10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2018

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
1-8809 1-3375	SCANA Corporation (a South Carolina corporation) South Carolina Electric & Gas Company (a South Carolina corporation) 100 SCANA Parkway, Cayce, South Carolina 29033 (803) 217-9000	57-0784499 57-0248695

Securities registered pursuant to Section 12(b) of the Act:	Securities registered pursuant to Section 12(g) of the Act:
SCANA Corporation:	South Carolina Electric & Gas Company:
Common stock, without par value	Series A Nonvoting Preferred Shares

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

SCANA Corporation x         South Carolina Electric & Gas Company x

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

SCANA Corporation o         South Carolina Electric & Gas Company o

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, and (2) has been subject to such filing requirements for the past 90 days.

        SCANA Corporation Yes x No o     South Carolina Electric & Gas Company Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months.

SCANA Corporation Yes x No o     South Carolina Electric & Gas Company Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

    SCANA Corporation x         South Carolina Electric & Gas Company x

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," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

SCANA Corporation	Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o	Emerging growth company o
South Carolina Electric & Gas Company	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o	Emerging growth company o

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.

         SCANA Corporation o         South Carolina Electric & Gas Company o

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

SCANA Corporation Yes o No x      South Carolina Electric & Gas Company Yes o No x

Effective January 1, 2019, Dominion Energy, Inc. became the sole holder of SCANA Corporation common stock. The aggregate market value of SCANA Corporation common stock held by non-affiliates was approximately $5.5 billion based on the closing price of SCANA Corporation's common stock as reported on the New York Stock Exchange as of the last day of SCANA Corporation's most recently completed second fiscal quarter. SCANA Corporation is the sole holder of South Carolina Electric & Gas Company common stock. At February 15, 2019, SCANA Corporation had 100 shares of common stock outstanding and South Carolina Electric & Gas Company had 40,296,147 shares of common stock outstanding.

This combined Form 10-K represents separate filings by SCANA Corporation and South Carolina Electric & Gas Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. South Carolina Electric & Gas Company makes no representation as to information relating to SCANA Corporation or its subsidiaries (other than South Carolina Electric & Gas Company and its consolidated affiliates).

SCANA CORPORATION AND SOUTH CAROLINA ELECTRIC & GAS COMPANY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND (b) OF FORM 10-K AND ARE FILING THIS FORM 10-K UNDER THE REDUCED DISCLOSURE FORMAT.

			Page
Cautionary Statement Regarding Forward-Looking Information			3
Definitions			4
PART I
Item 1.	Business		5
Item 1A.	Risk Factors		6
Item 1B.	Unresolved Staff Comments		14
Item 2.	Properties		14
Item 3.	Legal Proceedings		14
Item 4.	Mine Safety Disclosures		14
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		14
Item 6.	Selected Financial Data		15
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		19
Item 8.	Financial Statements and Supplementary Data		23
	SCANA Corporation and Subsidiaries		23
		Report of Independent Registered Public Accounting Firm
		Consolidated Balance Sheets
		Consolidated Statements of Operations
		Consolidated Statements of Comprehensive Income (Loss)
		Consolidated Statements of Cash Flows
		Consolidated Statements of Changes in Common Equity
	South Carolina Electric & Gas Company and Affiliates		30
		Report of Independent Registered Public Accounting Firm
		Consolidated Balance Sheets
		Consolidated Statements of Comprehensive Income (Loss)
		Consolidated Statements of Cash Flows
		Consolidated Statements of Changes in Common Equity
	Notes to Consolidated Financial Statements		36
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		88
Item 9A.	Controls and Procedures		88
Item 9B.	Other Information		90
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		90
Item 11.	Executive Compensation		90
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		90
Item 13.	Certain Relationships and Related Transactions, and Director Independence		91
Item 14.	Principal Accounting Fees and Services		91
PART IV
Item 15.	Exhibits, Financial Statement Schedules		91
Item 16.	Form 10-K Summary		92
Exhibit Index			93
Signatures			95

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Statements included in this Annual Report on Form 10-K which are not statements of historical fact are intended to be, and are hereby identified as, “forward-looking statements” for purposes of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  Forward-looking statements include, but are not limited to, statements concerning the recovery of Nuclear Project abandonment costs, customer growth, environmental regulations and expenditures, projections for pension fund contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules and estimated capital and other expenditures.  In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “forecasts,” “plans,” “targets,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or “continue” or the negative of these terms or other similar terminology.  Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements due to the information being of a preliminary nature and subject to further and/or continuing review and adjustment. Other important factors that could cause such material differences include, but are not limited to, the following:

(1) the ability of SCE&G to recover through rates the costs expended on the Nuclear Project, and a reasonable return on those costs, under the Merger Approval Order and the abandonment provisions of the BLRA or through other means; (2) uncertainties relating to the bankruptcy filing by WEC and WECTEC; (3) further changes in tax laws and realization of tax benefits and credits, and the ability to realize or maintain tax credits and deductions, particularly in light of the abandonment of the Nuclear Project; (4) legislative and regulatory actions, particularly changes related to electric and gas services, rate regulation, regulations governing electric grid reliability and pipeline integrity, environmental regulations including any imposition of fees or taxes on carbon emitting generating facilities, the BLRA, and any actions involving or arising from the abandonment of the Nuclear Project; (5) current and future litigation, including particularly litigation or government investigations or any actions involving or arising from the construction or abandonment of the Nuclear Project, including the possible impacts on liquidity and other financial impacts therefrom; (6) the results of short- and long-term financing efforts, including prospects for obtaining access to capital markets and other sources of liquidity and the effect of rating agency actions on the cost of and access to capital and sources of liquidity of SCANA, SCE&G and Dominion Energy; (7) the ability of suppliers, both domestic and international, to timely provide the labor, secure processes, components, parts, tools, equipment and other supplies needed which may be highly specialized or in short supply, at agreed upon quality and prices, for our construction program, operations and maintenance; (8) the results of efforts to ensure the physical and cyber security of key assets and processes; (9) changes in the economy, especially in areas served by subsidiaries of SCANA; (10) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial markets; (11) the impact of conservation and demand side management efforts and/or technological advances on customer usage; (12) the loss of electricity sales to distributed generation, such as solar photovoltaic systems or energy storage systems; (13) growth opportunities for the Company; (14) the effects of weather, especially in areas where the generation and transmission facilities of the Company are located and in areas served by SCANA’s subsidiaries; (15) changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies; (16) payment and performance by counterparties and customers as contracted and when due; (17) the results of efforts to license, site, construct and finance facilities, and to receive related rate recovery, for generation and transmission; (18) the results of efforts to operate the Company's electric and gas systems and assets in accordance with acceptable performance standards, including the impact of additional distributed generation; (19) the availability of fuels such as coal, natural gas and enriched uranium used to produce electricity; the availability of purchased power and natural gas for distribution; the level and volatility of future market prices for such fuels and purchased power; and the ability to recover the costs for such fuels and purchased power; (20) the availability and retention of skilled, licensed and experienced human resources to properly manage, operate, and grow the Company’s businesses, particularly in light of uncertainties with respect to legislative and regulatory actions surrounding recovery of Nuclear Project costs and integration within the combined companies of Dominion Energy; (21) labor disputes; (22) performance of SCANA’s pension plan assets and the effect(s) of associated discount rates; (23) inflation or deflation; (24) changes in interest rates; (25) compliance with regulations; (26) natural disasters, man-made mishaps and acts of terrorism that directly affect our operations or the regulations governing them; and (27) the other risks and uncertainties described from time to time in the reports filed by SCANA or SCE&G with the SEC.

SCANA and SCE&G disclaim any obligation to update any forward-looking statements.

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DEFINITIONS

Abbreviations used in this Form 10-K have the meanings set forth below unless the context requires otherwise:

TERM	MEANING
ACE	Affordable Clean Energy
Act 258	A law adopted in 2018 by the South Carolina General Assembly that required a temporary reduction in the amount SCE&G could collect from customers under the BLRA.
AFC	Allowance for Funds Used During Construction
ANI	American Nuclear Insurers
AOCI	Accumulated Other Comprehensive Income (Loss)
ARO	Asset Retirement Obligation
Bankruptcy Court	U.S. Bankruptcy Court for the Southern District of New York
bcf	billion cubic feet
BLRA	Base Load Review Act
CAA	Clean Air Act, as amended
CAIR	Clean Air Interstate Rule
CC	Combined Cycle
CCR	Coal Combustion Residuals
CEC	Columbia Energy Center
CEO	Chief Executive Officer
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act
CFO	Chief Financial Officer
CFTC	Commodity Futures Trading Commission
Citibank	Citibank, N.A.
CO2	Carbon Dioxide
Company	SCANA, together with its consolidated subsidiaries
Concurrent Dockets	Separate dockets that were before the SCPSC related to the Nuclear Project which were handled concurrently. The Concurrent Dockets included the Joint Petition, the Request for Rate Relief filed by the ORS on September 26, 2017, as subsequently amended on October 17, 2017, and a June 2017 complaint filed by the Friends of the Earth and the Sierra Club.
Consolidated SCE&G	SCE&G and its consolidated affiliates
Consortium	A consortium consisting of WEC and WECTEC
Court of Appeals	United States Court of Appeals for the Fourth Circuit
CPP	Clean Power Plan
CSAPR	Cross-State Air Pollution Rule
CT	Combustion Turbine
CUT	Customer Usage Tracker (decoupling mechanism)
CWA	Clean Water Act
DER	Distributed Energy Resource
Derivative Litigation	Claims asserted against former officers and directors of SCANA in derivative shareholder actions and related actions
DHEC	South Carolina Department of Health and Environmental Control
District Court	United States District Court for the District of South Carolina
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
DOE	United States Department of Energy
Dominion Energy	Dominion Energy, Inc., the parent company of SCANA effective January 1, 2019
DOR	South Carolina Department of Revenue
DOT	United States Department of Transportation
DSM Programs	Electric Demand Side Management Programs
ELG Rule	Federal effluent limitation guidelines for steam electric generating units
EMANI	European Mutual Association for Nuclear Insurance
EPA	United States Environmental Protection Agency
EPC Contract	Engineering, Procurement and Construction Agreement dated May 23, 2008, as amended by the October 2015 Amendment
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
FILOT	Fee in lieu of taxes
Fluor	Fluor Corporation
Fluor Defendants	Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc.
Fuel Company	South Carolina Fuel Company, Inc.
GAAP	Accounting principles generally accepted in the United States of America
GENCO	South Carolina Generating Company, Inc.
GHG	Greenhouse Gas
GPSC	Georgia Public Service Commission
GWh	Gigawatt hour
IAA	Interim Assessment Agreement dated March 28, 2017, as amended, among SCE&G, Santee Cooper, WEC and WECTEC
IRC	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
Joint Petition	Joint application and petition of SCE&G and Dominion Energy for review and approval of a proposed business combination as set forth in the Merger Agreement and for a prudency determination regarding the abandonment of the Nuclear Project and associated merger benefits and cost recovery plans, filed with the SCPSC on January 12, 2018
Level 1	A fair value measurement using unadjusted quoted prices in active markets for identical assets or liabilities
Level 2	A fair value measurement using observable inputs other than those for Level 1, including quoted prices for similar (not identical) assets or liabilities or inputs that are derived from observable market data by correlation or other means
Level 3	A fair value measurement using unobservable inputs, including situations where there is little, if any, market activity for the asset or liability
LNG	Liquefied Natural Gas
LOC	Lines of Credit
LTECP	SCANA Long-Term Equity Compensation Plan
MATS	Mercury and Air Toxics Standards
Merger Agreement	Agreement and Plan of Merger, dated as of January 2, 2018, by and among Dominion Energy, Sedona Corp. and SCANA
Merger Approval Order	The December 21, 2018, order by the SCPSC related to the Concurrent Dockets and setting forth its approval of the SCANA Combination
MGP	Manufactured Gas Plant
MMBTU	Million British Thermal Units
MRA	Modified Removal Action
MW or MWh	Megawatt or Megawatt-hour
NASDAQ	The NASDAQ Stock Market, Inc.
NAV	Net Asset Value
NCUC	North Carolina Utilities Commission
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Corporation
NOL	Net Operating Loss
NOX	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NRC	United States Nuclear Regulatory Commission
NSPS	New Source Performance Standards
NSR	New Source Review
Nuclear Project	Project to construct Unit 2 and Unit 3 under the EPC Contract
Nuclear Waste Act	Nuclear Waste Policy Act of 1982
NYMEX	New York Mercantile Exchange
NYSE	The New York Stock Exchange
OCI	Other Comprehensive Income
October 2015 Amendment	Amendment, dated October 27, 2015, to the EPC Contract
ORS	South Carolina Office of Regulatory Staff
PGA	Purchased Gas Adjustment
PHMSA	United States Pipeline Hazardous Materials Safety Administration
PLR	Private Letter Ruling
PPA	Purchase Power Agreement
Price-Anderson	Price-Anderson Indemnification Act
PSNC Energy	Public Service Company of North Carolina, Incorporated
RICO	The Racketeer Influenced and Corrupt Organizations Act
ROE	Return on Equity
RSA	Natural Gas Rate Stabilization Act
RTO/ISO	Regional Transmission Organization/Independent System Operator
Santee Cooper	South Carolina Public Service Authority
SCANA	SCANA Corporation, the parent company of SCE&G
SCANA Combination	Dominion Energy's acquisition of SCANA and its subsidiaries effective January 1, 2019 pursuant to the terms of the Merger Agreement
SCANA Energy	SCANA Energy Marketing, Inc.
SCANA Services	SCANA Services, Inc.
SCE&G	South Carolina Electric & Gas Company
SCE&G Ratepayer Case	A consolidated complaint styled Richard Lightsey, LeBrian Cleckley, Phillip Cooper et al. on behalf of themselves and all others similarly situated v. SCE&G, SCANA, and the State of South Carolina filed in the State Court of Common Pleas in Hampton County
SCEUC	South Carolina Energy Users Committee
SCPSC	Public Service Commission of South Carolina
SEC	United States Securities and Exchange Commission
SIP	State Implementation Plan
SLED	South Carolina Law Enforcement Division
SO2	Sulfur Dioxide
Summer Station	V.C. Summer Nuclear Station
Supreme Court	United States Supreme Court
Tax 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
Toshiba	Toshiba Corporation, parent company of WEC
Toshiba Settlement	Settlement Agreement dated as of July 27, 2017, by and among Toshiba, SCE&G and Santee Cooper
Transco	Transcontinental Gas Pipe Line Company, LLC
TSR	Total Shareholder Return
Unit 1	Nuclear Unit 1 at Summer Station
Unit 2	Nuclear Unit 2 at Summer Station (abandoned prior to construction completion)
Unit 3	Nuclear Unit 3 at Summer Station (abandoned prior to construction completion)
USACE	United States Army Corps of Engineers
VIE	Variable Interest Entity
WARN Act	Worker Adjustment and Retraining Notification Act
WEC	Westinghouse Electric Company LLC
WEC Subcontractors	Subcontractors and suppliers to the Consortium
WECTEC	WECTEC Global Project Services, Inc. (formerly known as Stone & Webster, Inc.), a wholly-owned subsidiary of WEC
Williams Station	A.M. Williams Generating Station, owned by GENCO
WNA	Weather Normalization Adjustment

