwards, Expiration Period	2031

XML

Income Taxes (Narrative) (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Investments Owned Federal Income Tax Note [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	21.00%	35.00%
Increase in net operating loss utilization		$ 79
Weighted average rate used to originate deferred tax liability		35.00%
Deferred income taxes, net		$ (379)	$ (184)	$ (780)
Regulatory liabilities		265	(360)	899
Income tax reconciliation, tax reform remeasurement				1
Income tax reconciliation tax reform remeasurement of additional impairment charges.			176
Income tax reconciliation tax reform remeasurement of additional adjustments to deferred income taxes.			23
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	$ (10)	$ 31	$ 13
Income tax examination, description		The statute is closed for IRS examination of years prior to 2010, except for certain outstanding refund claims. The IRS has completed examinations of DESC’s federal returns through 2012. The IRS is currently examining DESC’s federal returns from 2013 through 2017. With few exceptions, DESC is no longer subject to state and local income tax examinations by tax authorities for years prior to 2012
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 65	$ 65
Maximum [Member]
Investments Owned Federal Income Tax Note [Line Items]
Potential increase in earnings in next twelve months if tax benefits recognized		4
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

XML

Employee Benefit Plans and Equity Compensation Plan (Schedule of Amounts in Regulatory Assets to be Recognized Over the Next Fiscal Year) (Detail) - Scenario Forecast $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, future amortization of gain or loss from regulatory assets	$ 6
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, future amortization of gain or loss from regulatory assets	$ 1

XML

Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

A summary of DESC’s quarterly results of operations for the years ended December 31, 2019 and 2018 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

(millions)	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
2019
Operating revenue	$	(335	)	$	698		$	795	$	771
Operating income (loss)		(1,143	)		17			261		(76	)
Total comprehensive income (loss)		(1,103	)		(70	)		143		(191	)
Comprehensive income (loss) available (attributable) to    common shareholder		(1,109	)		(78	)		143		(195	)
2018
Operating revenue	$	702		$	632		$	739	$	689
Operating income (loss)		121			107			212		(1,271	)
Total comprehensive income (loss)		128			31			104		(852	)
Comprehensive income (loss) available (attributable) to    common shareholder		124			26			98		(861	)

XML

Rate and Other Regulatory Matters (Narrative) (Detail) $ in Millions				1 Months Ended			3 Months Ended		12 Months Ended
	Feb. 28, 2020 USD ($) NuclearPlant kV mi	Jan. 31, 2020 USD ($)	Oct. 30, 2018 Petition	Oct. 31, 2019 USD ($)	Jun. 30, 2019 USD ($)	Jul. 31, 2018 USD ($)	Sep. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Rate And Other Regulatory Matters [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent										21.00%	21.00%	35.00%
Operating expense										$ 2,870	$ 3,593	$ 3,153
South Carolina Commission Order for Decrease of Total Fuel Cost Component of Retail Electric Rates to produce a projected under-recovery										35
South Carolina Commission Order, Annual DSM Program Rate Rider Recovery Amount										$ 30
South Carolina Commission order, revenue requirement under RSA					$ 437
South Carolina Commission order, increase in natural gas rates under RSA					$ 7
South Carolina Commission order, revenue requirement approved under RSA				$ 436
Regulatory asset recovery assessment end period										2047
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
Subsequent Event
Rate And Other Regulatory Matters [Line Items]
DESC Pension Costs Rider approved by the South Carolina Commission		$ 11
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
Demand Side Management Programs [Member]
Rate And Other Regulatory Matters [Line Items]
Recovery period of regulatory asset										5 years
Asset Retirement Obligation Costs [Member]
Rate And Other Regulatory Matters [Line Items]
Recovery period of regulatory asset										105 years
Cost of Reacquired Debt [Member]
Rate And Other Regulatory Matters [Line Items]
Recovery period of regulatory asset										26 years
Net costs incurred										$ 270
Environmental Remediation Costs [Member]
Rate And Other Regulatory Matters [Line Items]
MPG environmental remediation										16 years
Electric Operations
Rate And Other Regulatory Matters [Line Items]
Public utilities percentage change in retail electric rates approved under BLRA						18.00%
Public utilities, approved rate increase (decrease), percentage						3.00%
Public utilities, requested rate increase (decrease), amount						$ 31
Operating expense											109
Operating expense after tax											82
Scenario Forecast
Rate And Other Regulatory Matters [Line Items]
South Carolina Commission Order for Decrease of Total Fuel Cost Component of Retail Electric Rates to produce a projected under-recovery	$ 44
DESC
Rate And Other Regulatory Matters [Line Items]
Credits to Customer Related to Tax Act										$ 63	$ 100
South Carolina Commission Order, Number of Petitions Granted | Petition			1
DESC | Subsequent Event
Rate And Other Regulatory Matters [Line Items]
South Carolina Commission Order, Annual DSM Program Rate Rider Recovery Amount		$ 40
DESC | Scenario Forecast
Rate And Other Regulatory Matters [Line Items]
Credits to Customer Related to Tax Act									$ 67
Number of nuclear plants under development | NuclearPlant	2
Cost of anticipated project	$ 75
DESC | Scenario Forecast | Transmission Project
Rate And Other Regulatory Matters [Line Items]
Cost of anticipated project	$ 30
Transmission lines length of miles to be approved | mi	28
Transmission lines capacity | kV	230
Savannah River Site
Rate And Other Regulatory Matters [Line Items]
Interest charges (benefit)							$ (10)	$ 6
Interest charges (benefit), after tax							$ (7)	$ 4

XML

Affiliated and Related Party Transactions (Schedule of Affiliated Transactions - Balance Sheet) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
SCANA Energy Marketing, Inc. [Member]
Related Party Transaction [Line Items]
Payable to affiliates	$ 0	$ 14
DESS [Member]
Related Party Transaction [Line Items]
Payable to affiliates	76	38
Public Service Company of North Carolina, Incorporated [Member]
Related Party Transaction [Line Items]
Payable to affiliates	8	7
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Receivable from affiliates	2	7
Payable to affiliates	$ 2	$ 7

XML

Quarterly Financial Information

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information

18.  QUARTERLY FINANCIAL DATA (UNAUDITED)

A summary of DESC’s quarterly results of operations for the years ended December 31, 2019 and 2018 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

(millions)	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
2019
Operating revenue	$	(335	)	$	698		$	795	$	771
Operating income (loss)		(1,143	)		17			261		(76	)
Total comprehensive income (loss)		(1,103	)		(70	)		143		(191	)
Comprehensive income (loss) available (attributable) to    common shareholder		(1,109	)		(78	)		143		(195	)
2018
Operating revenue	$	702		$	632		$	739	$	689
Operating income (loss)		121			107			212		(1,271	)
Total comprehensive income (loss)		128			31			104		(852	)
Comprehensive income (loss) available (attributable) to    common shareholder		124			26			98		(861	)

DESC’s 2019 results include the impact of the following significant items:

• Fourth quarter results include a $240 million after-tax charge related to litigation.

• Second quarter results include a $75 million after-tax charge related to litigation and a $47 million after-tax charge related to a voluntary retirement program.

• First quarter results include a $756 million after-tax charge for refunds of amounts previously collected from retail electric customers for the NND Project, a $198 million tax charge for $264 million of income tax-related regulatory assets for which DESC committed to forgo recovery, a $118 million after-tax charge for a settlement agreement of a DESC ratepayer class action lawsuit and an $86 million after-tax charge for property, plant and equipment for which DESC committed to forgo recovery.

DESC’s 2018 results include the impact of the following significant item:

• Fourth quarter results include a $870 million after-tax impairment charge related to the NND Project.

XML

Operating Segments

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Operating Segments

14.  OPERATING SEGMENTS

In December 2019, DESC realigned its segments which resulted in the formation of a single primary operating segment. The historical information presented herein has been recast to reflect the current segment presentation.

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 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.

In 2018, DESC reported after-tax net expenses of $917 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 2018 primarily related to a $1.4 billion ($870 million after-tax) impairment charge associated with the NND Project.

In 2017, DESC reported after-tax net expenses of $690 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 2017 related to a $1.1 billion ($690 million after-tax) impairment charge associated with the NND Project.

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)
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
Total assets (billions)		14.3		—			14.3
2018
External revenue	$	2,763	$	(1	)	$	2,762
Depreciation and amortization		327		—			327
Interest and related charges		306		(3	)		303
Income tax expense (benefit)		98		(514	)		(416	)
Comprehensive income (loss) available (attributable) to    common shareholder		304		(917	)		(613	)
Capital expenditures		633		—			633
Total assets (billions)		15.0		—			15.0
2017
External revenue	$	3,070	$	—		$	3,070
Depreciation and amortization		312		—			312
Interest and related charges		288		—			288
Income tax expense (benefit)		257		(428	)		(171	)
Comprehensive income (loss) available (attributable) to    common shareholder		505		(690	)		(185	)
Capital expenditures		928		—			928

XML

Utility Plant and Nonutility Property - Schedule of Jointly Owned Utility Plants (Details) - Summer Unit 1 - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Property Plant And Equipment [Line Items]
Jointly owned utility plant, proportionate ownership share	66.70%	66.70%
Plant in service, jointly owned utility plant	$ 1,400	$ 1,500
Accumulated depreciation, jointly owned utility plant	684	644
Construction work in progress, jointly owned utility plant	$ 79	$ 128

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Operating Segments (Narrative) (Detail) $ in Millions	3 Months Ended					12 Months Ended
	Dec. 31, 2019 USD ($) Segment	Jun. 30, 2019 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2019 USD ($) Segment	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Segment Reporting Information [Line Items]
Number of primary operating segments | Segment	1					1
Charge for refund of amounts from customers	$ 76			$ 73		$ 76	$ 73
Charge for refund of amounts from customers, after tax			$ 756
Litigation settlement expense, after tax	240	$ 75	118
Charge for utility plant but committed to forgo recovery, after tax			86
Charge related to a voluntary retirement program, after-tax		$ 47
Asset impairment charge			$ 105			576	1,376	$ 1,118
Asset impairment charge after-tax				$ 870	$ 3			690
Operating Segment | Corporate and Other
Segment Reporting Information [Line Items]
After- tax net expenses						1,600	917	690
Operating Segment | Dominion Energy South Carolina
Segment Reporting Information [Line Items]
Charge for refund of amounts from customers	1,000					1,000
Charge for refund of amounts from customers, after tax						756
Litigation settlement expense						590
Litigation settlement expense, after tax						444
Income tax related to regulatory assets acquired	194					194
Income tax related to regulatory assets acquired, after tax	$ 258					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
Asset impairment charge							1,400	1,100
Asset impairment charge after-tax							$ 870	$ 690

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Consolidated Statements of Changes in Common Equity - USD ($) shares in Millions, $ in Millions	Total	Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
Beginning balance at Dec. 31, 2016	$ 5,472	$ 2,860	$ 2,481	$ (3)	$ 134
Beginning balance (in shares) at Dec. 31, 2016		40
Total comprehensive income (loss) available (attributable) to common shareholder	(172)
Total comprehensive income (loss) available (attributable) to common shareholder	(173)		(185)	(1)	13
Capital contribution from parent	3				3
Dividend to parent	(322)		(314)		(8)
Ending balance at Dec. 31, 2017	4,980	$ 2,860	1,982	(4)	142
Ending balance (in shares) at Dec. 31, 2017		40
Total comprehensive income (loss) available (attributable) to common shareholder	(588)		(614)	1	25
Capital contribution from parent	24				24
Dividend to parent	(101)		(89)		(12)
Ending balance at Dec. 31, 2018	4,315	$ 2,860	1,279	(3)	179
Ending balance (in shares) at Dec. 31, 2018		40
Cumulative-effect of change in accounting principle			1	(1)
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