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PART I

ITEM 1. BUSINESS

CORPORATE STRUCTURE

Effective January 1, 2019, SCANA became a wholly-owned subsidiary of Dominion Energy under the terms of the Merger Agreement. SCANA's shareholders approved the merger in a special meeting on July 31, 2018, and various regulatory bodies approved the transaction throughout 2018. See additional discussion in Note 2 and Note 11 to the consolidated financial statements in Part II, Item 8. Financial Statements and Supplementary Data.

SCANA is a South Carolina corporation created in 1984 as a holding company. SCANA does not directly own or operate any significant physical properties, but it holds directly all of the capital stock of its subsidiaries, including the subsidiaries described below.

Regulated Utilities

SCE&G is engaged in the generation, transmission, distribution and sale of electricity to approximately 730,000 customers and the purchase, sale and transportation of natural gas to approximately 380,000 customers (each as of December 31, 2018). SCE&G’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. SCE&G’s service territory includes portions of central, southern and southwestern South Carolina (for electric and natural gas) as well as portions of eastern South Carolina (for natural gas only). SCE&G’s electric transmission system extends over a large part of the central, southern and southwestern portions of South Carolina.

GENCO owns Williams Station and sells electricity solely to SCE&G under the terms of a unit power sales agreement and related operating agreement and pursuant to a FERC-approved tariff. Fuel Company acquires, owns and provides financing for SCE&G's nuclear fuel, certain fossil fuels and emission allowances.

PSNC Energy purchases, sells and transports natural gas to approximately 580,000 residential, commercial and industrial customers (as of December 31, 2018). PSNC Energy serves portions of western, central and eastern North Carolina, including the area known as the Research Triangle.

Nonregulated Businesses

SCANA Energy markets natural gas in the southeast and provides energy-related services. A division of SCANA Energy sells natural gas to approximately 420,000 customers (as of December 31, 2018) in Georgia’s deregulated natural gas market. As Georgia’s provider of last resort, SCANA Energy provides service to customers considered to be low-income or that are otherwise unable to obtain natural gas service from other marketers. SCANA Energy provides this service at rates approved by the GPSC and receives funding from Georgia's Universal Service Fund to offset some of the resulting bad debt. SCANA Energy files financial and other information periodically with the GPSC, and such information is available at www.psc.state.ga.us (which is not intended as an active hyperlink; the information on the GPSC website is not part of this or any other report filed by the Company with the SEC).

SCANA Services provides shared administrative and management services to SCANA's other subsidiaries.

Employees

At December 31, 2018, the Company had approximately 5,200 full-time employees, of which approximately 1,100 were subject to collective bargaining agreements, and Consolidated SCE&G had approximately 2,700 employees, of which approximately 800 were subject to collective bargaining agreements.

COMPETITION

There is no competition for electric distribution or generation service within SCE&G's 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 SCE&G’s service territory is permitted pursuant to FERC Order

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1000, subject to state and local siting and permitting approvals. This could result in additional competition to build and own transmission infrastructure in SCE&G’s service area in the future.

Competition in SCE&G's and PSNC Energy'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.

SCANA Energy faces competition from affiliates of large energy companies and electric membership cooperatives, among others. The ability of SCANA Energy to maintain its market share primarily depends on the prices it charges customers relative to the prices charged by its competitors and its ability to provide high levels of customer service.

REGULATION

SCE&G's electric distribution service, including the rates it may charge to jurisdictional customers, is subject to regulation by the SCPSC. SCE&G's electric generation operations are subject to regulation by the SCPSC, FERC, the NRC, the EPA, the DOE and various other federal, state and local authorities. SCE&G's electric transmission service is primarily regulated by FERC and the DOE. SCE&G and PSNC Energy's gas distribution operations are subject to regulation by the SCPSC and the NCUC, respectively, as well as PHMSA, DOT, the ORS and the NCUC for enforcement of federal and state pipeline safety requirements in their respective service territories. SCANA Energy's activities are subject to regulation by the GPSC as to retail prices for customers served under regulated provider contracts and the FERC.

WHERE YOU CAN FIND MORE INFORMATION

SCANA and SCE&G file 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.

SCANA and SCE&G make 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 internet 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

The risk factors that follow relate in each case to the Company, and where indicated the risk factors also relate to Consolidated SCE&G.

There may be significant challenges to successfully integrate the Company’s and Consolidated SCE&G’s businesses with Dominion Energy.

Significant management attention and resources will be required to integrate the Company’s and Consolidated SCE&G’sbusinesses with Dominion Energy. Potential difficulties that may be encountered in the integration process include the following:

• the complexities associated with integrating the Company, including its utility businesses, while at the same time providing consistent, high quality services;

• the complexities of integrating a company with different markets and customers;

• the inability to attract and retain key employees;

• potential unknown liabilities and unforeseen increased expenses associated with the merger;

• difficulties in managing political and regulatory conditions related to the Company's utility businesses;

• the moratorium on filing requests for adjustments in SCE&G's base electric rates until 2020 with no change in rates until January 1, 2021, which limits the ability to recover increases in non-fuel related costs of electric operations for SCE&G’s customers;

• the stipulation agreement approved by the NCUC, which provides for a rate moratorium at PSNC Energy until November 1, 2021, with certain exceptions; and

• performance shortfalls as a result of the diversion of management’s attention caused by integrating the Company's businesses.

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For these reasons, it is possible that the integration process could result in the distraction of the Company's and Consolidated SCE&G's management, the disruption of each of their ongoing businesses or inconsistencies in their services, standards, controls, procedures and policies, any of which could adversely affect the ability of the Company or Consolidated SCE&G to maintain or establish relationships with current and prospective customers, vendors and employees or could otherwise adversely affect their businesses and financial results.

The Company and Consolidated SCE&G are subject to the reputational risks that may result from a failure to adhere to high standards related to compliance with laws and regulations, ethical conduct, operational effectiveness, customer service and the safety of employees, customers and the public. In addition, the Company and Consolidated SCE&G have been and may continue to be adversely affected by negative publicity related to the abandonment of the Nuclear Project.

The Company and Consolidated SCE&G are committed to operational excellence, to quality customer service, and, through an ethics and compliance program, to maintain high standards of ethical conduct in our business operations. A failure to meet these commitments, or a perceived failure to meet these commitments, may subject the Company and Consolidated SCE&G not only to fraud, regulatory action, litigation or financial loss, but also to reputational risk that could adversely affect the Company’s and Consolidated SCE&G’s access to capital, and result in further regulatory oversight. In addition, traditional news media and social media can very rapidly convey information, whether factual or not, to large numbers of people, including customers, investors, regulators, legislators and other stakeholders, and the failure to effectively manage timely, accurate communication through these channels could adversely impact our reputation.

Political and public sentiment in connection with the abandonment of the Nuclear Project has resulted in and may continue to result in a significant amount of adverse press coverage and other adverse public statements affecting the Company and Consolidated SCE&G. 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 in addition to those which have already occurred or are currently pending. Responding to these investigations and lawsuits, regardless of the ultimate outcome of the proceedings, as well as responding to and addressing adverse press coverage and other adverse public statements, can divert the time and effort of senior management from the management of the Company’s and Consolidated SCE&G’s respective businesses.

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 the Company and Consolidated SCE&G, on the morale and performance of their employees and on their relationships with their respective regulators, customers and commercial counterparties. It may also have a negative impact on their 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 an adverse effect on the Company’s and Consolidated SCE&G’s respective businesses, financial condition, results of operations and prospects.

The rates that the Company and Consolidated SCE&G can charge customers are subject to regulatory review.

Revenue provided by the Company’s and Consolidated SCE&G’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.

The Company’s retail gas base rates for distribution services to customers in North Carolina are regulated on a cost-of-service basis subject to North Carolina statutes and the rules and procedures of the NCUC. Consolidated SCE&G’s retail electric bases 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 SCSPC. If retail electric earnings exceed the returns established by the SCPSC, retail electric rates may be subject to review and possible reduction by the SCPSC, which may decrease Consolidated SCE&G’s future earnings. If the NCUC and SCPSC do not allow recovery through base rates, on a timely basis, of costs incurred in providing service, the Company’s and Consolidated SCE&G’s future earnings could be negatively impacted.

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.

The Company and SCE&G are subject to numerous legal proceedings and ongoing governmental investigations and examinations.

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The Company and SCE&G are defendants in numerous federal and state legal proceedings and governmental investigations relating to the decision to abandon construction at the Nuclear Project. Among other things, the lawsuits and investigations allege misrepresentation, failure to properly manage the Nuclear Project, unfair trade practices and violation of anti-trust laws. The plaintiffs seek a judgment that SCE&G many not charge its customers for any past or continuing costs of the Nuclear Project, among other remedies.

Additionally, the Company and SCE&G are defendants in federal and state legal proceedings relating to the SCANA Combination. Among other things, the lawsuits allege improper disclosures and breaches of various fiduciary duties. Remedies sought include rescinding the SCANA Combination.

The outcome of these legal proceedings, investigations and examinations is uncertain and may adversely affect the Company’s and Consolidated SCE&G’s financial condition or results of operation.

The Company and Consolidated SCE&G have engaged in activities for which they have claimed research and experimentation tax deductions and credits and tax abandonment losses, all of which are the subject of uncertainty.

The Company and Consolidated SCE&G have claimed significant research and experimentation tax deductions and credits related to the design and construction activities of Unit 2 and Unit 3. A significant portion of these claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. The Company and Consolidated SCE&G have also claimed a significant tax deduction related to the decision to stop construction and to abandon the Nuclear Project in 2017.

These tax claims primarily involve the timing of recognition of tax deductions rather than permanent tax attributes, and their permanent attributes (net), as well as most of the interest accruals required to be recorded with respect to them, had been deferred within regulatory assets. As such, until December 31, 2017 when these deferrals were considered to be impaired, these claims had not had, and were not expected to have in the future, significant direct effects on the Company’s and Consolidated SCE&G’s results of operations. Nonetheless, the claims contributed significantly to the Company’s and Consolidated SCE&G’s cash flows by providing a significant source of capital and lessening the level of debt and equity financing that the Company and Consolidated SCE&G were required to raise in the financial markets. 

The claims made to date are under examination and, even though a favorable PLR regarding the 2017 abandonment loss related to the Nuclear Project was obtained, all such claims are considered uncertain. To the extent that any of these claims are not sustained as ordinary losses on examination or through any subsequent appeal, the Company and Consolidated SCE&G will be required to repay any cash received for tax benefit claims which are ultimately disallowed, along with interest on those amounts. Such amounts could be significant and could adversely affect the Company's and Consolidated SCE&G's liquidity, cash flows, results of operations and financial condition. In certain circumstances, which management considers to be remote, penalties for underpayment of income taxes could also be assessed. 

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.

The Company and Consolidated SCE&G are 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, the Company’s and Consolidated SCE&G’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 the Company or Consolidated SCE&G 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.

SCE&G 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, SCE&G 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 SCE&G’s businesses, SCE&G may not be able to keep investment-grade ratings.

The Company and Consolidated SCE&G are subject to numerous environmental laws and regulations that require significant capital expenditures, can increase our costs of operations and may impact our business plans or expose us to environmental liabilities.

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The Company and Consolidated SCE&G are subject to extensive federal, state and local environmental laws and regulations, including those relating to water quality and air emissions (such as reducing NO_X, SO₂, mercury and particulate matter). Some form of regulation is expected at the federal and state levels to impose regulatory requirements specifically directed at reducing GHG emissions from fossil fuel-fired electric generating units. For example, on August 21, 2018, the EPA proposed a replacement rule to the CPP, known as the ACE rule, which will establish guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. However, a number of bills have been introduced in Congress that seek to require GHG emissions reductions from fossil fuel-fired electric generation facilities, natural gas facilities and other sectors of the economy, although none has yet been enacted. Furthermore, the EPA finalized standards under the CWA governing effluent limitation guidelines for electric generating units in September 2015. While the rule setting forth these standards has been stayed administratively, the EPA has begun a new rulemaking process that could take until 2020 before revisions to the effluent limitation guidelines for electric generating units is complete.

Compliance with environmental laws and regulations requires us to commit significant resources toward environmental monitoring, installation of pollution control equipment, emissions fees and permitting at our facilities. These expenditures have been significant in the past and are expected to continue or increase in the future. Changes in compliance requirements, additional regulations and related costs, or more restrictive interpretations by governmental authorities of existing requirements may impose additional costs on us (such as more stringent clean-up of contaminated sites or reduced emission allowances) or require us to incur additional expenditures or curtail some of our cost savings activities (such as the recycling of fly ash and other coal combustion products for beneficial use). Compliance with any GHG emission reduction requirements, including any mandated renewable portfolio standards, also may impose significant costs on us, and the resulting price increases to our customers may lower customer consumption. Such costs of compliance with environmental regulations could negatively impact our businesses and our results of operations and financial position, especially if emissions or discharge limits are reduced or more onerous permitting requirements or additional regulatory requirements are imposed. Additionally, there can be no assurance that a federal tax or fee for carbon emitting generating facilities will not be imposed.

The compliance costs of these environmental laws and regulations are important considerations in the Company's and Consolidated SCE&G's strategic planning and, as a result, significantly affect the decisions to construct, operate, and retire facilities, including generating facilities. In turn, they affect the costs and rates of the Company and Consolidated SCE&G.

Commodity price changes, delays in delivery of commodities, commodity availability and other factors may affect the operating cost, capital expenditures and competitive positions of the Company’s and Consolidated SCE&G’s energy businesses.

Our energy businesses are sensitive to changes in coal, natural gas, uranium and other commodity prices (as well as their transportation costs), availability and deliverability. Any such changes could affect the prices these businesses charge, their operating costs, and the competitive position of their products and services. While Consolidated SCE&G is permitted to recover the prudently incurred cost of purchased power and fuel (including transportation) used in electric generation through retail customers’ bills, such cost increases affect electric prices and therefore the competitive position of electricity against other energy sources. In addition, when natural gas prices are low enough relative to coal to result in the dispatch of gas-fired electric generation ahead of coal-fired electric generation, higher inventories of coal, with related increased carrying costs, may result. This may adversely affect our results of operations, cash flows and financial condition.

In the case of regulated natural gas operations, costs prudently incurred for purchased gas and pipeline capacity may be recovered through retail customers’ bills. However, in both our regulated and deregulated natural gas markets, increases in gas costs affect total retail prices and therefore the competitive position of gas relative to electricity and other forms of energy. Accordingly, customers able to do so may switch to alternate forms of energy and reduce their usage of gas from the Company and Consolidated SCE&G. Customers on a volumetric rate structure unable to switch to alternate fuels or suppliers may reduce their usage of gas from the Company and Consolidated SCE&G. A regulatory mechanism applies to residential and commercial customers at PSNC Energy to mitigate the earnings impact of an increase or decrease in gas usage.

Certain construction-related commodities, such as copper and aluminum used in our transmission and distribution lines and in our electrical equipment, and steel, concrete and rare earth elements, have experienced significant price fluctuations due to changes in worldwide demand. To operate our air emissions control equipment, we use significant quantities of ammonia, limestone and lime. With EPA-mandated industry-wide compliance requirements for air emissions controls, increased demand for these reagents, combined with the increased demand for low sulfur coal, may result in higher costs for coal and reagents used for compliance purposes.

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Changing and complex laws and regulations to which the Company and Consolidated SCE&G are subject could adversely affect revenues, increase costs, or curtail activities.

The Company and Consolidated SCE&G operate under the regulatory authority of the United States government and its various regulatory agencies, including the FERC, NRC, SEC, IRS, EPA, the Department of Homeland Security, CFTC and PHMSA. In addition, the Company and Consolidated SCE&G are subject to regulation by the state governments of South Carolina, North Carolina and Georgia via regulatory agencies, state environmental agencies, and state employment commissions. Accordingly, the Company and Consolidated SCE&G must comply with extensive federal, state and local laws and regulations. Such governmental oversight and regulation broadly and materially affect the operation of our businesses. In addition to many other aspects of our businesses, these requirements impact the services mandated or offered to our customers, and the licensing, siting, construction and operation of facilities. They affect our management of safety, the reliability of our electric and natural gas systems, the physical and cyber security of key assets, customer conservation through DSM Programs, information security, the issuance of securities and borrowing of money, financial reporting, interactions among affiliates, the pricing of utility services, the payment of dividends and employment programs and practices. Changes to governmental regulations are continual and potentially costly to effect compliance. Non-compliance with these requirements by third parties, such as our contractors, vendors and agents, may subject the Company and Consolidated SCE&G to operational risks and to liability. We cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on the Company’s or Consolidated SCE&G’s businesses. Non-compliance with these laws and regulations could result in fines, litigation, loss of licenses or permits, mandated capital expenditures and other adverse business outcomes, as well as reputational damage, which could adversely affect the cash flows, results of operations, and financial condition of the Company and Consolidated SCE&G.

Furthermore, changes in or uncertainty in monetary, fiscal, tax, economic, trade, or regulatory policies of the federal government may adversely affect the debt and equity markets and the economic climate for the nation, region or particular industries, such as ours or those of our customers. The Company and Consolidated SCE&G also could be adversely impacted by changes in tax policy, or taxes related to the usage of certain fuel types in our businesses or our ownership and/or operation of certain types of generating facilities. Future, unknown regulation of hydraulic fracturing activities also could impact the operations and finances of the Company and Consolidated SCE&G.

SCE&G’s electric operations in South Carolina and the Company’s gas distribution operations in South Carolina and North Carolina are regulated by state utilities commissions. Consolidated SCE&G’s generating facilities are subject to extensive regulation and oversight from the NRC and SCPSC. SCE&G's electric transmission system is subject to extensive regulations and oversight from the SCPSC, NERC and FERC. Implementing and maintaining compliance with the NERC's mandatory reliability standards, enforced by FERC, for bulk electric systems could result in higher operating costs and capital expenditures. Non-compliance with these standards could subject SCE&G to substantial monetary penalties. Our gas marketing operations in Georgia are subject to state regulatory oversight and, for a portion of its operations, to rate regulation. There can be no assurance that Georgia’s gas delivery regulatory framework will remain unchanged as market conditions evolve.

Furthermore, Dodd-Frank affects the use and reporting of derivative instruments. The regulations under this legislation provide for substantial additional regulation of over-the-counter and security-based derivative instruments, among other things, and require numerous rule-makings by the CFTC and the SEC to implement, many of which are still pending final action by those federal agencies. The Company and Consolidated SCE&G have determined that they meet the end-user exception to mandatory clearing of swaps under Dodd-Frank. In addition, the Company and Consolidated SCE&G have taken steps to ensure that they are not the party required to report these transactions in real-time (the "reporting party") by transacting solely with swap dealers and major swap participants, when possible, as well as entering into reporting party agreements with counterparties who also are not swap dealers or major swap participants, which establishes that those counterparties are obligated to report the transactions in accordance with applicable Dodd-Frank regulations. While these actions minimize the reporting obligations of the Company and Consolidated SCE&G, they do not eliminate required recordkeeping for any Dodd-Frank regulated transactions. Despite qualifying for the end-user exception to mandatory clearing and ensuring that neither the Company nor Consolidated SCE&G is the reporting party to a transaction required to be reported in real-time, we cannot predict when the final regulations will be issued or what requirements they will impose.

Hostile cyber intrusions could severely impair the Company’s and Consolidated SCE&G’s operations, lead to the disclosure of confidential information, damage the reputation of the Company and Consolidated SCE&G and otherwise have an adverse effect on the Company’s and Consolidated SCE&G’s business.

The Company and Consolidated SCE&G own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run the Company’s and Consolidated

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SCE&G’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 the Company’s and Consolidated SCE&G’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, the Company’s and Consolidated SCE&G’s businesses require that they and their vendors collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

A successful cyber attack on the systems that control the Company’s and Consolidated SCE&G’s electric generation, electric or gas transmission or distribution assets could severely disrupt business operations, preventing the Company and Consolidated SCE&G from serving customers or collecting revenues. The breach of certain business systems could affect the Company’s and Consolidated SCE&G’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 the Company’s and Consolidated SCE&G’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data at the Company or Consolidated SCE&G or one of their vendors could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. While the Company and Consolidated SCE&G maintain 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 the Company’s and Consolidated SCE&G’s business, financial condition and results of operations.

Operating results may be adversely affected by natural disasters, man-made mishaps and abnormal weather.

The Company has delivered less gas and, in deregulated markets, received lower prices for natural gas when weather conditions have been milder than normal, and as a consequence earned less income from those operations. Mild weather in the future could adversely impact the revenues and results of operations and harm the financial condition of the Company and Consolidated SCE&G. Hot or cold weather could result in higher bills for customers and result in higher write-offs of receivables and in a greater number of disconnections for non-payment. In addition, for the Company and Consolidated SCE&G, severe weather can be destructive, causing outages and property damage, adversely affecting operating expenses and revenues.

Natural disasters (such as hurricanes or other significant weather events, electromagnetic events, earthquakes, flooding or fires) or man-made mishaps (such as natural gas transmission pipeline failure, electric utility companies' ash pond failures, and cyber-security failures experienced by many businesses) could have direct significant impacts on the Company and Consolidated SCE&G and on our key contractors and suppliers or could impact us through changes to federal, state or local policies, laws and regulations, and have a significant impact on our financial condition, operating expenses, and cash flows.

The costs of large capital projects, such as the Company’s and Consolidated SCE&G’s construction and environmental compliance programs, are significant, and these projects are subject to a number of risks and uncertainties that may adversely affect the cost, timing and completion of these projects.

The Company’s and Consolidated SCE&G’s businesses are capital intensive and require significant investments in electric generation and in other internal infrastructure projects, including projects for environmental compliance. Achieving the intended benefits of any large construction project is subject to many uncertainties. For instance, the ability to adhere to established budgets and construction schedules may be affected by many variables, such as the 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, the availability and cost of financing, and weather. There also may be contractor or supplier performance issues or adverse changes in their creditworthiness and/or financial stability, unforeseen difficulties meeting critical regulatory requirements, contract disputes and litigation, and changes in key contractors or subcontractors. There may be unforeseen engineering problems or unanticipated changes in project design or scope. Our ability to complete construction projects as well as our ability to maintain current operations at reasonable cost could be affected by the availability of key components or commodities, increases in the price of or the unavailability of labor, commodities or other materials, increases in lead times for components, adverse changes in applicable laws and regulations, new or enhanced environmental or regulatory requirements, supply chain failures (whether resulting from the foregoing or other factors), and disruptions in the transportation of components, commodities and fuels. To the extent that, in connection with the construction of a project, delays occur, costs become unrecoverable, or we otherwise become unable to effectively manage and complete the project, our results of operations, cash flows and financial condition, as well as our qualifications for applicable governmental programs, benefits and tax credits may be adversely affected.

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A significant portion of Consolidated SCE&G’s generating capacity is derived from nuclear power, the use of which exposes us to regulatory, environmental and business risks.

SCE&G jointly owns and is the operator of Unit 1. Various risks of nuclear generation to which SCE&G is subject include the following:

• The potential harmful effects on the environment and human health resulting from a release of radioactive materials in connection with the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; 

• Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;

• The possibility that new laws and regulations could be enacted that could adversely affect the liability structure that currently exists in the United States;

• Uncertainties, including trade disputes, with respect to procurement of nuclear fuel and suppliers thereof, fabrication of nuclear fuel and related vendors, and the storage of spent nuclear fuel;

• Uncertainties with respect to contingencies if insurance coverage is inadequate;

• Uncertainties with respect to possible future increased regulation of nuclear facilities and nuclear generation, and related costs thereof; and

• Uncertainties with respect to the technological aspects of, and adequacy of funding for, decommissioning nuclear plants at the end of their operating lives.

SCE&G maintains a trust to minimize the financial risks associated with the decommissioning of Unit 1; however, it is possible that future decommissioning costs could exceed amounts in the decommissioning trust. If assets in the trust are insufficient to cover the eventual costs of decommissioning, and if SCE&G is unable to recover the shortfall through regulatory means, the Company's and Consolidated SCE&G's results of operations could be negatively impacted.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate capital expenditures at nuclear plants such as ours. In today’s environment, there is a heightened risk of terrorist attack on the nation’s nuclear facilities, which has resulted in increased security costs at our nuclear plant. Although we have no reason to anticipate a serious nuclear incident, a major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit, resulting in costly changes to units in operation and adversely impacting our results of operations, cash flows and financial condition. Furthermore, a major incident at a domestic nuclear facility could result in retrospective premium assessments under our nuclear insurance coverages.

Potential competitive changes may adversely affect our gas and electricity businesses due to the loss of customers, reductions in revenues, or write-down of stranded assets.

The utility industry has been undergoing a structural change for a number of years, resulting in increasing competitive pressures on electric and natural gas utility companies. Competition in wholesale power sales via an RTO/ISO is in effect across much of the country, but the Southeastern utilities have retained the traditional bundled, vertically integrated structure. Should an RTO/ISO-market be implemented in the Southeast, potential risks emerge from reliance on volatile wholesale market prices as well as increased costs associated with new transmission and distribution infrastructure.