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Consolidated Statements of Comprehensive Loss - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Statement [Abstract]
Operating Revenue	[1]	$ 1,929	$ 2,762	$ 3,070
Operating Expenses:
Fuel used in electric generation	[1]	573	671	594
Purchased power	[1]	54	92	80
Gas purchased for resale	[1]	216	239	206
Other operations and maintenance		388	449	417
Other operations and maintenance – affiliated suppliers		244	182	180
Impairment of assets and other charges		695	1,376	1,118
Depreciation and amortization		450	327	312
Other taxes	[1]	250	257	246
Total operating expenses		2,870	3,593	3,153
Operating loss		(941)	(831)	(83)
Other income (expense), net		(33)	129	28
Interest charges, net of allowance for funds used during construction	[1]	260	303	288
Loss before income tax benefit		(1,234)	(1,005)	(343)
Income tax benefit		(12)	(416)	(171)
Net Loss		(1,222)	(589)	(172)
Other Comprehensive Income:
Deferred cost of employee benefit plans, net of tax		1	1	0
Total Comprehensive Loss		(1,221)	(588)	(172)
Comprehensive Income Attributable to Noncontrolling Interest		18	25	13
Comprehensive Loss Attributable to Common Shareholder		$ (1,239)	$ (613)	$ (185)

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

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Quarterly Financial Information (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended				12 Months Ended
	Dec. 31, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Litigation settlement expense, after tax	$ 240	$ 75	$ 118
Charge related to voluntary retirement program, after-tax		$ 47
Charge for refund of amounts from customers, after tax			756
Tax charge related to regulatory assets committed to forgo recovery			198
Regulatory asset impairment charges committed to forgo recovery			264
Charge for utility plant but committed to forgo recovery, after tax			$ 86
Impairment of assets and other charges					$ 695	$ 1,376	$ 1,118
NND Project Costs [Member]
Impairment of assets and other charges				$ 870

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Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2019

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:

	December 31, 2019								December 31, 2018
			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	$	—	$	19	$	—	$	11	$	—	$	11	$	—
Total derivatives	$	19	$	—	$	19	$	—	$	11	$	—	$	11	$	—

Schedule of Volume of Derivative Activity

The following table presents the volume of derivative activity at December 31, 2019. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions.

	Current		Noncurrent
Interest rate(1)	$	—	$	71,400,000

(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, 2019
Current Liabilities
Interest rate	$	1	$	1	$	2
Total current derivative liabilities(1)		1		1		2
Noncurrent Liabilities
Interest rate		11		6		17
Total noncurrent derivative liabilities(2)		11		6		17
Total derivative liabilities	$	12	$	7	$	19
At December 31, 2018
Current Liabilities
Interest rate	$	1	$	—	$	1
Total current derivative liabilities(1)		1		—		1
Noncurrent Liabilities
Interest rate		7		3		10
Total noncurrent derivative liabilities(2)		7		3		10
Total derivative liabilities	$	8	$	3	$	11

(1) Current derivative liabilities are presented in other current liabilities in the Consolidated Balance Sheets.

(2) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in the 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)	Gain (loss) Reclassified from Deferred Accounts into Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(1)
Year Ended December 31, 2019
Derivative type and location of gains (losses):
Interest rate(2)	$	—		$	1
Total	$	—		$	1
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Interest rate(2)	$	(1	)	$	1
Total	$	(1	)	$	1
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Interest rate(2)	$	(2	)	$	(2	)
Total	$	(2	)	$	(2	)

(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 Loss.

(2) Amounts recorded in DESC’s Consolidated Statements of Comprehensive Loss are classified in interest charges.

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,	2019			2018			2017
Derivative type and location of gains (losses):
Interest rate contracts:
Interest charges	$	(1	)	$	(2	)	$	(3	)
Other income		—			115			—
Impairment loss		—			—			(173	)
Total	$	(1	)	$	113		$	(176	)

(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 Loss.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2019

Commitments And Contingencies Disclosure [Abstract]

Schedule of Long-Term Purchase Agreements

At December 31, 2019, 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)	2020		2021		2022		2023		2024		Thereafter		Total
Purchased electric capacity(1)	$	59	$	58	$	57	$	57	$	57	$	661	$	949

(1) Includes affiliated amounts with certain solar facilities of $234 million.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2019

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, 2019, DESC has recorded AROs of $177 million for nuclear plant decommissioning. At December 31, 2019, DESC had $214 million in a trust for its two-thirds share of decommissioning activities. In addition, DESC has recorded AROs of $312 million for other conditional obligations primarily related to other generation, transmission 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)	2019			2018
Beginning balance	$	541		$	529
Liabilities settled		(29	)		(15	)
Accretion expense		23			23
Revisions in estimated cash flows(1)		(46	)		4
Ending balance	$	489		$	541

(1)   The decrease in 2019 reflects a change in the estimated timing of cash flows for interim pipeline replacements and DOE recoveries.

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Long-Term and Short-Term Debt

12 Months Ended

Dec. 31, 2019

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, 2019 and 2018 is as follows:

At December 31,	2019 Weighted- average Coupon(1)			2019			2018
(millions, except percentages)
DESC:
First Mortgage Bonds, 3.22% to 6.625%, due 2021 to 2065(2)		5.42	%	$	3,267		$	4,990
Tax-Exempt Financings:
Variable rate due 2038		1.65	%		35			35
3.625% and 4.00%, due 2028 and 2033		3.90	%		54			54
Other		3.69	%		1			—
GENCO:
Tax-Exempt Financing, variable rate due 2038		1.65	%		33			33
Secured Senior Notes, 5.49% due 2024(3)					—			40
Affiliated note, 3.05% due 2024		3.05	%		230			—
Total principal					3,620			5,152
Securities due within one year					—			(14	)
Unamortized discount, premium and debt issuance costs, net					(32	)		(36	)
Finance leases					20			30
Total long-term debt				$	3,608		$	5,132

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2019.

(2) In February, March and September 2019, DESC purchased certain of its first mortgage bonds having an aggregate purchase price of $1.8 billion pursuant to tender offers. The February and March tender offers expired in the first quarter of 2019 and the September tender offer expired in the third quarter of 2019.

(3) In May 2019, GENCO redeemed its 5.49% senior secured notes due in 2024 at the remaining principal outstanding of $33 million plus accrued interest.

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, 2019, were as follows:

(millions, except percentages)	2020		2021			2022		2023		2024			Thereafter			Total
First Mortgage Bonds	$	—	$	33		$	—	$	—	$	—		$	3,234		$	3,267
Tax-Exempt Financings		—		—			—		—		—			122			122
Other		—		—			—		—		230			1			231
Total	$	—	$	33		$	—	$	—	$	230		$	3,357		$	3,620
Weighted-average coupon				3.25	%						3.05	%		5.34	%

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 (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be issued (Bond Ratio). For the year ended December 31, 2019, the Bond Ratio was 6.88. Adjusted Net Earnings, as therein defined, excludes the impairment loss.

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

In March 2019, DESC became a co-borrower under Dominion Energy's $6.0 billion joint revolving credit facility. DESC's short-term financing is supported through its access to this joint revolving credit facility, which can be used for working capital, as support for the combined commercial paper programs of DESC, Dominion Energy and certain other of its subsidiaries (co-borrowers), 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, 2019	$	1,000	$	—	$	—

A maximum of $1.0 billion of the facility is available to DESC, less any amounts outstanding to co-borrowers. 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, 2019, 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 March 2023 and 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.

Also in March 2019, DESC canceled its previous committed long-term facility which was a revolving line of credit under a credit agreement with a syndicate of banks. This previous credit agreement was used for general corporate purposes, including liquidity support for DESC's commercial paper program and working capital needs, and was set to expire in December 2020.

(millions)	Facility Limit(1)		Outstanding Commercial Paper		Outstanding Letters of Credit
At December 31, 2018	$	1,200	$	73	$	—

(1) Included $500 million related to Fuel Company. In February 2019, Fuel Company's commercial paper program and its credit facility were terminated.

The weighted-average interest rate of the outstanding commercial paper supported by this credit facility was 3.82% at December 31, 2018.

In April 2019, DESC renewed its FERC authority through April 2020 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 April 2019, GENCO renewed its FERC authority through April 2020 to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. In January 2020, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization. The applications are pending.

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 2020.

DESC received FERC approval to enter into an inter-company credit agreement in April 2019 with Dominion Energy under which DESC may have short-term borrowings outstanding up to $900 million. At December 31, 2019, DESC had borrowings outstanding under this credit agreement totaling $355 million, which are recorded in affiliated and related party payables in DESC’s Consolidated Balance Sheets. For the twelve months ended December 31, 2019, DESC recorded interest charges of $3 million.

DESC participated in a utility money pool with SCANA and another regulated subsidiary of SCANA through April 2019. Fuel Company and GENCO remain in the utility money pool. Money pool borrowings and investments bear interest at short-term market rates. For the years ended December 31, 2019 and 2018, DESC recorded interest income from money pool transactions of $8 million and $4 million, respectively, and for the same periods DESC recorded interest expense from money pool transactions of $8 million and $4 million, respectively. DESC had outstanding money pool borrowings due to an affiliate of $219 million and investments due from an affiliate of $9 million at December 31, 2019. At December 31, 2018, DESC had outstanding money pool borrowings due to an affiliate of $282 million and investments due from an affiliate of $353 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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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

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 VIE’s 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 VIE’s. 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. GENCO’s property (carrying value of $508 million) previously served as collateral for its long-term borrowings. 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, DESC purchases shared services from DESS, an affiliated VIE that provides accounting, legal, finance and certain administrative and technical services to all SCANA subsidiaries, including DESC. DESC has determined that it is not the primary beneficiary of DESS 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 2018 and 2017 Consolidated Financial Statements and Notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect DESC’s net income, total assets, liabilities, equity or cash flows.

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 4.3%, 7.0% and 3.9% for 2019, 2018 and 2017, 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:

	2019			2018
Generation		2.50	%		2.61	%
Transmission		2.57	%		2.74	%
Distribution		2.41	%		2.41	%
Storage		2.74	%		2.71	%
General and other		3.22	%		3.18	%

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 equipment and nuclear refueling outages are 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.

DESC is authorized to collect $18 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2019 and 2018, DESC incurred $10 million and $16 million, respectively, for turbine 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 scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which DESC was responsible totaled $2 million in 2019 and $29 million in 2018.

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 2016, 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 $646 million, stated in 2019 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. At December 31, 2019, there were no restricted cash and equivalent balances. At December 31, 2018, cash and cash equivalents at DESC included $115 million held in escrow pending a settlement which was contingent on the consummation of the merger with Dominion Energy. As such, DESC did not consider this amount to be restricted at December 31, 2018.

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 $114 million and $129 million at December 31, 2019 and 2018, 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 facilities at Summer. Such receivables represented approximately 10% of DESC’s accounts receivable balance at December 31, 2019.

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 was filed for SCANA, including DESC for years through 2018. Beginning in 2019, SCANA and DESC are part of Dominion Energy’s consolidated federal income tax return. 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 participated in intercompany tax sharing agreements with SCANA through the SCANA Combination, and currently participates in similar agreements with Dominion Energy. Under both SCANA and Dominion Energy’s tax sharing agreements, 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 SCANA or 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.