Some states have also mandated or encouraged unbundled retail competition. Should this occur in South Carolina or North Carolina, increased competition may create greater risks to the stability of utility earnings generally and may in the future reduce earnings from retail electric and natural gas sales. In a deregulated environment, formerly regulated utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits as competitors gain access to their customers. In addition, the Company’s and Consolidated SCE&G’s generation assets would be exposed to considerable financial risk in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, a write-down in the value of the related assets could be required.

The Company and Consolidated SCE&G are subject to the risk of loss of sales due to the growth of distributed generation especially in the form of renewable power such as solar photovoltaic systems, which systems have undergone a rapid decline in their costs. As a result of federal and state subsidies, potential regulations allowing third-party retail sales, and

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advances in distributed generation technology, particularly when combined with storage solutions, the growth of such distributed generation could be significant in the future. Such growth will lessen the Company's and Consolidated SCE&G's sales and will slow growth, potentially causing higher rates to customers.

Renewable and/or alternative electric generation portfolio standards may be enacted at the federal or state level. Such renewable energy may not be readily available in our service territories and could be costly to build, finance, acquire, integrate, and/or operate. Resulting increases in the price of electricity to recover the cost of these types of generation, and the costs of their integration to the electric system, could result in lower usage of electricity by our customers. In addition, DER generation at customers’ facilities could result in the loss of sales to those customers. Compliance with potential future portfolio standards could significantly impact our capital expenditures and our results of operations and financial condition. Utility scale solar development companies are currently working in South Carolina to develop projects in SCE&G's service territory.

Problems with operations could cause us to curtail or limit our ability to serve customers or cause us to incur substantial costs.

Critical processes or systems in the Company’s or Consolidated SCE&G’s operations could become impaired or fail from a variety of causes, such as equipment breakdown, transmission equipment failure, information systems failure or security breach, operator error, natural disasters, and the effects of a pandemic, terrorist attack or cyber attack on our workforce or facilities or on vendors and suppliers necessary to maintain services key to our operations.

In particular, as the operator of power generation facilities, many of which entered service prior to 1985 and may be difficult to maintain, Consolidated SCE&G could incur problems, such as the breakdown or failure of power generation or emission control equipment, transmission equipment, or other equipment or processes which would result in performance below assumed levels of output or efficiency. The integration of a significant amount of distributed generation into our systems may entail additional cycling of our coal-fired generation facilities and may thereby increase the number of unplanned outages at those facilities. In addition, any such breakdown or failure may result in Consolidated SCE&G purchasing emission allowances or replacement power at market rates, if such allowances and replacement power are available at all. These purchases are subject to state regulatory prudency reviews for recovery through rates. If replacement power is not available, such problems could result in interruptions of service (blackout or brownout conditions) in all or part of SCE&G’s territory or elsewhere in the region. Similarly, a natural gas line failure of the Company or Consolidated SCE&G could affect the safety of the public, destroy property, and interrupt our ability to serve customers.

Events such as these could entail substantial repair costs, litigation, fines and penalties, and damage to reputation, each of which could have an adverse effect on the Company’s and Consolidated SCE&G's revenues, results of operations, cash flows, and financial condition. Insurance may not be available or adequate to mitigate the adverse impacts of these events.

The use of derivative instruments could result in financial losses and liquidity constraints. The Company and Consolidated SCE&G do not fully hedge against financial market risks or price changes in commodities. This could result in increased costs, thereby resulting in lower margin.

The Company and Consolidated SCE&G may use derivative instruments, including futures, forwards, options and swaps, to manage our financial market risks. The Company also uses such derivative instruments to manage certain commodity (i.e., natural gas) market risk. We could be required to provide cash collateral or recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities and financial contracts or if a counterparty fails to perform under a contract. We could also be required to provide additional cash collateral if credit rating agency downgrades of our debt trigger more stringent requirements.

The Company strives to manage commodity price exposure by establishing risk limits and utilizing various financial instruments (exchange traded and over-the-counter instruments) to hedge physical obligations and reduce price volatility. We do not hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility or our hedges are not effective, results of operations, cash flows and financial condition may be adversely impacted.

Failure to retain and attract key personnel could adversely affect the Company’s and Consolidated SCE&G’s operations and financial performance, particularly in light of uncertainties related to and resulting from regulatory, legislative and legal proceedings and integration.

A significant portion of our workforce will be eligible for retirement during the next few years. Uncertainties related to regulatory, legislative and legal proceedings, as well as the continuing integration of companies, also weigh significantly on the

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employment considerations made by current and prospective employees, and some workforce attrition has occurred. We must attract, retain and develop executive officers and other professional, technical and craft employees with the skills and experience necessary to successfully manage, operate and grow our businesses. Competition for these employees is high, and in some cases, we must compete for these employees on a regional or national basis. We may be unable to attract and retain these personnel. Further, the Company’s or Consolidated SCE&G’s ability to construct or maintain generation or other assets requires the availability of suitable skilled contractor personnel. We may be unable to obtain appropriate contractor personnel at the times and places needed. Labor disputes with employees or contractors covered by collective bargaining agreements also could adversely affect implementation of our strategic plan and our operational and financial performance. Furthermore, increased medical benefit costs of employees and retirees could adversely affect the results of operations of the Company and Consolidated SCE&G. Medical costs in this country have risen significantly over the past number of years and such increases are expected to continue. Such increases, unless satisfactorily managed by the Company and Consolidated SCE&G, could adversely affect results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not Applicable.

ITEM 2. PROPERTIES

SCANA owns no significant property other than the capital stock of each of its subsidiaries. It holds directly all of the capital stock of each of its subsidiaries.

SCE&G's bond indenture, which secures its First Mortgage Bonds, constitutes a direct mortgage lien on substantially all of its electric utility property. GENCO's Williams Station is also subject to a first mortgage lien which secures certain outstanding debt of GENCO.

Electric Operations

The following table shows the electric generating facilities and their net generating capacity as of December 31, 2018.

				Percentage
		Net Summer		Net Summer
Plant	Location	Capacity (MW)		Capacity
Gas
McMeekin	Irmo, SC	250
Urquhart Unit 3	Beech Island, SC	95
Jasper (CC)	Hardeeville, SC	852	*
Urquhart (CC)	Beech Island, SC	458	*
Columbia Energy Center (CC)	Gaston, SC	504	*
Hagood Units 4, 5 and 6 (CT)	Charleston, SC	126	*
Parr (CT)	Jenkinsville, SC	60	*
Coit (CT)	Columbia, SC	26	*
Urquhart Units 1, 2, 3 and 4 (CT)	Beech Island, SC	87
Williams (CT)	Goose Creek, SC	40	*
Hardeeville (CT)	Hardeeville, SC	9
Total Gas		2,507		42	%
Coal
Wateree	Eastover, SC	684
Williams	Goose Creek, SC	605
Cope	Cope, SC	415	**
Total Coal		1,704		28	%
Nuclear
Summer Station Unit 1	Jenkinsville, SC	647	***	11	%
Hydro
Fairfield Pumped Storage	Jenkinsville, SC	576
Saluda	Irmo, SC	198
Neal Shoals	Union, SC	2
Parr	Jenkinsville, SC	7
Stevens Creek	Martinez, GA	9
Total Hydro		792		13	%
Total Utility Generation		5,650
Power Purchase Agreements (contracted capacity)		335		6	%
Total Generation		5,985		100	%

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

* Capable of burning fuel oil as a secondary source

** Capable of burning natural gas as a secondary source

***Reflects SCE&G's 66.7% ownership share

SCE&G owns 440 substations. The transmission system consists of 3,478 miles of lines. The distribution system consists of 18,606 pole miles of overhead lines and 7,809 trench miles of underground lines, exclusive of service-level lines.

Gas Distribution

SCE&G's natural gas system includes 453 miles of transmission pipeline of up to 20 inches in diameter that connect its distribution system with Southern Natural Gas Company, Transco and Dominion Energy Carolina Gas Transmission, LLC. SCE&G’s distribution system consists of 18,005 miles of distribution mains and related service facilities.

SCE&G also owns two LNG plants, 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.

PSNC Energy’s natural gas system consists of 633 miles of transmission pipeline of up to 24 inches in diameter that connect its distribution systems with Transco. PSNC Energy’s distribution system consists of 22,600 miles of distribution mains and related service facilities. PSNC Energy owns one LNG plant that stores the liquefied equivalent of 1.0 bcf of natural gas, can regasify approximately 10% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day.

ITEM 3.  LEGAL PROCEEDINGS

From time to time, the Company and Consolidated SCE&G are 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 the Company or Consolidated SCE&G, 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, and particularly following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G are involved in various legal proceedings.

See Claims and Litigation in Note 11 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data, which information is incorporated herein by reference, for a discussion of various legal, environmental and other regulatory proceedings to which the Company and Consolidated SCE&G are a party to, including any material developments that have occurred in the fourth quarter of 2018.

ITEM 4.  MINE SAFETY DISCLOSURES

Not Applicable.

PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

SCANA:

SCANA became a wholly-owned subsidiary of Dominion Energy effective January 1, 2019, after which date no established public trading market exists for SCANA common stock. Prior to this date, SCANA common stock traded on the NYSE using the ticker symbol SCG. SCANA intends to pay quarterly cash dividends in 2019 but is neither required to nor restricted from making such payment, except as described in Note 4 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data.

The following table provides information about purchases by or on behalf of SCANA or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) of shares or other units of any class of SCANA's equity securities that are registered pursuant to Section 12 of the Exchange Act:

Issuer Purchases of Equity Securities
	(a)	(b)		(c)	(d)
Period	Total number of shares (or units) purchased	Average price paid per share (or unit)		Total number of shares (or units) purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs
October 1-31, 2018	6,162	$	39.85	6,162
November 1-30, 2018	—	—		—
December 1-31, 2018	—	—		—
Total	6,162			6,162	*

*The above table represents shares acquired for non-employee directors under the Director Compensation and Deferral Plan. On December 16, 2014, SCANA announced a program to convert from original issue to open market purchase of SCANA common stock for all applicable compensation and dividend reinvestment plans. This program took effect in the first quarter of 2015. Concurrent with the SCANA Combination, effective January 1, 2019, this program ceased.

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SCE&G:

All of SCE&G's common stock is owned by SCANA, and no established public trading market exists for SCE&G common stock. SCE&G intends to pay quarterly cash dividends in 2019 but is neither required to nor restricted from making such payment, except as described in Note 4 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data.

ITEM 6.  SELECTED FINANCIAL DATA

Not Applicable.

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SCANA and SCE&G meet the conditions to file under the reduced disclosure format, and therefore have omitted certain information related to themselves and their consolidated affiliates and subsidiaries called for by Item 7 of Form 10-K. As a result, this Item 7 provides a management's narrative analysis of the Company's and Consolidated SCE&G's results of operations, and it should be read in conjunction with Item 8. Financial Statements and Supplementary Data. Consolidated SCE&G makes no representation as to information relating solely to SCANA and its subsidiaries (other than Consolidated SCE&G).

RESULTS OF OPERATIONS

	2018			2017
The Company
Loss per share	$	(3.70	)	$	(0.83	)
Cash dividends declared per share	$	0.98		$	2.45
Consolidated SCE&G
Net loss (millions of dollars)	$	(589.3	)	$	(171.9	)

2018 vs 2017

The Company's loss per share and Consolidated SCE&G's net loss reflect impairment losses taken in each period related to the abandoned Nuclear Project. Results in 2018 also reflect an electric rate reduction made effective as of the second quarter of 2018 and significant legal and other costs incurred in connection with the Nuclear Project. For the Company, 2018's results also reflect costs associated with the merger with Dominion Energy. These and other results are discussed below.

Electric Operations

Electric Operations for the Company and for Consolidated SCE&G is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric Operations operating loss (including transactions with affiliates) was as follows: 

	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Operating revenues	$	2,326.6		$	2,664.4		$	2,326.6		$	2,664.4
Fuel used in electric generation	671.3			593.6			671.3			593.6
Purchased power	91.9			80.1			91.9			80.1
Other operation and maintenance	546.4			512.0			559.8			526.4
Impairment loss	1,376.0			1,118.1			1,376.0			1,118.1
Depreciation and amortization	307.4			294.7			296.4			282.8
Other taxes	227.4			220.3			225.0			217.8
Operating Loss	$	(893.8	)	$	(154.4	)	$	(893.8	)	$	(154.4	)

Electric operations can be significantly impacted by the effects of weather. SCE&G estimates the effects on its electric business of actual temperatures in its service territory as compared to historical averages to approximate electric revenue and fuel costs attributable to the effects of abnormal weather. Results in both 2018 and 2017 reflect milder than normal weather in

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the first quarter, with 2017 being significantly milder than 2018, and warmer than normal weather in the second, third and fourth quarters, with 2018 being warmer than 2017 in each period.

2018 vs 2017

Ÿ Operating revenues decreased in 2018 by $113.7 million pursuant to an SCPSC order whereby fuel cost recovery was offset with gains realized upon the settlement of certain interest rate derivative contracts, as further described in Other Income (Expense) below. Operating revenue also decreased by $300.4 million due to the enactment and implementation of Act 258, by $69.2 million due to the recognition of estimated amounts to be refunded to customers as a result of the Tax Act and by lower residential and commercial average use of $48.6 million. The downward reserve adjustment related to fuel cost recovery had no effect on net income as it was fully offset by the recognition within other income of gains realized upon the settlement of certain derivative interest rate contracts. These revenue decreases were partially offset by the effects of weather of $100.4 million, residential and commercial growth of $22.4 million and higher fuel cost recovery of $65.6 million.

Ÿ Fuel used in electric generation and purchased power expenses increased due to higher fuel prices of $65.6 million, increased sales volumes associated with residential and commercial customer growth of $5.2 million and higher sales volumes associated with the effects of weather of $24.3 million. These increases were partially offset by lower residential and commercial average use of $12.7 million. In 2018, purchased power expenses were lower and expenses for fuel used in electric generation were higher due to SCE&G's purchase of CEC and the termination of a related purchase power agreement.

Ÿ Other operation and maintenance expenses increased due to higher legal and other costs arising from the abandonment of the Nuclear Project of approximately $25.6 million and increases in non-labor costs associated with the purchase of CEC of $8.5 million. These increases were partially offset by lower labor costs of $9.4 million, primarily due to the absence of Nuclear Project severance accruals in 2018.

• Impairment loss in each period represents probable disallowances of cost recovery associated with the abandoned Nuclear Project.

Ÿ Depreciation and amortization increased primarily due to net plant additions.

Ÿ Other taxes increased primarily due to higher property taxes associated with net plant additions.

Sales volumes (in GWh) related to the electric operations above, by class, were as follows: 

Classification	2018	2017
Residential	8,366	7,782
Commercial	7,446	7,372
Industrial	6,250	6,212
Other	583	584
Total retail sales	22,645	21,950
Wholesale	1,014	916
Total Sales	23,659	22,866

2018 vs 2017

Retail and wholesale sales volumes increased primarily due to the effects of weather.

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Gas Distribution

Gas Distribution is comprised of the local distribution operations of SCE&G, and for the Company, also includes PSNC Energy. Gas Distribution operating income (including transactions with affiliates) was as follows: 

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Operating revenues	$	935.1	$	876.0	$	435.1	$	405.8
Gas purchased for resale	449.3		393.0		239.0		205.9
Other operation and maintenance	172.6		167.9		71.2		70.6
Depreciation and amortization	93.6		84.9		30.5		29.0
Other taxes	46.9		42.5		31.4		28.5
Operating Income	$	172.7	$	187.7	$	63.0	$	71.8

The effect of abnormal weather conditions on gas distribution operating income is mitigated by the WNA at SCE&G and the CUT at PSNC Energy as further described in Note 3 of the consolidated financial statements in Item 8. Financial Statements and Supplementary Data. The WNA and CUT do not affect sales volumes.

2018 vs 2017

Ÿ Operating revenues increased at SCE&G primarily due to higher gas cost recovery of $23.5 million, customer growth of $9.7 million and higher average use of $1.7 million. These increases were partially offset by a decrease of $7.5 million due to the deferral of estimated amounts to be refunded to customers as a result of the Tax Act. In addition to these factors, operating revenues for the Company increased due to weather at PSNC Energy of $63.6 million, customer growth of $12.3 million and an increased adjustment related to integrity management of $11.9 million. These increases were partially offset by a CUT adjustment of $34.3 million, decreased gas cost recoveries of $14.7 million and $14.8 million due to deferred revenues related to the Tax Act.

Ÿ Gas purchased for resale increased at SCE&G due to increased sales volumes due to weather of $14.5 million, higher gas prices of $9.0 million, higher average use of $4.8 million and firm customer growth of $4.7 million. In addition to these factors, gas purchased for resale at the Company reflects increased sales volumes due to weather at PSNC Energy of $32.1 million and customer growth of $4.6 million. These increases were partially offset by decreased gas costs of $14.7 million and the effect of a CUT adjustment of $3.9 million.

Ÿ Other operation and maintenance expenses increased primarily due to higher labor costs.

Ÿ Depreciation and amortization increased primarily due to net plant additions.

Ÿ Other taxes increased primarily due to higher property taxes associated with net plant additions.

Sales volumes (in MMBTU) related to gas distribution by class, including transportation, were as follows: 

	The Company		Consolidated SCE&G
Classification (in thousands)	2018	2017	2018	2017
Residential	45,477	37,251	14,082	11,285
Commercial	31,640	28,429	13,344	12,565
Industrial	21,543	20,108	19,037	18,091
Transportation gas	57,867	51,587	6,401	6,229
Total	156,527	137,375	52,864	48,170

2018 vs 2017

Residential, commercial and industrial sales volumes at the Company and Consolidated SCE&G increased due to the effects of weather and customer growth. Transportation volumes increased at the Company primarily due to a significant customer expansion and increased natural gas fired electric generation within PSNC Energy's territory.

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Gas Marketing

Gas Marketing is comprised of the Company’s nonregulated marketing operation, SCANA Energy, which operates in the southeast and includes Georgia’s retail natural gas market. Gas Marketing operating revenues and net income were as follows: 

Millions of dollars	2018		2017
Operating revenues	$	935.1	$	1,001.4
Net Income	43.2		26.9

2018 vs 2017

Operating revenues decreased primarily due to the impact of adopting revenue recognition guidance (see Note 3 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data), whereby certain pass through charges are no longer classified as revenues. Net income increased due to the effects of weather.

Other Operating Expenses

Other operating expenses were as follows:

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Other operation and maintenance	$	835.3	$	727.7	$	631.0	$	597.0
Impairment loss	1,376.0		1,118.1		1,376.0		1,118.1
Depreciation and amortization	402.7		381.6		326.8		311.8
Other taxes	276.1		264.2		256.4		246.4

Changes in other operating expenses are largely attributable to the electric operations and gas distribution segments and are addressed in those discussions. In addition, other operation and maintenance expense includes certain legal and other costs arising from the abandonment of the Nuclear Project and the merger with Dominion Energy. Increases in such costs at the Company totaled approximately $81.1 million (including $25.6 million attributable to Consolidated SCE&G). The increases attributable to Consolidated SCE&G are included in amounts described in electric operations.

Net Periodic Pension Benefit Cost

     Other operation and maintenance expense includes net periodic pension benefit cost, which was recorded on the income statements and balance sheets as follows:

	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Income Statement Impact:
Employee benefit costs	$	10.3		$	15.3		$	8.4		$	12.3
Other expense	0.1			0.5			0.1			0.3
Balance Sheet Impact:
Increase in capital expenditures	2.5			5.2			2.0			4.7
Component of amount receivable from Summer Station co-owner	0.7			2.1			0.7			2.1
Decrease in regulatory assets	(1.9		)	(0.8		)	(1.9		)	(0.8		)
Net periodic benefit cost	$	11.7		$	22.3		$	9.3		$	18.6

Pursuant to regulatory orders, SCE&G recovers current pension expense through a rate rider (for retail electric operations) and through cost of service rates (for gas operations), and amortizes pension costs previously deferred in regulatory assets as further described in Note 2 and Note 9 to the consolidated financial statements. Amounts amortized were $2.0 million for retail electric operations and $1.0 million for gas operations for each period presented. Pursuant to regulatory orders, PSNC Energy recovers current pension expense through cost of service rates.

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Other Income (Expense)

Other income (expense), net includes the results of certain incidental non-utility activities of regulated subsidiaries, the activities of certain non-regulated subsidiaries, governance activities of SCANA and AFC. AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. An equity portion of AFC is included in nonoperating income and a debt portion of AFC is included in interest charges (credits), both of which have the effect of increasing reported net income. Components of other income (expense), net were as follows:

	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Other income	$	200.7		$	78.4		$	146.8		$	44.9
Other expense	(46.0		)	(55.2		)	(28.2		)	(31.9		)
AFC - equity funds	18.7			23.2			10.8			14.8

2018 vs 2017

Other income at the Company and Consolidated SCE&G increased primarily due to the recognition of $113.7 million of gains realized upon the settlement of certain interest rate derivative contracts and $6.9 million of gains from land sales. The gains related to the settlement of interest rate derivative contracts were fully offset by downward adjustments to electric revenues pursuant to a previously received SCPSC order related to fuel cost recovery and, as such, had no effect on net income. These increases were partially offset by $10.9 million due to the absence of accrual of carrying costs on unrecovered Nuclear Project costs in 2018 and by $17.5 million due to lower carrying cost accrual on certain other deferred items. Other expense at the Company and Consolidated SCE&G decreased $2.9 million and $1.9 million, respectively, due to changes in non-service cost components of pension and other postretirement benefit expense recognized within other expense. At the Company, the decreases also include lower expenses related to other benefit programs. Equity AFC decreased primarily due to the abandonment of the Nuclear Project in 2017.

Interest Expense

Components of interest expense, net of the debt component of AFC, were as follows:

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Interest on long-term debt, net	$	357.7	$	346.7	$	271.0	$	266.1
Other interest expense	26.3		16.7		32.7		21.5
Total	$	384.0	$	363.4	$	303.7	$	287.6

Interest charges increased primarily due to the issuance of long-term debt at SCE&G and PSNC Energy in 2018, the accrual of interest related to uncertain tax positions and lower debt AFC due to the abandonment of the Nuclear Project. These increases were partially offset by the repayment of long-term debt at GENCO with short-term borrowings at lower rates.

Income Tax Benefit

At the Company and Consolidated SCE&G, income tax benefit increased primarily due to higher losses before taxes as a result of the increased impairment loss recognized in 2018 and the effect of the electric rate change effective in the second quarter.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

All financial instruments described in this section are held for purposes other than trading.

Interest Rate Risk

The tables below provide information about long-term debt issued by the Company and Consolidated SCE&G and other financial instruments that are sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect

19

notional amounts, weighted average interest rates and related maturities. Fair values for debt represent quoted market prices. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data. 

The Company
December 31, 2018	Expected Maturity Date
Millions of dollars	2019	2020	2021	2022	2023	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	54.3	363.8	792.3	261.3	9.8	5,175.2	6,656.7	7,048.3
Average Fixed Interest Rate (%)	3.94	6.30	4.21	5.24	4.69	5.58	5.42	—
Variable Rate ($)	4.4	4.4	4.4	4.4	4.4	116.2	138.2	132.5
Average Variable Interest Rate (%)	3.44	3.44	3.44	3.44	3.44	2.41	1.39	—
Interest Rate Swaps:
Pay Fixed/Receive Variable ($)	4.4	4.4	4.4	4.4	4.4	119.8	146.2	(24.4	)
Average Pay Interest Rate (%)	6.17	6.17	6.17	6.17	6.17	4.45	4.76	—
Average Receive Interest Rate (%)	3.44	3.44	3.44	3.44	3.44	2.41	2.59	—

December 31, 2017	Expected Maturity Date
Millions of dollars	2018	2019	2020	2021	2022	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	722.5	12.0	361.5	490.2	259.3	4,683.9	6,529.4	7,261.8
Average Fixed Interest Rate (%)	6.01	4.31	6.31	4.63	5.26	5.71	5.68	—
Variable Rate ($)	4.4	4.4	4.4	4.4	4.4	120.6	142.6	137.8
Average Variable Interest Rate (%)	2.18	2.18	2.18	2.18	2.18	1.64	1.72	—
Interest Rate Swaps:
Pay Fixed/Receive Variable ($)	554.4	4.4	4.4	4.4	4.4	124.2	696.2	20.4
Average Pay Interest Rate (%)	2.14	6.17	6.17	6.17	6.17	4.51	2.66	—
Average Receive Interest Rate (%)	1.48	2.18	2.18	2.18	2.18	1.91	1.58	—

Consolidated SCE&G
December 31, 2018	Expected Maturity Date
Millions of dollars	2019	2020	2021	2022	2023	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	13.8	13.3	341.8	10.8	9.5	4,725.3	5,114.5	5,406.8
Average Fixed Interest Rate (%)	4.18	4.23	3.52	4.53	5.23	5.64	5.48	—
Variable Rate ($)	—	—	—	—	—	67.8	67.8	63.0
Average Variable Interest Rate (%)	—	—	—	—	—	1.67	1.67	—
Interest Rate Swaps:
Pay Fixed/Receive Variable ($)	—	—	—	—	—	71.4	71.4	(11.2	)
Average Pay Interest Rate (%)	—	—	—	—	—	3.29	3.29	—
Average Receive Interest Rate (%)	—	—	—	—	—	1.67	1.67	—

December 31, 2017	Expected Maturity Date
Millions of dollars	2018	2019	2020	2021	2022	Thereafter	Total	Fair Value
Long-Term Debt:
Fixed Rate ($)	722.5	12.0	11.5	40.2	9.3	4,333.9	5,129.4	5,726.8
Average Fixed Interest Rate (%)	6.01	4.31	4.38	3.58	4.74	5.76	5.77	—
Variable Rate ($)	—	—	—	—	—	67.8	67.8	63.5
Average Variable Interest Rate (%)	—	—	—	—	—	1.21	1.21	—
Interest Rate Swaps:
Pay Fixed/Receive Variable ($)	550.0	—	—	—	—	71.4	621.4	37.4
Average Pay Interest Rate (%)	2.10	—	—	—	—	3.29	2.24	—
Average Receive Interest Rate (%)	1.48	—	—	—	—	1.71	1.51	—

 While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.

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For further discussion of long-term debt and interest rate derivatives, see Note 5 and Note 7 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data.

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Commodity Price Risk

The following table provides information about the Company’s financial instruments, which are limited to financial positions of Energy Marketing and PSNC Energy, that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 MMBTU. Fair value represents quoted market prices.