The 2017 Tax Reform Act included a broad range of tax reform provisions affecting DESC, including changes in corporate tax rates and business deductions. The 2017 Tax Reform Act reduces the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. Deferred tax assets and liabilities are classified as noncurrent in the Consolidated Balance Sheets and measured at the enacted tax rate expected to apply when temporary differences are realized or settled. Thus, at the date of enactment, federal deferred taxes were remeasured based upon the new 21% tax rate. The total effect of tax rate changes on deferred tax balances was recorded as a component of the income tax provision related to continuing operations for the period in which the law is enacted, even if the assets and liabilities relate to other components of the financial statements, such as items of accumulated other comprehensive income. DESC, as a rate-regulated utility, was required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, if it is probable that the effect of the change in income tax rates will be recovered or shared with customers in future rates, DESC recorded a regulatory asset or liability instead of an increase or decrease to deferred income tax expense.

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, 2019, DESC had $132 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.

Interest expense for DESC was $18 million, $8 million and less than $1 million in 2019, 2018, and 2017, respectively. Interest income for DESC was $2 million in 2019 and 2018, and less than $1 million in 2017. DESC also recorded penalty expenses of $7 million in 2019.

At December 31, 2019, DESC had an income tax-related affiliated receivable of $21 million from Dominion Energy. This balance is expected to be received from Dominion Energy.

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 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 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;

• Discussions with applicable regulatory authorities and legal counsel;

• Forecasted earnings; and

• Considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events and other natural disasters and unplanned outages of facilities.

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 Note 3 to the Consolidated Financial Statements for additional information.

Derivative Instruments

DESC uses derivative instruments such as swaps to manage interest rate risks of its business operations. Derivatives 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.

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 $19 million and $11 million associated with cash collateral at December 31, 2019 and 2018, respectively. DESC had no margin liabilities associated with cash collateral at December 31, 2019 and 2018. See Note 8 for further information about derivatives.

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 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 the Company 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. See Note 3 and Note 17 regarding the settlement gains realized in the first quarter of 2018.

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 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 Income (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, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, 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 Loss. Rent expense associated with finance leases results in the separate presentation of interest expense on the lease liability and amortization expense of the related right-of-use asset in the Consolidated Statements of Comprehensive Loss. Amortization expense and interest charges associated with finance leases are recorded in depreciation and amortization and interest charges, respectively, in the Consolidated Statements of Comprehensive Loss or deferred within regulatory assets in the Consolidated Balance Sheets.

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

REVENUE RECOGNITION

In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. DESC adopted this revised accounting guidance for interim and annual reporting periods beginning January 1, 2018 using the modified retrospective method. No cumulative effect adjustment was recognized upon adoption. For additional required disclosures, see Note 4.

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. Under this approach, DESC utilized the transition practical expedient to maintain historical presentation for periods before January 1, 2019. DESC also applied the other 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.

NET PERIODIC PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

In March 2017, the FASB issued revised accounting guidance for the presentation of net periodic pension and other postretirement benefit costs. This guidance became effective for DESC beginning January 1, 2018 and requires that the service cost component of net periodic pension and other postretirement benefit costs be classified in the same line item as other compensation costs arising from services rendered by employees, while all other components of net periodic pension and other postretirement costs are classified outside of income from operations. In addition, only the service cost component remains eligible for capitalization during construction. The standard also recognizes that in the event that a regulator continues to require capitalization of all net periodic

benefit costs prospectively, the difference would result in recognition of a regulatory asset or liability. For costs not capitalized for which regulators are expected to provide recovery, a regulatory asset will be established.

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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Employee Benefit Plans and Equity Compensation Plan (Amounts Recognized in Regulatory Assets ) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ 125	$ 202
Prior service cost	0	1
Total	125	203
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	29	9
Total	$ 29	$ 9

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Fair Value Measurements, Including Derivatives (Schedule of Liabilities Measured at Fair Value on Recurring Basis) (Details) - Fair value, recurring - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Liabilities
Total liabilities	$ 19	$ 11
Interest Rate Contract [Member]
Liabilities
Total liabilities	19	11
Level 1
Liabilities
Total liabilities	0	0
Level 1 | Interest Rate Contract [Member]
Liabilities
Total liabilities	0	0
Level 2
Liabilities
Total liabilities	19	11
Level 2 | Interest Rate Contract [Member]
Liabilities
Total liabilities	19	11
Level 3
Liabilities
Total liabilities	0	0
Level 3 | Interest Rate Contract [Member]
Liabilities
Total liabilities	$ 0	$ 0

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Employee Benefit Plans and Equity Compensation Plan (Narrative) (Detail) - USD ($)	3 Months Ended		12 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Voluntary retirement program related charges				$ 63,000,000
Voluntary retirement program related charges net of taxes				47,000,000
Increase in pension benefit obligation	$ 25,000,000	$ 16,000,000
Increase in accumulated postretirement benefit obligation		10,000,000
Increase in fair value of pension plan assets	$ 35,000,000	$ 27,000,000
Defined benefit plan, accumulated benefit obligation				$ 711,000,000	$ 714,000,000
Defined benefit plan, annual rate of increase in the per capita cost of covered health care benefits				6.60%
Defined benefit plan, ultimate health care cost trend rate				5.00%
Defined benefit plan, effect of one percentage point increase on accumulated postretirement benefit obligation					1,000,000
Defined benefit plan, effect of one percentage point decrease on accumulated postretirement benefit obligation					1,000,000
Fair value assets transfer from Level 1 to Level 2				$ 0	0
Fair value assets transfer from Level 2 to Level 1				$ 0	0
Defined benefit plan, expected future employer contributions, next fiscal year, description				no
Defined contribution plan maximum defer percentage of employer contribution of eligible employees earnings				75.00%
Defined contribution plan, maximum percentage of employer contribution for up to six percent of participant contribution				100.00%
Defined contribution plan, maximum percentage of participant contribution eligible for employer contribution match				6.00%
Defined contribution plan, employer matching contributions				$ 14,000,000	20,000,000	$ 23,000,000
Scenario Forecast
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, assumptions used calculating net periodic benefit cost, expected long-term rate of return on plan assets			7.00%
Summer
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, shared costs deferred with joint ownership				19,000,000	$ 25,000,000
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, effect of one percentage point increase on accumulated postretirement benefit obligation				1,000,000
Defined benefit plan, effect of one percentage point decrease on accumulated postretirement benefit obligation				$ 1,000,000
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate percentage	3.57%	4.07%		3.47%	4.35%
Defined benefit plan, assumptions used calculating net periodic benefit cost, expected long-term rate of return on plan assets				7.00%	7.00%	7.25%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate percentage		4.08%		3.52%	4.38%
Defined benefit plan, ultimate health care cost trend rate				5.00%	5.00%	5.00%
Other Postretirement Benefits | Summer
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, shared costs deferred with joint ownership				$ 15,000,000	$ 12,000,000
Other Operations and Maintenance Expense
Defined Benefit Plan Disclosure [Line Items]
Voluntary retirement program related charges				51,000,000
Other Taxes
Defined Benefit Plan Disclosure [Line Items]
Voluntary retirement program related charges				3,000,000
Other Income (Expense), Net
Defined Benefit Plan Disclosure [Line Items]
Voluntary retirement program related charges				9,000,000
Settlement losses as a result of voluntary retirement program				$ 16,000,000

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Employee Benefit Plans (Expected Benefit Payments) (Detail) $ in Millions	Dec. 31, 2019 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, expected benefit payments, 2020	$ 70
Defined benefit plan, expected benefit payments, 2021	37
Defined benefit plan, expected benefit payments, 2022	48
Defined benefit plan, expected benefit payments, 2023	46
Defined benefit plan, expected benefit payments, 2024	46
Defined benefit plan, expected benefit payments, 2025-2029	210
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, expected benefit payments, 2020	13
Defined benefit plan, expected benefit payments, 2021	13
Defined benefit plan, expected benefit payments, 2022	13
Defined benefit plan, expected benefit payments, 2023	13
Defined benefit plan, expected benefit payments, 2024	13
Defined benefit plan, expected benefit payments, 2025-2029	$ 69

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Ultimate health care cost trend rate	5.00%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate		3.71%	4.22%
Expected return on plan assets	7.00%	7.00%	7.25%
Rate of compensation increase	3.00%	3.00%	3.00%
Pension Benefits | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.57%
Pension Benefits | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.38%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate		3.74%	4.30%
Health care cost trend rate	6.60%	7.00%	6.60%
Ultimate health care cost trend rate	5.00%	5.00%	5.00%
Year achieved	2023	2023	2021
Other Postretirement Benefits | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.08%
Other Postretirement Benefits | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.41%

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Employee Benefit Plans and Equity Compensation Plan (Amounts Recognized on Consolidated Balance Sheets) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Noncurrent liability	$ (2)	$ (56)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liability	(13)	(11)
Noncurrent liability	$ (201)	$ (177)

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Long-Term and Short-Term Debt (Schedule of Principal Payments of Long-Term Debt) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
2020	$ 0
2021	33
2022	0
2023	0
2024	230
Thereafter	3,357
Total	$ 3,620	$ 5,152
Weighted-average coupon, 2021	3.25%
Weighted-average coupon, 2024	3.05%
Weighted-average coupon, Thereafter	5.34%
Weighted-average coupon, Thereafter		3.82%
First Mortgage Bonds
Debt Instrument [Line Items]
2020	$ 0
2021	33
2022	0
2023	0
2024	0
Thereafter	3,234
Total	3,267
Tax Exempt Financings
Debt Instrument [Line Items]
2020	0
2021	0
2022	0
2023	0
2024	0
Thereafter	122
Total	122
Other Debt
Debt Instrument [Line Items]
2020	0
2021	0
2022	0
2023	0
2024	230
Thereafter	1
Total	$ 231

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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, 2019	Dec. 31, 2018
Revenues [Abstract]
Beginning balance	$ 15	$ 16
Amortization	(2)	(1)
Ending balance	$ 13	$ 15

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Rate and Other Regulatory Matters (Schedule of Regulatory Liabilities) (Detail) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities
Regulatory liability, current		$ 256	$ 126
Regulatory liability, noncurrent		3,210	2,264
Total regulatory liabilities		3,466	2,390
Monetization Of Guaranty Settlement [Member]
Regulatory Liabilities
Regulatory liability, current	[1]	67	61
Regulatory liability, noncurrent	[1]	970	1,037
Income Taxes Refundable Through Future Rates [Member]
Regulatory Liabilities
Regulatory liability, current	[2]	16	52
Regulatory liability, noncurrent	[2]	948	607
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities
Regulatory liability, noncurrent	[3]	552	541
Reserve For Refunds To Electric Utility Customers [Member]
Regulatory Liabilities
Regulatory liability, current	[4]	143	0
Regulatory liability, noncurrent	[4]	656	0
Other Regulatory Liability [Member]
Regulatory Liabilities
Regulatory liability, current		30	13
Regulatory liability, noncurrent		13	4
Deferred Gains On Interest Rate Derivatives [Member]
Regulatory Liabilities
Regulatory liability, noncurrent	[5]	$ 71	$ 75

[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] Represents estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.

[4] 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 in connection with the SCANA Merger Approval Order. See Note 12 for more information.

[5] 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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Summary of Significant Accounting Policies (Narrative) (Detail)		12 Months Ended
	Jan. 01, 2019 USD ($)	Dec. 31, 2019 USD ($) MW		Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Significant Accounting Policies
Carrying value of property		$ 69,000,000		$ 72,000,000
Public utilities, allowance for funds used during construction, rate		4.30%		7.00%	3.90%
Utilities operating expense, maintenance and operations, affiliate		$ 244,000,000		$ 182,000,000	$ 180,000,000
Turbine maintenance expense		10,000,000		16,000,000
Amount accrued annually for nuclear fuel outages		17,000,000
Nuclear refueling outage cost		2,000,000		29,000,000
Decommissioning liability, noncurrent		646,000,000
Payments to acquire investments to be held in decommissioning trust fund		3,000,000
Restricted cash and equivalent balances		0		0	$ 0
Cash held in escrow				115,000,000
Unbilled revenues		$ 114,000,000		$ 129,000,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%		21.00%	35.00%
Unrecognized tax benefits		$ 132,000,000		$ 106,000,000	$ 98,000,000	$ 350,000,000
Interest expense		18,000,000		8,000,000
Interest income		2,000,000		2,000,000
Penalty expenses		7,000,000
Income taxes related to affiliated receivable		21,000,000
Margin liabilities with cash collateral		0		0
Margin assets with cash collateral		$ 19,000,000		$ 11,000,000
Option to extend, existence, operating lease		true
Operating lease, right of use asset	$ 19,000,000	$ 23,000,000	[1]
Operating lease liability	19,000,000	$ 23,000,000
Reclassification From AOCI to retained earnings	$ 1,000,000
Minimum [Member]
Significant Accounting Policies
Lease renewal term		1 year
Maximum [Member]
Significant Accounting Policies
Interest expense					1,000,000
Interest income					$ 1,000,000
Lease renewal term		70 years
Original term of leases		1 year
Accounts Receivable | Credit Concentration Risk
Significant Accounting Policies
Concentration risk percentage		10.00%
Turbine [Member]
Significant Accounting Policies
Utilities operating expense, maintenance and operations, affiliate		$ 18,000,000
Genco
Significant Accounting Policies
Power Generation Capacity Megawatts | MW		605
Carrying value of property		$ 508,000,000

[1] Included in other deferred debits and other assets in the Consolidated Balance Sheets.

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Leases (Summary of Total Lease Cost) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Leases [Abstract]
Finance lease cost, amortization	$ 7
Finance lease cost, interest	1
Operating lease cost	4
Short-term lease cost	1
Total lease cost	$ 13

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Derivative Financial Instruments (Offsetting Liabilities) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Gross liabilities presented in the consolidated balance sheet	$ 19	$ 11
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	19	11
Gross amounts not offset in the consolidated balance sheet, net amounts	0	0
Interest Rate Contract [Member] | Over The Counter [Member]
Derivative [Line Items]
Gross liabilities presented in the consolidated balance sheet	19	11
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	19	11
Gross amounts not offset in the consolidated balance sheet, net amounts	$ 0	$ 0

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Income Taxes (Schedule of Effective Income Tax Rate Reconciliation) (Detail)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
U.S. statutory rate	21.00%	21.00%	35.00%
Increases (reductions) resulting from:
State taxes, net of federal benefit	3.90%	3.80%	2.30%
State investment tax credits	0.00%	0.30%	1.50%
AFUDC - equity	0.00%	0.20%	1.50%
Amortization of federal investment tax credits	0.10%	0.20%	0.60%
Production tax credits	0.40%	0.90%	2.30%
Domestic production activities deduction	0.00%	0.00%	5.20%
Reversal of excess deferred income taxes	(1.40%)	0.00%	0.00%
Federal legislative change	0.00%	17.50%	0.30%
NND Project impairment	(2.40%)	(2.30%)	0.00%
Write-off of regulatory asset	(15.80%)	0.00%	0.00%
Changes in unrecognized tax benefits	(5.10%)	0.00%	0.00%
Other	0.20%	(0.20%)	1.20%
Effective tax rate	0.90%	41.40%	49.90%

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Commitments and Contingencies (Schedule of Long-Term Purchase Agreements) (Detail) $ in Millions	Dec. 31, 2019 USD ($)	[1]
Commitments And Contingencies Disclosure [Abstract]
Purchased electric capacity, 2020	$ 59
Purchased electric capacity, 2021	58
Purchased electric capacity, 2022	57
Purchased electric capacity, 2023	57
Purchased electric capacity, 2024	57
Purchased electric capacity, Thereafter	661
Purchased electric capacity, Total	$ 949

[1] Includes affiliated amounts with certain solar facilities of $234 million

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Consolidated Statements of Cash Flows - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Activities
Net loss		$ (1,222)	$ (589)	$ (172)
Adjustments to reconcile net loss to net cash provided by operating activities:
Impairment of assets and other charges		576	1,376	1,118
Provision for refunds to electric customers		800	0	0
Gain on sale of assets		(7)	0	0
Deferred income taxes, net		(379)	(184)	(780)
Depreciation and amortization		464	342	323
Amortization of nuclear fuel		53	47	44
Other adjustments		(7)	(17)	(49)
Changes in certain assets and liabilities:
Receivables		(33)	50	(32)
Receivables – affiliated and related party		1	(2)	12
Income tax receivable		0	198	(145)
Inventories		(76)	(54)	(60)
Prepayments		(9)	0	6
Regulatory assets		(20)	(179)	185
Regulatory liabilities		265	(360)	899
Accounts payable		(54)	61	20
Accounts payable – affiliated and related party		(15)	0	(28)
Revenue subject to refund		(73)	77	0
Unrecognized tax benefits		52	19	(241)
Taxes accrued		(10)	31	13
Pension and other postretirement benefits		(27)	15	(21)
Other assets and liabilities		169	96	(86)
Net cash provided by operating activities		448	927	1,006
Investing Activities
Property additions and construction expenditures		(497)	(633)	(928)
Proceeds from monetization of guaranty settlement		0	0	1,096
Proceeds from investments and sales of assets		39	40	118
Purchase of investments		(54)	(29)	(122)
Purchase of investments – affiliate		0	(111)	0
Payments upon interest rate derivative contract settlement		0	0	(39)
Proceeds from interest rate derivative contract settlement		0	115	0
Investment in affiliate, net		344	(214)	(28)
Net cash provided by (used in) investing activities		(168)	(832)	97
Financing Activities
Proceeds from issuance of debt		0	795	0
Proceeds from issuance of affiliated debt		230	0	0
Repayment of long-term debt, including redemption premiums		(1,890)	(825)	(12)
Dividend to parent		(30)	(173)	(319)
Short-term borrowings, net		(73)	(179)	(552)
Short-term borrowings – affiliated, net		292	0	0
Money pool borrowings, net		0	245	8
Contribution from parent		838	24	3
Contribution returned to parent		(20)	0	0
Net cash used in financing activities		(653)	(113)	(872)
Net increase (decrease) in cash, restricted cash and equivalents		(373)	(18)	231
Cash, restricted cash and equivalents at beginning of period	[1]	377	395	164
Cash, restricted cash and equivalents at end of period	[1]	4	377	395
Supplemental Cash Flow Information
Cash for interest paid (net of capitalized interest)		220	264	269
Cash for income taxes paid		13	3	47
Cash for income taxes received		0	216	145
Noncash investing and financing activities:
Accrued construction expenditures	[2]	120	69	99
Leases	[2],[3]	12	8	8
Contributed capital	[2]	$ 1	$ 6	$ 0

[1] For the years ended December 31, 2019, 2018 and 2017 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.

[3] Includes $4 million of financing leases and $8 million of operating leases for the year ended December 31, 2019 and $8 million of capital leases for both years ended December 31, 2018 and 2017.

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Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
ASSETS
Utility plant in service	$ 13,208	$ 12,803
Accumulated depreciation and amortization	(4,851)	(4,581)
Construction work in progress	339	350
Nuclear fuel, net of accumulated amortization	219	211
Utility plant, net	8,915	8,783
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	69	72
Assets held in trust, nuclear decommissioning	214	190
Other investments	0	1
Nonutility property and investments, net	283	263
Current Assets:
Cash and cash equivalents	4	377
Receivables, customer, net of allowance for uncollectible accounts	320	331
Receivables, affiliated and related party	14	359
Receivables, other	119	68
Inventories (at average cost):
Fuel	104	89
Materials and supplies	168	158
Prepayments	91	82
Regulatory assets	271	224
Other current assets	27	1
Total current assets	1,118	1,689
Deferred Debits and Other Assets:
Regulatory assets	3,892	4,060
Other	93	168
Total deferred debits and other assets	3,985	4,228
Total assets	14,301	14,963
CAPITALIZATION AND LIABILITIES
Common Stock - no par value	3,695	2,860
Retained earnings	20	1,279
Accumulated other comprehensive income (loss)	(3)	(3)
Total common equity	3,712	4,136
Noncontrolling interest	180	179
Total Equity	3,892	4,315
Long-term debt, net	3,358	5,132
Affiliated long-term debt	230	0
Finance leases	20	0
Total long-term debt	3,608	5,132
Total capitalization	7,500	9,447
Current Liabilities:
Short-term borrowings	0	73
Securities due within one year	7	14
Accounts payable	245	267
Affiliated and related party payables	624	347
Customer deposits and customer prepayments	76	73
Revenue subject to refund	4	77
Taxes accrued	218	228
Interest accrued	88	72
Regulatory liabilities	256	126
Reserves for litigation and regulatory proceedings	492	11
Other	56	42
Total current liabilities	2,066	1,330
Deferred Credits and Other Liabilities:
Deferred income taxes and investment tax credits	629	1,008
Asset retirement obligations	489	542
Pension and other postretirement benefits	203	232
Regulatory liabilities	3,210	2,264
Affiliated liabilities	15	16
Other	189	124
Total deferred credits and other liabilities	4,735	4,186
Commitments and Contingencies
Total capitalization and liabilities	$ 14,301	$ 14,963

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Affiliated and Related Party Transactions

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Affiliated and Related Party Transactions

16.  AFFILIATED AND RELATED PARTY TRANSACTIONS

DESC owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions at certain 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 Loss.

DESC purchases natural gas and related pipeline capacity from SCANA Energy Marketing, Inc. to service its retail gas customers and to satisfy certain electric generation requirements. These purchases are included within gas purchased for resale or fuel used in electric generation, as applicable in the Consolidated Statements of Comprehensive Loss.

DESS, on behalf of itself and its parent company, provides the following services to DESC, which are 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 processes and pays invoices for DESC and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in other operations and maintenance – affiliated suppliers and other income (expense), net in the Consolidated Statements of Comprehensive Loss.

Year Ended December 31,	2019		2018		2017
(millions)
Purchases of coal from affiliate	$	121	$	150	$	162
Sales of coal to affiliate		120		149		161
Purchases of fuel used in electric generation from affiliate		43		139		127
Direct and allocated costs from services company affiliate(1)		297		283		303
Operating Revenues – Electric from sales to affiliate		4		5		5
Operating Revenues – Gas from sales to affiliate		1		1		1
Operating Expenses – Other taxes from affiliate		6		6		5

(1) Includes capitalized expenditures of $53 million, $41 million and $82 million for the years ended December 31, 2019, 2018 and 2017, respectively.