Expected Maturity	2019	2020	2021
Futures - Long
Settlement Price (a)	2.85	2.82	2.81
Contract Amount (b)	82.2	12.3	0.2
Fair Value (b)	69.8	12.4	0.2
Futures - Short
Settlement Price (a)	2.90	—	—
Contract Amount (b)	31.9	—	—
Fair Value (b)	20.8	—	—
Options - Purchased Call (Long)
Strike Price (a)	2.58	3.54	—
Contract Amount (b)	17.5	2.3	—
Fair Value (b)	1.6	0.1	—
Options - Sold Call (Short)
Strike Price (a)	0.39	—	—
Contract Amount (b)	0.4	—	—
Fair Value (b)	0.5	—	—
Swaps - Commodity
Pay fixed/receive variable (b)	6.1	3.8	0.9
Average pay rate (a)	2.92	2.85	2.73
Average received rate (a)	2.80	2.69	2.74
Fair Value (b)	5.8	3.5	0.9
Pay variable/receive fixed (b)	26.4	8.2	0.8
Average pay rate (a)	2.80	2.70	2.79
Average received rate (a)	2.90	2.80	2.77
Fair Value (b)	27.3	8.5	0.7
Swaps - Basis
Pay variable/receive variable (b)	15.9	—	—
Average pay rate (a)	3.14	—	—
Average received rate (a)	3.15	—	—
Fair Value (b)	16.0	—	—

(a) Weighted average, in dollars

(b) Millions of dollars

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 7 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data.

PSNC Energy utilizes futures, options and swaps to hedge gas purchasing activities. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred. PSNC Energy defers premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program for subsequent recovery from customers.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

SCANA Corporation

Cayce, South Carolina

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of SCANA Corporation and subsidiaries (the "Company") as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive income (loss), changes in common equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes and the financial statement schedule listed in the Part IV at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2019, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company 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 financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/DELOITTE & TOUCHE LLP

Charlotte, North Carolina

February 28, 2019

We have served as the Company's auditor since 1945.

23

SCANA Corporation and Subsidiaries

Consolidated Balance Sheets

December 31, (Millions of dollars)	2018			2017
Assets
Utility Plant in Service	$	15,171		$	14,370
Accumulated Depreciation and Amortization	(5,109		)	(4,611		)
Construction Work in Progress	527			471
Nuclear Fuel, Net of Accumulated Amortization	211			208
Goodwill	210			210
Utility Plant, Net	11,010			10,648
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $143 and $133	267			270
Assets held in trust, net-nuclear decommissioning	190			136
Other investments	22			68
Nonutility Property and Investments, Net	479			474
Current Assets:
Cash and cash equivalents	389			409
Receivables:
Customer, net of allowance for uncollectible accounts of $7 and $6	632			665
Income taxes	—			198
Other	88			105
Inventories:
Fuel	153			143
Materials and supplies	170			161
Prepayments	105			99
Other current assets	12			71
Total Current Assets	1,549			1,851
Deferred Debits and Other Assets:
Regulatory assets	4,380			5,580
Other	236			186
Total Deferred Debits and Other Assets	4,616			5,766
Total	$	17,654		$	18,739

See Notes to Consolidated Financial Statements.

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December 31, (Millions of dollars)	2018			2017
Capitalization and Liabilities
Common Stock - no par value, 143 million shares outstanding for all periods presented	$	2,389		$	2,390
Retained Earnings	2,247			2,915
Accumulated Other Comprehensive Loss	(34		)	(50		)
Total Common Equity	4,602			5,255
Long-Term Debt, Net	6,695			5,906
Total Capitalization	11,297			11,161
Current Liabilities:
Short-term borrowings	173			350
Current portion of long-term debt	59			727
Accounts payable	430			438
Customer deposits and customer prepayments	114			112
Revenue subject to refund	77			—
Taxes accrued	245			214
Interest accrued	89			87
Dividends declared	17			86
Other	72			99
Total Current Liabilities	1,276			2,113
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,112			1,261
Asset retirement obligations	577			568
Pension and postretirement benefits	376			360
Unrecognized tax benefits	38			19
Regulatory liabilities	2,789			3,059
Other	189			198
Total Deferred Credits and Other Liabilities	5,081			5,465
Commitments and Contingencies (Note 11)
Total	$	17,654		$	18,739

See Notes to Consolidated Financial Statements.

25

SCANA Corporation and Subsidiaries

Consolidated Statements of Operations

Years Ended December 31, (Millions of dollars, except per share amounts)	2018			2017			2016
Operating Revenues:
Electric	$	2,322		$	2,659		$	2,614
Gas-regulated	934			874			788
Gas-nonregulated	796			874			825
Total Operating Revenues	4,052			4,407			4,227
Operating Expenses:
Fuel used in electric generation	671			594			576
Purchased power	92			80			64
Gas purchased for resale	1,128			1,156			1,054
Other operation and maintenance	835			728			741
Impairment loss	1,376			1,118			—
Depreciation and amortization	403			382			371
Other taxes	276			264			254
Total Operating Expenses	4,781			4,322			3,060
Operating Income (Loss)	(729		)	85			1,167
Other Income (Expense), net	173			47			41
Interest charges, net of allowance for borrowed funds used during construction of $12, $18 and $19	(384		)	(363		)	(342		)
Income (Loss) Before Income Tax Expense (Benefit)	(940		)	(231		)	866
Income Tax Expense (Benefit)	(412		)	(112		)	271
Net Income (Loss)	$	(528	)	$	(119	)	$	595
Earnings (Loss) Per Share of Common Stock	$	(3.70	)	$	(0.83	)	$	4.16
Weighted Average Common Shares Outstanding (millions)	143			143			143

See Notes to Consolidated Financial Statements.

26

SCANA Corporation and Subsidiaries

Consolidated Statements of Comprehensive Income (Loss)

Years Ended December 31, (Millions of dollars)	2018			2017			2016
Net Income (Loss)	$	(528	)	$	(119	)	$	595
Other Comprehensive Income (Loss), net of tax:
Unrealized Gains (Losses) on Cash Flow Hedging Activities:
Arising during period, net of tax of $(1), $(4) and $2	(2		)	(7		)	4
Reclassified as interest expense, net of tax of $2, $4 and $4	9			7			7
Reclassified as gas purchased for resale, net of tax of $2, $- and $4	7			(1		)	6
Net unrealized gains (losses) on cash flow hedging activities	14			(1		)	17
Deferred Costs of Employee Benefit Plans (Note 9):
Gains arising during the period, net of tax of $1, $- and $-	2			—			—
Reclassified to net income, net of tax of $-, $- and $-	—			—			(1		)
Net deferred gains (costs) of employee benefit plans	2			—			(1		)
Other Comprehensive Income (Loss)	16			(1		)	16
Total Comprehensive Income (Loss)	$	(512	)	$	(120	)	$	611

See Notes to Consolidated Financial Statements.

27

SCANA Corporation and Subsidiaries

Consolidated Statements of Cash Flows

For the Years Ended December 31, (Millions of dollars)	2018			2017			2016
Cash Flows From Operating Activities:
Net Income (Loss)	$	(528	)	$	(119	)	$	595
Adjustments to reconcile net income to net cash provided from operating activities:
Impairment loss	1,376			1,118			—
Gain on sale of investments	(30		)	—			—
Deferred income taxes, net	(151		)	(911		)	242
Depreciation and amortization	434			406			389
Amortization of nuclear fuel	47			44			57
Allowance for equity funds used during construction	(19		)	(23		)	(29		)
Carrying cost recovery	(6		)	(34		)	(17		)
Changes in certain assets and liabilities:
Receivables	37			(56		)	(112		)
Income tax receivable	198			(56		)	(142		)
Inventories	(88		)	(93		)	(43		)
Prepayments	(4		)	(5		)	11
Regulatory assets	(199		)	181			(114		)
Regulatory liabilities	(350		)	1,051			(2		)
Accounts payable	61			24			44
Revenue subject to refund	77			—			—
Unrecognized tax benefits	19			(224		)	175
Taxes accrued	31			13			(41		)
Pension and other postretirement benefits	16			(20		)	51
Other assets	61			(47		)	(44		)
Other liabilities	(18		)	(80		)	72
Net Cash Provided From Operating Activities	964			1,169			1,092
Cash Flows From Investing Activities:
Property additions and construction expenditures	(890		)	(1,225		)	(1,579		)
Proceeds from monetization of guaranty settlement	—			1,096			—
Proceeds from investments (including derivative collateral returned)	227			145			860
Purchase of investments (including derivative collateral posted)	(155		)	(143		)	(788		)
Payments upon interest rate derivative contract settlement	—			(39		)	(113		)
Proceeds from interest rate derivative contract settlement	115			—			—
Net Cash Used For Investing Activities	(703		)	(166		)	(1,620		)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	935			150			592
Repayments of long-term debt	(830		)	(17		)	(117		)
Dividends	(209		)	(344		)	(325		)
Short-term borrowings, net	(177		)	(591		)	410
Net Cash Provided From (Used For) Financing Activities	(281		)	(802		)	560
Net Increase (Decrease) in Cash and Cash Equivalents	(20		)	201			32
Cash and Cash Equivalents, January 1	409			208			176
Cash and Cash Equivalents, December 31	$	389		$	409		$	208
Supplemental Cash Flow Information:
Cash for—Interest paid (net of capitalized interest of $12, $18 and $19)	$	356		$	346		$	328
—Income taxes paid	4			2			229
—Income taxes received	206			184			166
Noncash Investing and Financing Activities:
Accrued construction expenditures	85			139			109
Capital leases	11			8			15
Contributed construction	6			—			—

 See Notes to Consolidated Financial Statements.

28

SCANA Corporation and Subsidiaries

Consolidated Statements of Changes in Common Equity

	Common Stock									Accumulated Other Comprehensive Income (Loss)
Millions	Shares	Outstanding Amount		Treasury Amount			Retained Earnings			Gains (Losses) on Cash Flow Hedges			Deferred Costs of Employee Benefit Plans			Total AOCI			Total
Balance as of January 1, 2016	143	$	2,402	$	(12	)	$	3,118		$	(53	)	$	(12	)	$	(65	)	$	5,443
Net Income							595												595
Other Comprehensive Income (Loss)
Gains (Losses) arising during the period										4			(1		)	3			3
Losses/amortization reclassified from AOCI										13			—			13			13
Total Comprehensive Income (Loss)							595			17			(1		)	16			611
Dividends Declared							(329		)										(329		)
Balance as of December 31, 2016	143	2,402		(12		)	3,384			(36		)	(13		)	(49		)	5,725
Net Loss							(119		)										(119		)
Other Comprehensive Income (Loss)
Losses arising during the period										(7		)	—			(7		)	(7		)
Losses/amortization reclassified from AOCI										6			—			6			6
Total Comprehensive Income (Loss)							(119		)	(1		)	—			(1		)	(120		)
Dividends Declared							(350		)										(350		)
Balance as of December 31, 2017	143	2,402		(12		)	$	2,915		$	(37	)	$	(13	)	$	(50	)	$	5,255
Net Loss							(528		)										(528		)
Other Comprehensive Income (Loss)
Gains (losses) arising during the period										(2		)	2			—			—
Losses/amortization reclassified from AOCI										16			—			16			16
Total Comprehensive Income (Loss)							(528		)	14			2			16			(512		)
Purchase of Treasury Stock				(1		)													(1		)
Dividends Declared							(140		)										(140		)
Balance as of December 31, 2018	143	$	2,402	$	(13	)	$	2,247		$	(23	)	$	(11	)	$	(34	)	$	4,602

Dividends declared per share of common stock were $0.98, $2.45 and $2.30 for 2018, 2017 and 2016, respectively.

See Notes to Consolidated Financial Statements.

29

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

South Carolina Electric & Gas Company

Cayce, South Carolina

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of South Carolina Electric & Gas Company and affiliates (the "Company") as of December 31, 2018 and 2017, the related consolidated statements of comprehensive income (loss), changes in equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes and the financial statement schedule listed in the Part IV at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company'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 the Company 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 financial statements are free of material misstatement, whether due to error or fraud. The Company 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 the Company’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 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/DELOITTE & TOUCHE LLP

Charlotte, North Carolina

February 28, 2019

We have served as the Company's auditor since 1945.

30

South Carolina Electric & Gas Company and Affiliates

Consolidated Balance Sheets

December 31, (Millions of dollars)	2018			2017
Assets
Utility Plant in Service	$	12,803		$	12,161
Accumulated Depreciation and Amortization	(4,581		)	(4,124		)
Construction Work in Progress	350			375
Nuclear Fuel, Net of Accumulated Amortization	211			208
Utility Plant, Net ($711 and $711 related to VIEs)	8,783			8,620
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	72			71
Assets held in trust, net-nuclear decommissioning	190			136
Other investments	1			2
Nonutility Property and Investments, Net	263			209
Current Assets:
Cash and cash equivalents	377			395
Receivables:
Customer, net of allowance for uncollectible accounts of $4 and $4	344			390
Affiliated companies	359			32
Income taxes	—			198
Other	68			85
Inventories:
Fuel	89			90
Materials and supplies	158			149
Prepayments	82			82
Other current assets	1			56
Total Current Assets ($96 and $191 related to VIEs)	1,478			1,477
Deferred Debits and Other Assets:
Regulatory assets	4,256			5,476
Other	183			164
Total Deferred Debits and Other Assets ($34 and $50 related to VIEs)	4,439			5,640
Total	$	14,963		$	15,946

See Notes to Consolidated Financial Statements.