At December 31,	2019		2018
(millions)
Receivable from Canadys Refined Coal, LLC	$	2	$	7
Payable to Canadys Refined Coal, LLC		2		7
Payable to SCANA Energy Marketing, Inc		—		14
Payable to DESS		76		38
Payable to Public Service Company of North Carolina, Incorporated		8		7

In connection with the SCANA Combination, purchases from certain entities owned by Dominion Energy became affiliated transactions. During the year ended December 31, 2019, DESC purchased electricity generated by certain solar facilities, totaling $8 million, which is recorded as purchased power in the Consolidated Statements of Comprehensive Loss. At December 31, 2019, DESC

had accounts payable balances to these affiliates totaling less than $1 million. In addition, during the year ended December 31, 2019, DESC incurred demand and transportation charges from DECG totaling $63 million, of which $19 million is recorded as fuel used in electric generation and $44 million is recorded as gas purchased for resale in the Consolidated Statements of Comprehensive Loss. At December 31, 2019, DESC had an accounts payable balance due to this affiliate totaling $5 million and an accounts receivable to this affiliate totaling $1 million.

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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Commitments And Contingencies

12 Months Ended

Dec. 31, 2019

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. 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 and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. DESC and GENCO participate in the SO₂ and NO_X emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at their coal-fired electric generating plants. These actions are expected to address many of the rules and regulations discussed herein.

Air

CAA

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 address all 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.

MATS

In February 2019, the EPA published a proposed rule to reverse its previous finding that it is appropriate and necessary to regulate toxic emissions from power plants. However, the emissions standards and other requirements of the MATS rule would remain in place as the EPA is not proposing to remove coal and oil-fired power plants from the list of sources that are regulated under MATS. Although litigation of the MATS rule and the outcome of the EPA’s rulemaking are still pending, the regulation remains in effect and DESC is complying with the applicable requirements of the rule and does not expect any adverse impacts to its operations at this time.

Ozone Standards

The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018. States have until August 2021 to develop plans to address the new standard. Until the states have developed implementation plans for the standard, DESC is unable to predict whether or to what extent the new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact on DESC’s results of operations and 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 applies to existing coal-fired power plants. The final rule includes unit-specific performance standards based on the degree of emission reduction levels achievable from unit efficiency improvements to be determined by the permitting agency. The ACE Rule requires states to develop plans by July 2022 to implement these performance standards. These state plans must be approved by the EPA by January 2024. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina provide rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

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 to set a significant emissions rate at 75,000 tons per year of CO2 equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, DESC cannot predict the impact to their 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 the best operating practices.

Oil and Gas NSPS

In August 2012, the EPA issued an NSPS impacting new and modified facilities in the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In June 2016, the EPA issued another NSPS regulation, for the oil and natural gas sector, to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. All projects which commenced construction after September 2015 are required to comply with this regulation. In October 2018, the EPA published a proposed rule reconsidering and amending portions of the 2016 rule, including but not limited to, the fugitive emissions requirements at well sites and compressor stations. The amended portions of the 2016 rule were effective immediately upon publication. Until the proposed rule regarding reconsideration is final, DESC is implementing the 2016 regulation. DESC is still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.

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 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, technology, cost and 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 establishes 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 remains December 2023. 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 will be required at Williams and Wateree generating stations, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC.

In December 2019, the EPA released proposed revisions to the ELG Rule that, if adopted, could extend the deadlines for compliance with certain standards at several facilities. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina provide rate recovery mechanisms that could substantially mitigate any such impacts for the regulated electric utilities.

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 2024 at an estimated cost of $10 million. In September 2018, DESC submitted an updated remediation work plan for one site to SCDHEC, which if approved, would increase costs by approximately $8 million. DESC expects to recover costs arising from the remediation work at all four sites through rate recovery mechanisms and as of December 31, 2019, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $23 million and are included in regulatory assets. Due to the uncertainty surrounding the other sites, DESC is unable to make an estimate of the potential financial statement impacts.

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 flexibilities in implementing their programs. In July 2018, the EPA promulgated the first phase of changes to the CCR rule. Until all phases of the CCR rule are promulgated, DESC cannot forecast potential incremental impacts or costs related to existing coal ash sites in connection with future implementation of the 2016 CCR legislation and reconsideration of 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 regulatory action is taken to incorporate the U.S. Court of Appeals for the D.C. Circuit’s decision, DESC is unable to make an estimate of the potential financial statement impacts associated with any future changes to the CCR rule in connection with the court’s remand.

Abandoned NND Project

DESC, on behalf of itself and as agent for Santee Cooper, entered into an engineering, construction and procurement contract with the Consortium in 2008 for the design and construction of the NND Project. DESC’s ownership share in the NND Project is 55%. Various difficulties were encountered in connection with the project. The ability of the Consortium 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 the Consortium on March 29, 2017 (see Contractor Bankruptcy Proceedings below) and were the subject of comprehensive analyses performed by SCANA, DESC and Santee Cooper.

Santee Cooper decided to suspend construction on the NND Project, on July 31, 2017, and in light of this decision and based on the results of SCANA and DESC’s analysis, SCANA and DESC 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 BLRA or through other means. This decision by SCANA became the focus of numerous legislative, regulatory and legal proceedings, and led to DESC recording pre-tax impairment charges in 2017 totaling approximately $1.1 billion (approximately $690 million after-tax). An additional pre-tax impairment loss was recorded in the first quarter of 2018 of approximately $4 million (approximately $3 million after-tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in the NND Project. These proceedings continued in 2018, and some of them remain unresolved and are described below under Claims and Litigation. On December 21, 2018, the South Carolina Commission issued the SCANA Merger Approval Order, which, among other things, limited recovery of capital costs related to the NND Project to $2.8 billion. As a result, DESC concluded that the NND Project capital costs exceeding the amounts established in the SCANA Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed, and recorded an impairment charge of $1.4 billion ($870 million after-tax) in the fourth quarter of 2018.

On January 2, 2018, SCANA and Dominion Energy entered into the SCANA Merger Agreement and sought the consents and approvals from governmental entities and the shareholders of SCANA required to consummate the merger. After all consents and approvals were obtained, the SCANA Combination was effective January 1, 2019.

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. In addition, a previously existing regulatory liability of $1.0 billion will be credited to customers over 20 years, 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.

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. As of December 31, 2019, such investment in these assets included $345 million within utility plant, net and $37 million within regulatory assets, which amount represents certain deferred operating 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 is addressed in a future rate proceeding. DESC believes these transmission capital and deferred operating costs are probable of recovery; however, if the South Carolina Commission were to disallow recovery of or a reasonable return on all or a portion of them, an impairment charge up to the disallowed costs may be required.

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 to events occurring before closing of the SCANA Combination. Dominion Energy intends to vigorously contest the lawsuits, claims and assessments which have been filed or initiated against DESC. 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 include reserves of $492 million and insurance receivables of $6 million included within other receivables at December 31, 2019. During the twelve months ended December 31, 2019, the Consolidated Statements of Comprehensive Loss includes charges of $590 million ($444 million after-tax), included within 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). In September 2018, the court certified this case as a class action. The plaintiffs allege, 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. The plaintiffs sought a declaratory judgment that DESC may not charge its customers for any past or continuing costs of the NND Project, sought to have SCANA and DESC’s assets frozen and all monies recovered from Toshiba and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the NND Project.

In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the DESC Ratepayer Case. The settlement agreement, contingent upon the closing of the SCANA Combination, provided that SCANA and DESC would establish an escrow account and proceeds from the escrow account would be distributed to the class members, 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 DESC Ratepayer Class estimate 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. The court held a fairness hearing on the settlement in May 2019. In June 2019, the court entered an order granting final approval of the settlement, which order became effective July 2019. In July 2019, DESC transferred $117 million representing the cash payment, plus accrued interest, to the plaintiffs. In addition, property with a net recorded cost of $42 million is in the process of being transferred to the plaintiffs in coordination with the court-appointed real estate trustee to satisfy the settlement agreement.

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 are substantially similar to those in the DESC Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the NND Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina which was denied. In December 2018, Santee Cooper filed its answer to the plaintiffs' fourth amended complaint and filed cross claims against DESC. In October 2019, Santee Cooper voluntarily consented to stay its cross claims against DESC pending the outcome of the trial of the underlying case. In November 2019, DESC removed the case to the U.S. District Court for the District of South Carolina. In December 2019, the plaintiffs and Santee Cooper filed a motion to remand the case to state court. In January 2020, the case was remanded to state court. In February 2020, the parties executed a preliminary settlement term sheet relating to this matter as well as the Luquire Case and the Glibowski Case described below. The proposed settlement is expected to be $520 million, of which DESC’s portion is $320 million. The parties are currently negotiating a settlement agreement based on the preliminary settlement term sheet that will be presented to the court for preliminary approval. This case is pending.

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 are similar to the Santee Cooper Ratepayer Case. In February 2020, the parties executed a preliminary settlement term sheet as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Glibowski Case. This case is pending.

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 alleges, 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. The DESC Ratepayer Class Action settlement described previously contemplates dismissal of claims by DESC ratepayers in this case against DESC, SCANA and their officers. In August 2019, the individual defendants filed motions to dismiss. In February 2020, the parties executed a preliminary settlement term sheet as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Luquire Case. This case is pending.

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 August 2018, the case was remanded back to the State Court of Common Pleas in Richland County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal was consolidated with another lawsuit regarding the SCANA Merger Agreement to which DESC is not a party. In June 2019, the U.S. Court of Appeals for the Fourth Circuit reversed the order remanding the case to state court. The case is pending in the U.S. District Court for the District of South Carolina.

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 are estimated to be as much as $100 million for 100% of the NND Project.

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. These cases are 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. This case is pending.

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. DESC has protested the proposed assessment, which remains pending.

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 addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and DESC. These matters are pending. SCANA and DESC are cooperating fully with the investigations, including responding to additional subpoenas and document requests; however, Dominion Energy cannot currently predict whether or to what extent SCANA or DESC may incur a material liability.

Other Litigation

In December 2018, arbitration proceedings commenced between DESC and Cameco Corporation related to a supply agreement signed in May 2008. This agreement provides the terms and conditions under which DESC agreed to purchase uranium hexafluoride from Cameco Corporation over a period from 2010 to 2020. Cameco Corporation alleges that DESC violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for the 2017 and 2018 delivery years. DESC denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement. This matter is pending.

In September 2019, a South Carolina state court jury awarded a judgment to the estate of Jose Larios in a wrongful death suit filed in June 2017 against DESC, of which DESC was apportioned $19 million. DESC holds general liability insurance coverage which is expected to provide payment for substantially all DESC’s liability in this matter. In October 2019, DESC filed a motion requesting a reduction in the judgment or, in the alternative, a new trial. In November 2019, DESC’s motion for a new trial was granted, setting aside the entire verdict amount. This matter is pending.

Contractor Bankruptcy Proceedings

Westinghouse’s Reorganization Plan became effective August 1, 2018. Initially, Westinghouse had projected that its Reorganization Plan would pay in full or nearly in full its pre-petition trade creditors, including several of the Westinghouse Subcontractors which have alleged non-payment by the Consortium for amounts owed for work performed on the NND Project and have filed liens on related property in Fairfield County, South Carolina. DESC is contesting approximately $285 million of such filed liens. Most of these asserted liens are “pre-petition” claims that relate to work performed by Westinghouse Subcontractors before the Westinghouse bankruptcy, although some of them are “post-petition” claims arising from work performed after the Westinghouse bankruptcy. It is possible that the Reorganization Plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant. In addition, payments under the Toshiba Settlement are subject to reduction if Westinghouse pays Westinghouse Subcontractors holding pre-petition liens directly. Under these circumstances, DESC and Santee Cooper, each in its pro rata share, would be required to make Citibank, N.A., which purchased the scheduled payments under the Toshiba Settlement, whole for reductions related to valid subcontractor and vendor pre-petition liens up to $60 million ($33 million for DESC's 55% share).