31

December 31, (Millions of dollars)	2018			2017
Capitalization and Liabilities
Common Stock - no par value, 40.3 million shares outstanding for all periods presented	$	2,860		$	2,860
Retained Earnings	1,279			1,982
Accumulated Other Comprehensive Loss	(3		)	(4		)
Total Common Equity	4,136			4,838
Noncontrolling interest	179			142
Total Equity	4,315			4,980
Long-Term Debt, net	5,132			4,441
Total Capitalization	9,447			9,421
Current Liabilities:
Short-term borrowings	73			252
Current portion of long-term debt	14			723
Accounts payable	267			251
Affiliated payables	347			102
Customer deposits and customer prepayments	83			70
Revenue subject to refund	77			—
Taxes accrued	239			208
Interest accrued	72			67
Dividends declared	10			82
Other	32			49
Total Current Liabilities	1,214			1,804
Deferred Credits and Other Liabilities:
Deferred income taxes, net	989			1,173
Asset retirement obligations	542			529
Pension and postretirement benefits	232			217
Unrecognized tax benefits	38			19
Regulatory liabilities	2,380			2,667
Other	105			97
Other - affiliate	16			19
Total Deferred Credits and Other Liabilities	4,302			4,721
Commitments and Contingencies (Note 11)
Total	$	14,963		$	15,946

See Notes to Consolidated Financial Statements.

32

South Carolina Electric & Gas Company and Affiliates

Consolidated Statements of Comprehensive Income (Loss)

For the Years Ended December 31, (Millions of dollars)	2018			2017			2016
Operating Revenues:
Electric	$	2,322		$	2,659		$	2,614
Electric - nonconsolidated affiliate	5			5			5
Gas	434			405			366
Gas - nonconsolidated affiliate	1			1			1
Total Operating Revenues	2,762			3,070			2,986
Operating Expenses:
Fuel used in electric generation	531			465			472
Fuel used in electric generation - nonconsolidated affiliate	140			129			104
Purchased power	92			80			64
Gas purchased for resale	239			206			174
Gas purchased for resale - nonconsolidated affiliate	—			—			9
Other operation and maintenance	449			417			403
Other operation and maintenance - nonconsolidated affiliate	182			180			199
Impairment loss	1,376			1,118			—
Depreciation and amortization	327			312			302
Other taxes	251			241			227
Other taxes - nonconsolidated affiliate	6			5			7
Total Operating Expenses	3,593			3,153			1,961
Operating Income (Loss)	(831		)	(83		)	1,025
Other Income (Expense), net	129			28			19
Interest charges, net of allowance for borrowed funds used during construction of $9, $15 and $18	(303		)	(288		)	(270		)
Income (Loss) Before Income Tax Expense	(1,005		)	(343		)	774
Income Tax Expense (Benefit)	(416		)	(171		)	248
Net Income (Loss)	(589		)	(172		)	526
Other Comprehensive Income
Deferred cost of employee benefit plans, net of tax of $-, $- and $-	1			—			—
Total Comprehensive Income (Loss)	(588		)	(172		)	526
Less Comprehensive Income Attributable to Noncontrolling Interest	25			13			13
Comprehensive Income Available (Loss Attributable) to Common Shareholder	$	(613	)	$	(185	)	$	513

See Notes to Consolidated Financial Statements.

33

South Carolina Electric & Gas Company and Affiliates

Consolidated Statements of Cash Flow

For the Years Ended December 31, (Millions of dollars)	2018			2017			2016
Cash Flows From Operating Activities:
Net income (Loss)	$	(589	)	$	(172	)	$	526
Adjustments to reconcile net income to net cash provided from operating activities:
Impairment loss	1,376			1,118			—
Deferred income taxes, net	(184		)	(780		)	207
Depreciation and amortization	342			323			310
Amortization of nuclear fuel	47			44			57
Allowance for equity funds used during construction	(11		)	(15		)	(26		)
Carrying cost recovery	(6		)	(34		)	(17		)
Changes in certain assets and liabilities:
Receivables	50			(32		)	(47		)
Receivables - affiliate	(2		)	12			(3		)
Income tax receivable	198			(145		)	(53		)
Inventories	(54		)	(60		)	(35		)
Prepayments	—			6			(4		)
Regulatory assets	(179		)	185			(94		)
Other regulatory liabilities	(360		)	899			(5		)
Accounts payable	61			20			8
Accounts payable - affiliate	—			(28		)	13
Revenue subject to refund	77			—			—
Unrecognized tax benefits	19			(241		)	192
Taxes accrued	31			13			(104		)
Pension and other postretirement benefits	15			(21		)	39
Other assets	77			(46		)	(99		)
Other liabilities	22			(43		)	58
Other liabilities - affiliate	(3		)	3			(1		)
Net Cash Provided From Operating Activities	927			1,006			922
Cash Flows From Investing Activities:
Property additions and construction expenditures	(633		)	(928		)	(1,399		)
Proceeds from monetization of guaranty settlement	—			1,096			—
Proceeds from investments and sales of assets (including derivative collateral returned)	40			118			794
Purchase of investments (including derivative collateral posted)	(29		)	(122		)	(740		)
Purchase of investments - affiliate	(111		)	—			—
Payments upon interest rate derivative contract settlement	—			(39		)	(113		)
Proceeds from interest rate derivative contract settlement	115			—			—
Proceeds from investments - affiliate	111			—			9
Investment in affiliate	(325		)	(28		)	—
Net Cash Provided From (Used For) Investing Activities	(832		)	97			(1,449		)
Cash Flows From Financing Activities:
Proceeds from issuance of debt	795			—			494
Repayment of long-term debt	(825		)	(12		)	(112		)
Dividends	(173		)	(319		)	(301		)
Short-term borrowings, net	(179		)	(552		)	384
Money pool borrowings, net	245			8			(4		)
Contribution from parent	24			3			100
Net Cash Provided From (Used For) Financing Activities	(113		)	(872		)	561
Net Increase (Decrease) in Cash and Cash Equivalents	(18		)	231			34
Cash and Cash Equivalents, January 1	395			164			130
Cash and Cash Equivalents, December 31	$	377		$	395		$	164
Supplemental Cash Flow Information:
Cash for—Interest paid (net of capitalized interest of $9, $15 and $18)	$	264		$	269		$	251
—Income taxes paid	3			47			289
—Income taxes received	216			145			189
Noncash Investing and Financing Activities:
Accrued construction expenditures	69			99			95
Capital leases	8			8			14
Contributed construction	6			—			—

See Notes to Consolidated Financial Statements.

34

South Carolina Electric & Gas Company and Affiliates

Consolidated Statements of Changes in Equity

	Common Stock						Accumulated Other Comprehensive Income (Loss)			Non-controlling Interest
Millions	Shares	Amount		Retained Earnings									Total Equity
Balance at January 1, 2016	40	$	2,760	$	2,265		$	(3	)	$	129		$	5,151
Earnings (Loss) Available for (Attributable to) Common Shareholder				513						13			526
Deferred Cost of Employee Benefit Plans, net of tax $-							—						—
Total Comprehensive Income				513			—			13			526
Capital contributions from parent		100								—			100
Cash dividends declared				(297		)				(8		)	(305		)
Balance at December 31, 2016	40	2,860		2,481			(3		)	134			5,472
Earnings (Loss) Available for (Attributable to) Common Shareholder				(185		)				13			(172		)
Deferred Cost of Employee Benefit Plans, net of tax $-							(1		)				(1		)
Total Comprehensive Income				(185		)	(1		)	13			(173		)
Capital contributions from parent		—								3			100
Cash dividends declared				(314		)				(8		)	(322		)
Balance at December 31, 2017	40	2,860		1,982			(4		)	142			4,980
Earnings (Loss) Available for (Attributable to) Common Shareholder				(614		)				25			(589		)
Deferred Cost of Employee Benefit Plans, net of tax $-							1						1
Total Comprehensive Income (Loss)				(614		)	1			25			(588		)
Capital contributions from parent		—								24			24
Cash dividends declared				(89		)				(12		)	(101		)
Balance at December 31, 2018	40	$	2,860	$	1,279		$	(3	)	$	179		$	4,315

See Notes to Consolidated Financial Statements.

35

SCANA Corporation and Subsidiaries

South Carolina Electric & Gas Company and Affiliates

Notes to Consolidated Financial Statements

The following notes to the consolidated financial statements are a combined presentation. Except as otherwise indicated herein, each note applies to the Company and Consolidated SCE&G; however, Consolidated SCE&G makes no representation as to information relating solely to SCANA Corporation or its subsidiaries (other than Consolidated SCE&G).

1.             SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Principles of Consolidation

Effective January 1, 2019, SCANA became a wholly-owned subsidiary of Dominion Energy under the terms of the Merger Agreement. See additional discussion in Note 2 and Note 11.

The Company

SCANA, a South Carolina corporation, is a holding company created in 1984. The Company primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina, and the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia.

The accompanying consolidated financial statements reflect the accounts of SCANA and the following wholly-owned subsidiaries.

Regulated businesses	Nonregulated businesses
South Carolina Electric & Gas Company	SCANA Energy Marketing, Inc.
South Carolina Fuel Company, Inc.	SCANA Services, Inc.
South Carolina Generating Company, Inc.	SCANA Corporate Security Services, Inc.
Public Service Company of North Carolina, Incorporated	SCANA Communications Holdings, Inc.

SCANA reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. Discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

Consolidated SCE&G

SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA. Consolidated SCE&G primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s 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, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $500 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5.

36

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

No estimate is made for legal costs expected to be incurred in connection with loss contingencies. Such costs are recorded when incurred.

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 AFC, 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.

AFC 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. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 7.7% for 2018, 5.6% for 2017, and 5.3% for 2016. Consolidated SCE&G calculated AFC using average composite rates of 7.0% for 2018, 3.9% for 2017, and 4.7% for 2016. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.

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 2018 composite weighted average depreciation rates for utility plant by function were as follows:

	The Company		Consolidated SCE&G
Generation	2.61	%	2.61	%
Transmission	2.47	%	2.74	%
Distribution	2.48	%	2.41	%
Storage	2.48	%	2.71	%
General and other	5.64	%	3.18	%

SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization 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 SCPSC 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.

SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2018, and 2017, SCE&G incurred $16.3 million and $26.1 million, respectively, for turbine maintenance.

Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 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 SCE&G was responsible totaled $28.6 million in 2018 and $23.2 million in 2017.

37

Goodwill

The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company has tested goodwill for impairment annually as of January 1, unless indicators, events or circumstances required interim testing to be performed. The Company performed its test on January 1, 2019 and intends to test goodwill annually on April 1, effective April 1, 2019. Under current accounting guidance, the Company may perform a qualitative assessment of impairment. Based on this assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to make a quantitative estimate of the fair value of the reporting unit and to compare that amount to its carrying value. If the Company is required to make a quantitative assessment or if it chooses to do so without first performing a qualitative one, and if the quantitative assessment indicates a carrying value in excess of fair value, an impairment charge would be required. Any such charge would be treated as an operating expense.

For each period presented, assets with a carrying value of $210 million for PSNC Energy (Gas Distribution segment), net of a writedown of $230 million taken in 2002, were classified as goodwill. The Company performed a quantitative assessment of goodwill in its evaluation as of January 1, 2019 and performed a qualitative assessment of goodwill in its evaluation as of January 1, 2018. No impairment of goodwill was required based on these evaluations.

Nuclear Decommissioning

Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $625.8 million, stated in 2018 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. 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 SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ($3.2 million pre-tax 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 Unit 1 on an after-tax basis.

Cash and Cash Equivalents

Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds. At December 31, 2018, cash and cash equivalents at the Company and Consolidated SCE&G included approximately $115.3 million held in escrow pending consummation of the merger with Dominion Energy and final approval of a legal settlement in the SCE&G Ratepayer Case. As such, the Company and Consolidated SCE&G did not consider these amounts to be restricted at December 31, 2018. See Claims and Litigation in Note 11 for additional discussion.

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 3. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $217.5 million at December 31, 2018 and $220.9 million at December 31, 2017 for the Company. Unbilled revenues totaled $129.3 million at December 31, 2018 and $140.3 million at December 31, 2017 for Consolidated SCE&G.

Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station.

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

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inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable.

PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 46% and 39% of PSNC Energy’s natural gas inventory at December 31, 2018 and December 31, 2017, respectively, with a carrying value of $13.9 million and $11.5 million, respectively. Under the terms of this agreement, PSNC Energy receives storage asset management feesof which 75% are credited to customers. This agreement has been extended and expires October 31, 2020.

Income Taxes

SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 6 for a discussion of the impact of adjustments recorded in connection with enactment of the Tax Act.

Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA for all periods presented. Also, under provisions of an income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions.

Regulatory Assets and Regulatory Liabilities

The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods that differ from those in which the costs would be charged to expense, or record revenues in periods that differ from those in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified on the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively.

Debt Issuance Premiums, Discounts and Other Costs

Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred credits or debits and are amortized over the term of the replacement debt, also as interest charges.

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 and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense).

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Revenue Recognition

Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed.

Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings.

SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews.

Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of operations. 

Earnings (Loss) Per Share

The Company computes basic earnings (loss) per share by dividing net income (loss) by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings (loss) per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.

New Accounting Matters

Recently Adopted

In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact or no significant impact on their respective financial statements except as indicated.

• Goodwill impairment guidance, issued in January 2017, removed Step 2 of the goodwill impairment test.

• Guidance for revenue arising from contracts with customers uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods were not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3.

• The required presentation of net periodic pension and postretirement benefit costs has been changed to distinguish between service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees. Non-service cost components are now excluded from operating income. This guidance has been applied retrospectively for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017 and 2016.