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 (i.e., post-petition) until termination of the IAA (the IAA Period). In the Westinghouse bankruptcy proceeding, deadlines were established for creditors of Westinghouse to assert the amounts owed to such creditors prior to the Westinghouse bankruptcy filing and during the IAA Period. Many of the Westinghouse Subcontractors have filed such claims. In December 2019, DESC and Santee Cooper entered into a confidential settlement agreement with W Wind Down Co LLC resolving claims relating to the IAA.

Further, some Westinghouse Subcontractors who have made claims against Westinghouse in the bankruptcy proceeding also filed against DESC and Santee Cooper in South Carolina state court for damages. The Westinghouse Subcontractor claims in South Carolina state court include common law claims for pre-petition work, IAA Period work, and work after the termination of the IAA. Many of these claimants have also asserted construction liens against the NND Project site. While DESC cannot be assured that it will not have any exposure on account of unpaid Westinghouse Subcontractor claims, which claims DESC is presently disputing, DESC believes it is unlikely that it will be required to make payments on account of such claims.

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 $14.0 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. As of December 31, 2019, 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, 2019, 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)	2020		2021		2022		2023		2024		Thereafter		Total
Purchased electric capacity(1)	$	59	$	58	$	57	$	57	$	57	$	661	$	949

(1) Includes affiliated amounts with certain solar facilities of $234 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 $37 million in 2019 and $24 million in 2018.

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Affiliated and Related Party Transactions (Schedule of Affiliated Transactions - Income Statement) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Purchases of fuel used in electric generation from affiliate		$ 43	$ 139	$ 127
Operating Revenues – Electric from sales to affiliate		4	5	5
Operating Revenues – Gas from sales to affiliate		1	1	1
Operating Expenses – Other taxes from affiliate		6	6	5
DESS [Member]
Related Party Transaction [Line Items]
Direct and allocated costs from services company affiliate	[1]	297	283	303
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Purchases of coal from affiliate		121	150	162
Sales of coal to affiliate		$ 120	$ 149	$ 161

[1] Includes capitalized expenditures of $53 million, $41 million and $82 million for the years ended December 31, 2019, 2018 and 2017, respectively.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Schedule of Weighted Average Depreciation Rates

The composite weighted average depreciation rates for utility plant by function were as follows:

	2019			2018
Generation		2.50	%		2.61	%
Transmission		2.57	%		2.74	%
Distribution		2.41	%		2.41	%
Storage		2.74	%		2.71	%
General and other		3.22	%		3.18	%

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Utility Plant and Nonutility Property - Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Property Plant And Equipment [Line Items]
Gross nonutility property	$ 75	$ 73
Generation
Property Plant And Equipment [Line Items]
Utility plant in service	5,765	5,751
Transmission
Property Plant And Equipment [Line Items]
Utility plant in service	1,905	1,758
Distribution
Property Plant And Equipment [Line Items]
Utility plant in service	4,685	4,456
Storage
Property Plant And Equipment [Line Items]
Utility plant in service	73	74
General and other
Property Plant And Equipment [Line Items]
Utility plant in service	549	535
Intangible
Property Plant And Equipment [Line Items]
Utility plant in service	231	229
Construction Work In Progress
Property Plant And Equipment [Line Items]
Utility plant in service	339	350
Nuclear Fuel
Property Plant And Equipment [Line Items]
Utility plant in service	608	611
Total Gross Utility Plant
Property Plant And Equipment [Line Items]
Utility plant in service	$ 14,155	$ 13,764

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2019

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

8.  DERIVATIVE FINANCIAL INSTRUMENTS

See Note 2 for the Company’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 the Company’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 DESC 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. DESC’s derivatives with credit-related contingent provisions that were in a liability position were fully collateralized with cash at December 31, 2019 and 2018.

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:

	December 31, 2019								December 31, 2018
			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	$	—	$	19	$	—	$	11	$	—	$	11	$	—
Total derivatives	$	19	$	—	$	19	$	—	$	11	$	—	$	11	$	—

Volumes

The following table presents the volume of derivative activity at December 31, 2019. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions.

	Current		Noncurrent
Interest rate(1)	$	—	$	71,400,000

(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, 2019
Current Liabilities
Interest rate	$	1	$	1	$	2
Total current derivative liabilities(1)		1		1		2
Noncurrent Liabilities
Interest rate		11		6		17
Total noncurrent derivative liabilities(2)		11		6		17
Total derivative liabilities	$	12	$	7	$	19
At December 31, 2018
Current Liabilities
Interest rate	$	1	$	—	$	1
Total current derivative liabilities(1)		1		—		1
Noncurrent Liabilities
Interest rate		7		3		10
Total noncurrent derivative liabilities(2)		7		3		10
Total derivative liabilities	$	8	$	3	$	11

(1) Current derivative liabilities are presented in other current liabilities in the Consolidated Balance Sheets.

(2) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in the 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)	Gain (loss) Reclassified from Deferred Accounts into Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(1)
Year Ended December 31, 2019
Derivative type and location of gains (losses):
Interest rate(2)	$	—		$	1
Total	$	—		$	1
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Interest rate(2)	$	(1	)	$	1
Total	$	(1	)	$	1
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Interest rate(2)	$	(2	)	$	(2	)
Total	$	(2	)	$	(2	)

(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 Loss.

(2) Amounts recorded in DESC’s Consolidated Statements of Comprehensive Loss are classified in interest charges.

Derivatives Not designated as Hedging Instruments

(millions)	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2019			2018			2017
Derivative type and location of gains (losses):
Interest rate contracts:
Interest charges	$	(1	)	$	(2	)	$	(3	)
Other income		—			115			—
Impairment loss		—			—			(173	)
Total	$	(1	)	$	113		$	(176	)

(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 Loss.

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Operating Revenue

12 Months Ended

Dec. 31, 2019

Revenues [Abstract]

Operating Revenue

4.  OPERATING REVENUE

The Company’s operating revenue, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, consists of the following:

Year Ended December 31,	2019				2018
(millions)	Electric		Gas		Electric		Gas
Customer class:
Residential	$	669	$	194	$	1,054	$	208
Commercial		507		111		744		117
Industrial		224		81		385		92
Other		116		18		132		17
Revenues from contracts with customers		1,516		404		2,315		434
Other revenues		9		—		12		1
Total Operating Revenues	$	1,525	$	404	$	2,327	$	435

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 $9 million and $4 million at December 31, 2019 and 2018, respectively. For the years ended December 31, 2019 and 2018, DESC recognized revenue of $3 million and $4 million 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)	2019			2018
Beginning balance, January 1	$	15		$	16
Amortization		(2	)		(1	)
Ending balance, December 31	$	13		$	15

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Operating Segments (Tables)

12 Months Ended

Dec. 31, 2019

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)
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
Total assets (billions)		14.3		—			14.3
2018
External revenue	$	2,763	$	(1	)	$	2,762
Depreciation and amortization		327		—			327
Interest and related charges		306		(3	)		303
Income tax expense (benefit)		98		(514	)		(416	)
Comprehensive income (loss) available (attributable) to    common shareholder		304		(917	)		(613	)
Capital expenditures		633		—			633
Total assets (billions)		15.0		—			15.0
2017
External revenue	$	3,070	$	—		$	3,070
Depreciation and amortization		312		—			312
Interest and related charges		288		—			288
Income tax expense (benefit)		257		(428	)		(171	)
Comprehensive income (loss) available (attributable) to    common shareholder		505		(690	)		(185	)
Capital expenditures		928		—			928

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Long-Term and Short-Term Debt (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Schedule of Debt

Long-term debt by type with related weighted-average coupon rates and maturities at December 31, 2019 and 2018 is as follows:

At December 31,	2019 Weighted- average Coupon(1)			2019			2018
(millions, except percentages)
DESC:
First Mortgage Bonds, 3.22% to 6.625%, due 2021 to 2065(2)		5.42	%	$	3,267		$	4,990
Tax-Exempt Financings:
Variable rate due 2038		1.65	%		35			35
3.625% and 4.00%, due 2028 and 2033		3.90	%		54			54
Other		3.69	%		1			—
GENCO:
Tax-Exempt Financing, variable rate due 2038		1.65	%		33			33
Secured Senior Notes, 5.49% due 2024(3)					—			40
Affiliated note, 3.05% due 2024		3.05	%		230			—
Total principal					3,620			5,152
Securities due within one year					—			(14	)
Unamortized discount, premium and debt issuance costs, net					(32	)		(36	)
Finance leases					20			30
Total long-term debt				$	3,608		$	5,132

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2019.

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, 2019, were as follows:

(millions, except percentages)	2020		2021			2022		2023		2024			Thereafter			Total
First Mortgage Bonds	$	—	$	33		$	—	$	—	$	—		$	3,234		$	3,267
Tax-Exempt Financings		—		—			—		—		—			122			122
Other		—		—			—		—		230			1			231
Total	$	—	$	33		$	—	$	—	$	230		$	3,357		$	3,620
Weighted-average coupon				3.25	%						3.05	%		5.34	%

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, 2019	$	1,000	$	—	$	—

(millions)	Facility Limit(1)		Outstanding Commercial Paper		Outstanding Letters of Credit
At December 31, 2018	$	1,200	$	73	$	—

(1) Included $500 million related to Fuel Company. In February 2019, Fuel Company's commercial paper program and its credit facility were terminated.

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2019

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)	2019			2018
Beginning balance	$	541		$	529
Liabilities settled		(29	)		(15	)
Accretion expense		23			23
Revisions in estimated cash flows(1)		(46	)		4
Ending balance	$	489		$	541

(1)   The decrease in 2019 reflects a change in the estimated timing of cash flows for interim pipeline replacements and DOE recoveries.

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Long-Term and Short-Term Debt (Schedule of Debt) (Detail) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Weighted-average coupon rate			3.82%
Total principal		$ 3,620	$ 5,152
Securities due within one year		0	(14)
Unamortized discount, premium and debt issuance costs, net		(32)	(36)
Finance leases		27
Total long-term debt		3,608	5,132
First Mortgage Bonds
Debt Instrument [Line Items]
Total principal		$ 3,267
First Mortgage Bonds | DESC
Debt Instrument [Line Items]
Weighted-average coupon rate	[1],[2]	5.42%
Total principal	[1]	$ 3,267	4,990
Tax Exempt Financings Variable Rate Due 2038 | DESC
Debt Instrument [Line Items]
Weighted-average coupon rate	[2]	1.65%
Total principal		$ 35	35
Tax Exempt Financings Variable Rate Due 2038 | Genco
Debt Instrument [Line Items]
Weighted-average coupon rate	[2]	1.65%
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	[2]	3.90%
Total principal		$ 54	54
Other Debt
Debt Instrument [Line Items]
Total principal		$ 231
Other Debt | DESC
Debt Instrument [Line Items]
Weighted-average coupon rate	[2]	3.69%
Total principal		$ 1	0
5.49% Senior Secured Note Due 2024 | Genco
Debt Instrument [Line Items]
Total principal		$ 0	40
3.05% Affiliated Note Due 2024 | Genco
Debt Instrument [Line Items]
Weighted-average coupon rate	[2],[3]	3.05%
Total principal	[3]	$ 230	0
Finance Lease
Debt Instrument [Line Items]
Finance leases		$ 20	$ 30

[1] In February, March and September 2019, DESC purchased certain of its first mortgage bonds having an aggregate purchase price of $1.8 billion pursuant to tender offers. The February and March tender offers expired in the first quarter of 2019 and the September tender offer expired in the third quarter of 2019

[2] Represents weighted-average coupon rates for debt outstanding as of December 31, 2019.

[3] In May 2019, GENCO redeemed its 5.49% senior secured notes due in 2024 at the remaining principal outstanding of $33 million plus accrued interest

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating revenue from contracts with customers		$ 4	$ 5	$ 0
Total Operating Revenues	[1]	1,929	2,762	$ 3,070
Electric Operations
Operating revenue from contracts with customers		1,516	2,315
Other revenues		9	12
Total Operating Revenues		1,525	2,327
Gas Distribution
Operating revenue from contracts with customers		404	434
Other revenues		0	1
Total Operating Revenues		404	435
Residential | Electric Operations
Operating revenue from contracts with customers		669	1,054
Residential | Gas Distribution
Operating revenue from contracts with customers		194	208
Commercial | Electric Operations
Operating revenue from contracts with customers		507	744
Commercial | Gas Distribution
Operating revenue from contracts with customers		111	117
Industrial | Electric Operations
Operating revenue from contracts with customers		224	385
Industrial | Gas Distribution
Operating revenue from contracts with customers		81	92
Other | Electric Operations
Operating revenue from contracts with customers		116	132
Other | Gas Distribution
Operating revenue from contracts with customers		$ 18	$ 17

[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) - USD ($)		Dec. 31, 2019	Dec. 31, 2018
Current Joint Revolving Credit Facility
Debt Instrument [Line Items]
Facility limit		$ 1,000,000,000
Outstanding Commercial Paper		0
Outstanding Letters of Credit		$ 0
Previous Joint Revolving Credit Facility
Debt Instrument [Line Items]
Facility limit	[1]		$ 1,200,000,000
Outstanding Commercial Paper			73,000,000
Outstanding Letters of Credit			$ 0

[1] Included $500 million related to Fuel Company. In February 2019, Fuel Company's commercial paper program and its credit facility were terminated

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Employee Benefit Plans (Pension Plan Asset Allocation and Target Allocation) (Detail)	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit Plan, Plan asset		64.00%	55.00%
Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit Plan, Plan asset		35.00%	34.00%
Cash
Defined Benefit Plan Disclosure [Line Items]
Defined benefit Plan, Plan asset		1.00%	0.00%
Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit Plan, Plan asset		0.00%	11.00%
Scenario Forecast | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit Plan, Target allocation plan asset	45.00%
Scenario Forecast | Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit Plan, Target allocation plan asset	50.00%
Scenario Forecast | Cash
Defined Benefit Plan Disclosure [Line Items]
Defined benefit Plan, Target allocation plan asset	5.00%

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Asset Retirement Obligations (Narrative) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, other conditional obligations	$ 312
Assets held in trust, nuclear decommissioning	214	$ 190
Asset retirement obligation, nuclear decommissioning	$ 177

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Employee Benefit Plans and Equity Compensation Plan (Significant Assumptions Used to Determine Benefit Obligations) (Detail)	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Dec. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Annual discount rate used to determine benefit obligation	3.47%	3.57%	4.07%	4.35%
Assumed annual rate of future salary increases for projected benefit obligation	3.00%			3.00%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Annual discount rate used to determine benefit obligation	3.52%		4.08%	4.38%

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Current year actuarial (gain) loss	$ (1)	$ 1	$ 0
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Current year actuarial (gain) loss	$ 1	$ (1)	$ 1

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Fair Value Measurements, Including Derivatives

12 Months Ended

Dec. 31, 2019

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. 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 their 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 interest rate assets and liabilities. DESC’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. 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. The inputs and assumptions used in measuring fair value for interest rate derivative contracts include the following:

• 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.

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.

Recurring Fair Value Measurements

Fair value disclosures for assets held in DESC’s pension and other postretirement benefit plans are presented in Note 11.

The following table presents DESC’s 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, 2019
Liabilities
Interest rate	$	—	$	19	$	—	$	19
Total liabilities	$	—	$	19	$	—	$	19
At December 31, 2018
Liabilities
Interest rate	$	—	$	11	$	—	$	11
Total liabilities	$	—	$	11	$	—	$	11

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,	2019				2018
(millions)	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(2)
Long-term debt(3)	$	3,358	$	4,262	$	5,146	$	5,470
Affiliated long-term debt		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) Fair value is estimated based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. 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.

(3) 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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Equity

12 Months Ended

Dec. 31, 2019

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 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, the Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At both December 31, 2019 and 2018, retained earnings of $115 million were restricted by this requirement as to payment of cash dividends on DESC’s common stock. 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, 2019, DESC’s retained earnings are below the balance established by the Federal Power Act as a reserve on earnings attributable to hydroelectric generation plants. As a result, DESC is prohibited from the payment of dividends without regulatory approval until the balance of its retained earnings increases. 

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Operating Revenue (Tables)

12 Months Ended

Dec. 31, 2019

Revenue Recognition And Deferred Revenue [Abstract]

Operating Revenue Subsequent to the Adoption of Guidance for Revenue Recognition from Contracts with Customers

The Company’s operating revenue, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, consists of the following:

Year Ended December 31,	2019				2018
(millions)	Electric		Gas		Electric		Gas
Customer class:
Residential	$	669	$	194	$	1,054	$	208
Commercial		507		111		744		117
Industrial		224		81		385		92
Other		116		18		132		17
Revenues from contracts with customers		1,516		404		2,315		434
Other revenues		9		—		12		1
Total Operating Revenues	$	1,525	$	404	$	2,327	$	435

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)	2019			2018
Beginning balance, January 1	$	15		$	16
Amortization		(2	)		(1	)
Ending balance, December 31	$	13		$	15

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Fair Value Measurements, Including Derivatives (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Schedule of Liabilities Measured at Fair Value on Recurring Basis

The following table presents DESC’s 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, 2019
Liabilities
Interest rate	$	—	$	19	$	—	$	19
Total liabilities	$	—	$	19	$	—	$	19
At December 31, 2018
Liabilities
Interest rate	$	—	$	11	$	—	$	11
Total liabilities	$	—	$	11	$	—	$	11

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,	2019				2018
(millions)	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(2)
Long-term debt(3)	$	3,358	$	4,262	$	5,146	$	5,470
Affiliated long-term debt		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) Fair value is estimated based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. 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.

(3) 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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Leases (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Schedule Of Lease Assets and Liabilities Recorded in Consolidated Balance Sheets

At December 31, 2019, DESC had the following lease assets and liabilities recorded in the Consolidated Balance Sheets:

At December 31,	2019
(millions)
Lease assets:
Operating lease assets(1)	$	23
Finance lease assets(2)		26
Total lease assets	$	49
Lease liabilities:
Operating lease - current(3)	$	3
Operating lease - noncurrent(4)		20
Finance lease - current(5)		7
Finance lease - noncurrent		20
Total lease liabilities	$	50

(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 $24 million of accumulated amortization at December 31, 2019.

(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 current portion of long-term debt in the Consolidated Balance Sheets.

Summary of Total Lease Cost

For the year ended December 31, 2019, total lease cost consisted of the following:

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

Cash Paid for Amounts Included in Measurement of Lease Liabilities

For the year ended December 31, 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,	2019
(millions)
Operating cash flows from finance leases	$	1
Operating cash flows from operating leases		3
Financing cash flows from finance leases		7

Summary of Weighted Average Remaining Lease Term And Discount Rate for Operating and Finance Leases

At December 31, 2019, the weighted average remaining lease term and weighted average discount rate for finance and operating leases were as follows:

At December 31,	2019
Weighted average remaining lease term - finance leases	5 years
Weighted average remaining lease term - operating leases	18 years
Weighted average discount rate - finance leases		2.94	%
Weighted average discount rate - operating leases		3.94	%

Schedule of Maturity Analysis of Operating and Finance Lease Liabilities

Lease liabilities have the following scheduled maturities:

(millions)	Operating			Finance
2020	$	4		$	8
2021		3			7
2022		2			5
2023		2			4
2024		1			2
After 2024		23			3
Total undiscounted lease payments		35			29
Present value adjustment		(12	)		(2	)
Present value of lease liabilities	$	23		$	27

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Long-Term and Short-Term Debt (Schedule of Line of Credit Facilities) (Parenthetical) (Detail)	Dec. 31, 2018 USD ($)
Fuel Company
Debt Instrument [Line Items]
Facility limit	$ 500,000,000

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Long-Term and Short-Term Debt (Schedule of Debt) (Parenthetical) (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	May 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Redemption of remaining principal outstanding plus accrued interest		$ 1,890	$ 825	$ 12
DESC
Debt Instrument [Line Items]
Aggregate purchase price of first mortgage bonds		$ 1,800
First Mortgage Bonds | Minimum [Member] | DESC
Debt Instrument [Line Items]
Debt Instrument, Maturity Year		2021
Debt instrument, interest rate		3.22%
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%
5.49% Senior Secured Note Due 2024 | Genco
Debt Instrument [Line Items]
Debt Instrument, Maturity Year		2024
Debt instrument, interest rate		5.49%
Redemption of remaining principal outstanding plus accrued interest	$ 33
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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Operating Revenue (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disaggregation Of Revenue [Line Items]
Contract liability balances	$ 9	$ 4
Revenue recognized from contract liability balances	$ 3	$ 4
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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Employee Benefit Plans (Change in Fair Value of Plan Assets) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Compensation And Retirement Disclosure [Abstract]
Fair value of plan assets, January 1	$ 677	$ 781
Actual return (loss) on plan assets	149	(43)
Benefits paid	(21)	(61)
Settlements	(80)	0
Fair value of plan assets, December 31	$ 725	$ 677

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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, 2019		Dec. 31, 2018
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Long-term debt	[1]	$ 3,358		$ 5,146
Affiliated long-term debt		230		0
Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Long-term debt	[1]	4,262	[2]	5,470	[3]
Affiliated long-term debt		$ 230	[2]	$ 0	[3]

[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.

[3] Fair value is estimated based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. 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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Employee Benefit Plans and Equity Compensation Plan (Changes in Benefit Obligations) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation, January 1	$ 732	$ 793
Service cost	15	17	$ 18
Interest cost	28	29	32
Plan participants’ contributions	0	0
Actuarial (gain) loss	47	(46)
Benefits paid	(21)	(19)
Settlements	(80)	(42)
Curtailment	6	0
Amounts funded to parent	0	0
Benefit obligation, December 31	727	732	793
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation, January 1	187	217
Service cost	3	4	4
Interest cost	9	8	9
Plan participants’ contributions	1	1
Actuarial (gain) loss	22	(31)
Benefits paid	(13)	(11)
Settlements	0	0
Curtailment	3	0
Amounts funded to parent	2	(1)
Benefit obligation, December 31	$ 214	$ 187	$ 217

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Employee Benefit Plans (Components of Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 15	$ 17	$ 18
Interest cost	28	29	32
Expected return on assets	(40)	(48)	(46)
Prior service cost amortization	0	0	1
Amortization of actuarial losses	11	11	14
Settlement loss	16	0	0
Curtailment	6	0	0
Net periodic benefit cost	36	9	19
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	3	4	4
Interest cost	9	8	9
Amortization of actuarial losses	0	0	1
Curtailment	3	0	0
Net periodic benefit cost	$ 15	$ 12	$ 14

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Utility Plant and Nonutility Property (Tables)

12 Months Ended

Dec. 31, 2019

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, 2019 and 2018 were as follows:

At December 31,	2019		2018
(millions)
Gross utility plant:
Generation	$	5,765	$	5,751
Transmission		1,905		1,758
Distribution		4,685		4,456
Storage		73		74
General and other		549		535
Intangible		231		229
Construction work in progress		339		350
Nuclear fuel		608		611
Total gross utility plant	$	14,155	$	13,764
Gross nonutility property	$	75	$	73

Schedule of Jointly Owned Utility Plants

At December 31,	2019			2018
	Summer Unit 1			Summer Unit 1
Percent owned	66.7%			66.7%
Plant in service	$	1.4	billion	$	1.5	billion
Accumulated depreciation	$	684	million	$	644	million
Construction work in progress	$	79	million	$	128	million

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Nature of Operations (Narrative) (Detail) - Segment	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Number of primary operating segments	1	1

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Rate and Other Regulatory Matters (Schedule of Regulatory Assets) (Detail) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets
Regulatory assets, current		$ 271	$ 224
Regulatory assets, noncurrent		3,892	4,060
Total regulatory assets		4,163	4,284
NND Project Costs [Member]
Regulatory Assets
Regulatory assets, current	[1]	138	127
Regulatory assets, noncurrent	[1]	2,503	2,641
Deferred Employee Benefit Plan Costs [Member]
Regulatory Assets
Regulatory assets, current	[2]	13	16
Regulatory assets, noncurrent	[2]	196	256
Other Unrecovered Plant [Member]
Regulatory Assets
Regulatory assets, current	[3]	14	14
Regulatory assets, noncurrent	[3]	69	79
Demand Side Management Programs [Member]
Regulatory Assets
Regulatory assets, current	[4]	17	14
Regulatory assets, noncurrent	[4]	54	51
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory assets, current	[5]	28	0
Regulatory assets, noncurrent	[5]	293	380
Cost Of Fuel Under-collections [Member]
Regulatory Assets
Regulatory assets, current	[6]	13	13
Other Regulatory Assets [Member]
Regulatory Assets
Regulatory assets, current		48	40
Regulatory assets, noncurrent	[7]	110	123
Cost of Reacquired Debt [Member]
Regulatory Assets
Regulatory assets, noncurrent	[8],[9]	259	14
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets
Regulatory assets, noncurrent	[10]	305	442
Environmental Remediation Costs [Member]
Regulatory Assets
Regulatory assets, noncurrent	[11]	22	24
Deferred Storm Damage Costs [Member]
Regulatory Assets
Regulatory assets, noncurrent	[12]	44	35
Deferred Transmission Operating Costs [Member]
Regulatory Assets
Regulatory assets, noncurrent	[13]	$ 37	$ 15

[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 over the units' previous estimated remaining useful lives through 2025. 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 five 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-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] Costs of the reacquisition of debt are deferred and amortized as interest expense over the would-be remaining life of the reacquired debt or over the life of the replacement debt if refinanced. The reacquired debt had a weighted-average life of approximately 26 years as of December 31, 2019.

[9] During 2019, DESC purchased certain of its first mortgage bonds as discussed in Note 6. As a result of these transactions, DESC incurred net costs, including write-offs of unamortized discount, premium and debt issuance costs, of $270 million.

[10] 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.

[11] 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 16 years. See Note 12 for more information.

[12] Represents storm restoration costs for which DESC expects to receive future recovery through customer rates.

[13] Includes deferred depreciation and property taxes associated with certain transmission assets for which DESC expects recovery from customers through future rates. See Note 12 for more information.

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Leases (Cash Paid for Amounts Included in Measurement of Lease Liabilities) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Leases [Abstract]
Operating cash flows from finance leases	$ 1
Operating cash flows from operating leases	3
Financing cash flows from finance leases	$ 7

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Derivative Financial Instruments (Schedule of Volume of Derivative Activity) (Detail)	Dec. 31, 2019 USD ($)	[1]
Interest Rate Swap Current [Member]
Derivative [Line Items]
Interest rate	$ 0
Interest Rate Swap Noncurrent [Member]
Derivative [Line Items]
Interest rate	$ 71,400,000

[1] Maturity is determined based on final settlement period.

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Income Taxes (Schedule of Deferred Income Taxes) (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred income taxes:
Total deferred income tax assets	$ 1,258	$ 971
Total deferred income tax liabilities	1,868	1,960
Total net deferred income tax liabilities	610	989
Depreciation method and plant basis differences	1,007	998
Excess deferred income taxes	(231)	(148)
Unrecovered nuclear plant cost	553	584
DESC rate refund	(169)	(1)
Toshiba settlement	(219)	(231)
Nuclear decommissioning	(43)	(9)
Deferred state income taxes	200	296
Federal benefit of deferred state income taxes	(42)	(62)
Deferred fuel, purchased energy and gas costs	7	1
Pension benefits	46	46
Other postretirement benefits	(35)	(35)
Loss and credit carryforwards	(391)	(520)
Other	(73)
Other		70
Deferred Investment Tax Credits-Regulated Operations	19	19
Deferred income taxes and investment tax credits	$ 629	$ 1,008

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Commitments and Contingencies (Schedule of Long-Term Purchase Agreements) (Parenthetical) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Solar Affiliates [Member]
Long Term Purchase Commitment [Line Items]
Purchases from affiliates	$ 234

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Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement Of Cash Flows [Abstract]
Cash paid for interest, capitalized interest	$ 5	$ 9	$ 15
Restricted cash and equivalents	0	0	0
Financing leases	4
Operating leases	$ 8
Capital leases		$ 8	$ 8

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Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Utility plant, net	$ 8,915	$ 8,783
Receivables, customer, allowance for uncollectible accounts	3	4
Total current assets	1,118	1,689
Total deferred debits and other assets	$ 3,985	$ 4,228
Common stock, par value	$ 0	$ 0
Common stock, shares outstanding	40.3	40.3
Variable Interest Entity, Primary Beneficiary [Member]
Utility plant, net	$ 727	$ 711
Total current assets	143	96
Total deferred debits and other assets	$ 32	$ 34

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Rate and Other Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities

At December 31,	2019		2018
(millions)
Regulatory assets:
NND Project costs(1)	$	138		127
Deferred employee benefit plan costs(2)		13		16
Other unrecovered plant(3)		14		14
DSM programs(4)		17		14
AROs(5)		28		—
Cost of fuel under-collections(6)		13		13
Other		48		40
Regulatory assets - current		271		224
NND Project costs(1)		2,503		2,641
AROs(5)		293		380
Cost of reacquired debt(7)(8)		259		14
Deferred employee benefit plan costs(2)		196		256
Deferred losses on interest rate derivatives(9)		305		442
Other unrecovered plant(3)		69		79
DSM programs(4)		54		51
Environmental remediation costs(10)		22		24
Deferred storm damage costs(11)		44		35
Deferred transmission operating costs(12)		37		15
Other(13)		110		123
Regulatory assets - noncurrent		3,892		4,060
Total regulatory assets	$	4,163	$	4,284
Regulatory liabilities:
Monetization of guaranty settlement(14)	$	67		61
Income taxes refundable through future rates(15)		16		52
Reserve for refunds to electric utility customers(16)		143		—
Other		30		13
Regulatory liabilities - current		256		126
Monetization of guaranty settlement(14)		970		1,037
Income taxes refundable through future rates(15)		948		607
Asset removal costs(17)		552		541
Deferred gains on interest rate derivatives(9)		71		75
Reserve for refunds to electric utility customers(16)		656		—
Other		13		4
Regulatory liabilities – noncurrent		3,210		2,264
Total regulatory liabilities	$	3,466	$	2,390

(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 over the units' previous estimated remaining useful lives through 2025. 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 five 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-collected from customers pursuant to the cost of fuel components approved by the South Carolina Commission.

(7) Costs of the reacquisition of debt are deferred and amortized as interest expense over the would-be remaining life of the reacquired debt or over the life of the replacement debt if refinanced. The reacquired debt had a weighted-average life of approximately 26 years as of December 31, 2019.

(8)   During 2019, DESC purchased certain of its first mortgage bonds as discussed in Note 6. As a result of these transactions, DESC incurred net costs, including write-offs of unamortized discount, premium and debt issuance costs, of $270 million.

(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 16 years. See Note 12 for more information.

(11) Represents storm restoration costs for which DESC expects to receive future recovery through customer rates.

(12) Includes deferred depreciation and property taxes associated with certain transmission assets for which DESC expects recovery from customers through future rates. See Note 12 for more information.

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

(14) 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.

(15) 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.

(16) 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 in connection with the SCANA Merger Approval Order. See Note 12 for more information.

(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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Affiliated and Related Party Transactions (Schedule of Affiliated Transactions - Income Statement) (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
DESS [Member]
Related Party Transaction [Line Items]
Capitalized expenditures	$ 53	$ 41	$ 82

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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, 2019	Dec. 31, 2018
Utility Plant And Non Utility Property [Line Items]
Amounts due from Santee Cooper for share of direct expenses			$ 119	$ 68
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			$ 50	$ 46
NND Project | Summer
Utility Plant And Non Utility Property [Line Items]
Percentage of ownership interest		55.00%
Santee Cooper | NND Project | Summer
Utility Plant And Non Utility Property [Line Items]
Percentage of ownership interest		11.70%
Ownership interest purchased		$ 8

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Other Income (Expense), Net

12 Months Ended

Dec. 31, 2019

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,	2019			2018			2017
(millions)
Revenues from contracts with customers	$	4		$	5		$	—
Other income		19			141			45
Other expense		(57	)		(28	)		(32	)
Allowance for equity funds used during construction		1			11			15
Other income (expense), net	$	(33	)	$	129		$	28

The recording of revenue from contracts with customers within other income (expense) arose upon the adoption of related accounting guidance described in Note 1 and Note 4, and as permitted, periods prior to adoption have not been restated. Other income in 2018 includes gains from the settlement of interest rate derivatives of $115 million (see Note 8). Non-service cost components of pension and other postretirement benefits are included in other expense.

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Leases

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Leases

13. LEASES

At December 31, 2019, DESC had the following lease assets and liabilities recorded in the Consolidated Balance Sheets:

At December 31,	2019
(millions)
Lease assets:
Operating lease assets(1)	$	23
Finance lease assets(2)		26
Total lease assets	$	49
Lease liabilities:
Operating lease - current(3)	$	3
Operating lease - noncurrent(4)		20
Finance lease - current(5)		7
Finance lease - noncurrent		20
Total lease liabilities	$	50

(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 $24 million of accumulated amortization at December 31, 2019.

(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 current portion of long-term debt in the Consolidated Balance Sheets.

For the year ended December 31, 2019, total lease cost consisted of the following:

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

For the year ended December 31, 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,	2019
(millions)
Operating cash flows from finance leases	$	1
Operating cash flows from operating leases		3
Financing cash flows from finance leases		7

At December 31, 2019, the weighted average remaining lease term and weighted average discount rate for finance and operating leases were as follows:

At December 31,	2019
Weighted average remaining lease term - finance leases	5 years
Weighted average remaining lease term - operating leases	18 years
Weighted average discount rate - finance leases		2.94	%
Weighted average discount rate - operating leases		3.94	%

Lease liabilities have the following scheduled maturities:

(millions)	Operating			Finance
2020	$	4		$	8
2021		3			7
2022		2			5
2023		2			4
2024		1			2
After 2024		23			3
Total undiscounted lease payments		35			29
Present value adjustment		(12	)		(2	)
Present value of lease liabilities	$	23		$	27