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Increase (Decrease) Millions of dollars	The Company						Consolidated SCE&G
Year Ended December 31	2017			2016			2017			2016
Other operation and maintenance	$	(9	)	$	(14	)	$	(7	)	$	(12	)
Total Operating Expenses	(9		)	(14		)	(7		)	(12		)
Operating Income	9			14			7			12
Other Income (Expense), Net	(9		)	(14		)	(7		)	(12		)

In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost component, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs. Effective January 1, 2018, amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets.

• Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things.

• Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented.

• Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented.

Pending Adoption

The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below.

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 currently 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 is effective for the Company's and Consolidated SCE&G's interim and annual reporting periods beginning January 1, 2019. This revised accounting guidance will be adopted using a modified-retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Company and Consolidated SCE&G are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Company and Consolidated SCE&G will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. The Company and Consolidated SCE&G anticipate that the adoption of this guidance will result in approximately $30 million to $35 million and $15 million to $20 million, respectively, of offsetting right-of-use assets and liabilities added to their consolidated balance sheets for operating leases in effect at the adoption date. No material changes are expected to the Company's and Consolidated SCE&G's results of operations.

In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and

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Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 and do not expect it to have a significant impact on their respective financial statements.

In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 on a prospective basis. Upon adoption, the Company and Consolidated SCE&G expect to record cumulative effect adjustments to retained earnings and AOCI in their statements of changes in common equity (in the amount of $8 million and $1 million at the Company and Consolidated SCE&G, respectively) and do not expect any other significant impact on their financial statements. The amounts to be reclassified reflect the impact of the reduction in the federal income tax rate arising from the Tax Act, and the related federal benefit of state income taxes, on the components of the Company’s and Consolidated SCE&G’s AOCI.

In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. A modified-retrospective approach is required upon adoption, whereby a cumulative-effect adjustment to retained earnings is made as of the beginning of the first reporting period in which the guidance is effective. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements.

In August 2018, the FASB issued accounting guidance to modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance must be applied retrospectively to all periods presented. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position.

2.             RATE AND OTHER REGULATORY MATTERS

Rate Matters

Tax Act Regulatory Proceedings

The Tax Act lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the SCPSC and NCUC have required SCE&G and PSNC Energy to track and defer impacts related to the Tax 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 Tax Act. Certain of these amounts are protected under normalization rules and will be amortized over the remaining regulatory life of the property, and certain of these amounts will be amortized to the benefit of customers, as instructed by regulators, which ranges from 5 years to 50 years.

As of December 31, 2018, SCE&G has recorded approximately $73.7 million as Revenue subject to refund and approximately $3.7 million as Regulatory liabilities on the consolidated balance sheet for the Company and Consolidated SCE&G, and PSNC Energy has recorded approximately $15.4 million of such deferrals within Regulatory liabilities on the consolidated balance sheet for the Company. These amounts were collected through customer rates in 2018 and include the accrual of estimated carrying costs. In addition, the Company and Consolidated SCE&G have recorded amounts related to excess deferred income taxes arising from the Tax Act within Regulatory liabilities. For a discussion of related actions taken by the SCPSC and NCUC, see Electric - Other, Gas - SCE&G, and Gas - PSNC Energy below.

Electric - BLRA and Merger Approval Order

In 2016, the SCPSC approved revised rates under the BLRA to incorporate financing cost of SCE&G's incremental construction work in progress incurred for the Nuclear Project. Rate adjustments resulted in approximately $64.4 million in additional revenue on an annual basis and were effective for bills rendered on and after November 27, 2016. Such rate adjustments were based on SCE&G's updated cost of debt and capital structure and on an allowed ROE of 10.5% applied prospectively for purposes of calculating revised rates under the BLRA on and after January 1, 2016. No revised rates filings were pursued after this 2016 approval.

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In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for Unit 2 and Unit 3 which had been developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, the ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option included in that October 2015 contract amendment. By order dated February 28, 2017, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement, and that denial was not appealed.

On July 2 and 3, 2018, the SCPSC issued orders implementing a legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from customers under the BLRA. These orders reduced the portion of SCE&G's retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer's bill to approximately 3.2%, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. These lower rates remained in effect until February 2019 pursuant to the Merger Approval Order.

On December 21, 2018, the SCPSC issued the Merger Approval Order. The order adopted Dominion Energy's Plan-B Levelized Customer Benefits Plan whereby the average bill for an SCE&G residential electric customer would approximate that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the SCPSC retroactive to April 1, 2018. The Merger Approval Order established an allowed ROE of 9.9% on unrecovered Nuclear Project costs, and resulted in the following findings and conditions:

• No capital costs related to the Nuclear Project incurred after March 12, 2015 will be recoverable by SCE&G.

• SCE&G will provide refunds and restitution to customers from prior years' revenues totaling an aggregate $2.039 billion, comprised of $1.032 billion to be credited to customers over 20 years and $1.007 billion credited to customers over approximately 11 years.

• Except for rate adjustments for fuel and environmental costs, demand side management costs, and other rates routinely adjusted on an annual or biannual basis, SCE&G will freeze retail electric base rates at current levels until January 1, 2021.

• SCE&G's natural gas customers will receive a refund totaling $2.45 million in 2019, 2020 and 2021 combined.

• Corporate giving will increase above historical levels by $1 million per year for at least five years.

• SCE&G will not seek to pass on to ratepayers its initial capital investment in CEC, a 540-MW combined-cycle natural gas-fired generating facility, and will not seek to pass on to ratepayers any acquisition premium costs, transition costs, or transaction cost associated with the merger.

Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. On February 12, 2019, the SCPSC issued a ruling (1) finding that SCE&G was imprudent in its actions by not disclosing material information to the ORS and the SCPSC, and (2) denying the petitions for rehearing or reconsideration as to other issues raised in the various petitions. The Merger Approval Order and the ruling are subject to appeal by various parties. The Company and Consolidated SCE&G cannot predict the outcome of these matters. See also Note 11.

Electric - Cost of Fuel

SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G.

By order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G reduced the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G also began to recover projected DER program costs of approximately $6.9 million beginning with the first billing cycle of May 2016.

By order dated April 27, 2017, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component to produce a projected under recovery of $61.0 million over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately $16.5 million. Additionally, deferral of carrying costs would be allowed for base fuel component under-collected balances as they occurred.

On April 25, 2018, the SCPSC approved SCE&G’s proposal to increase the total fuel cost component of retail electric rates. Specifically, the SCPSC approved an increase to certain environmental, avoided capacity and DER program cost

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components and SCE&G’s agreement to maintain its base fuel component to produce a projected under-recovered balance of approximately $1.3 million at the end of the 12-month period beginning with the first billing cycle of May 2018. This projected under-recovered balance includes the effect of offsetting fuel cost recovery with gains realized from the settlement of certain interest rate derivatives in 2018. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2018, projected DER program costs of approximately $29.3 million. Petitions for rehearing and reconsideration were filed by various parties, and on October 30, 2018, the SCPSC issued an order granting one such petition related to SCE&G 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 SCE&G is required to pay to solar energy developers, and these appeals are pending. The Company and Consolidated SCE&G cannot predict the outcome of these matters.

On February 8, 2019, SCE&G filed with the SCPSC a proposal to decrease the total fuel cost component of retail electric rates. In the filing, SCE&G proposed to maintain its base fuel component at the current level to produce a projected under-recovered balance of approximately $35.4 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. SCE&G also proposed to reduce its variable environmental component and maintain or reduce its DER components.  A public hearing on this matter is scheduled to be held in April 2019.

Electric - Base Rates

Pursuant to an SCPSC order, SCE&G removed from rate base certain deferred income tax assets arising from capital expenditures related to Unit 2 and Unit 3 and accrued carrying costs on those amounts during periods in which they were not included in rate base. Such carrying costs were determined at SCE&G’s weighted average long-term debt borrowing rate and were recorded as a regulatory asset and other income. Carrying costs totaled $18.8 million during 2017 and $14.0 million during 2016. As part of the Nuclear Project impairment loss described in Note 11, accumulated carrying costs related to these deferred income tax assets totaling $51.0 million were written off in 2017.

Electric - Other

The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues (both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below:

Year	Effective	Amount
2018	First billing cycle of May	$33.0 million
2017	First billing cycle of May	$37.0 million
2016	First billing cycle of May	$37.6 million

In January 2019, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved the filing would allow recovery of approximately $30.3 million of costs and net lost revenues associated with DSM Programs, along with an incentive to invest in such programs.

SCE&G utilizes a pension costs rider approved by the SCPSC which is designed to allow recovery of projected pension costs, including under-collected balances or net of over-collected balances, as applicable. The rider is typically reviewed for adjustment every 12 months with any resulting increase or decrease going into effect beginning with the first billing cycle in May. In 2017, this rider was adjusted to decrease annual revenue by approximately $11.9 million. No adjustment was made in 2018. No adjustment has been proposed in 2019.

As part of the Merger Approval Order, the SCPSC approved refunds of approximately $100 million by SCE&G for the impact of the lower federal tax rate resulting from the Tax Act. The refunds include amounts which had been collected through customer rates in 2018 and January 2019 and also include the effects of the amortization of certain excess deferred taxes during the same period. At December 31, 2018, amounts to be refunded to electric customers totaled approximately $91 million, and were comprised of approximately $70 million included within Revenue subject to refund and approximately $21 million included within Regulatory liabilities. These refunds have been included in bills rendered on and after the first billing cycle of

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February 2019. In addition, the SCPSC 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 Tax Act will be amortized to the benefit of customers. This tax rider is expected to reduce base rates to customers by approximately $67 million in each of 2019 and 2020, effective with the first billing cycle of February 2019. Unamortized excess deferred income taxes that remain at the end of 2020 will be considered in future rate proceedings.

Gas - SCE&G

The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: 

Year	Action			Amount
2018	4.6	%	Decrease	$19.7 million	*
2017	2.2	%	Increase	$8.6 million
2016	1.2	%	Increase	$4.1 million

*Includes the impact of the lower federal corporate tax rate resulting from the Tax Act. The SCPSC also approved revised rate schedules for natural gas service that include a rider to refund certain amounts previously collected from customers for SCE&G's income taxes.

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G'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 SCPSC.

Gas - PSNC Energy

PSNC Energy's Rider D rate mechanism allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales.

PSNC Energy establishes rates using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.

On October 28, 2016, the NCUC granted PSNC Energy a net annual increase of approximately $19.1 million, or 4.39%, in rates and charges to customers, and set PSNC Energy's authorized ROE at 9.7%. In addition, the NCUC has authorized PSNC Energy to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy files biannual applications to adjust its rates for this purpose. The NCUC has approved those applications for the incremental increase to annual revenue requirements, as follows:

Rates Effective	2018	2017
March 1	$14.7 million	$1.9 million
September 1	$1.1 million	$0.7 million

On February 15, 2019, PSNC Energy submitted its biannual application to adjust rates associated with its pipeline integrity tracker. As approved by the NCUC, the filing increases PSNC Energy's allowed recovery by approximately $1.7 million effective March 1, 2019.    

On November 19, 2018, the NCUC issued an order approving the SCANA Combination subject to a stipulation agreement with the following provisions: (1) customer bill credits of $1.25 million in each of January 2019, 2020 and 2021; (2) a rate moratorium until November 1, 2021 other than for rate adjustments pursuant to the CUT, the Integrity Management Tracker and the PGA; and (3) an agreement that direct merger-related expenses will be excluded from PSNC Energy regulated expenses for ratemaking purposes.

On December 17, 2018, the NCUC issued an order approving PSNC Energy's proposed adjustments to customer rates to reflect the reduction in the federal corporate tax rate arising from the Tax Act. These lower rates became effective for service

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rendered on and after January 1, 2019. The impact of the lower tax rate collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC Energy's next general rate case proceeding or in three years, whichever is sooner (i.e., no later than October 25, 2021). The reduction in the federal corporate tax rate and its impact on PSNC Energy's various rate riders will be addressed in future proceedings related to those riders.

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, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Except for certain unrecovered nuclear project costs and other unrecovered plant, 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.

	The Company				Consolidated SCE&G
	December 31,				December 31,
Millions of dollars	2018		2017		2018		2017
Regulatory Assets:
Unrecovered Nuclear Project costs	$	2,768	3,976		$	2,768	3,976
AROs and related funding	406		434		380		410
Deferred employee benefit plan costs	302		305		272		273
Deferred losses on interest rate derivatives	448		456		448		456
Other unrecovered plant	93		105		93		105
DSM Programs	65		59		65		59
Pipeline integrity management costs	73		51		9		8
Environmental remediation costs	27		30		24		25
Deferred storm damage costs	35		24		35		24
Deferred transmission operating costs	15		—		15		—
Other	148		140		147		140
Total Regulatory Assets	$	4,380	$	5,580	$	4,256	$	5,476

Regulatory Liabilities:
Monetization of guaranty settlement	$	1,098	1,095		$	1,098	1,095
Accumulated deferred income taxes	814		1,076		659		914
Asset removal costs	779		757		541		527
Deferred gains on interest rate derivatives	77		131		77		131
Other	21		—		5		—
Total Regulatory Liabilities	$	2,789	$	3,059	$	2,380	$	2,667

The carrying amount of the regulatory asset for unrecovered Nuclear Project costs has been recorded based on such amount not being probable of loss in accordance with the accounting guidance on abandonments, whereas the other regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under applicable GAAP for regulated operations. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include 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 further discussed above and in Note 11. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts embodied in rate orders or applicable state law. The costs are currently not being recovered but are expected to be recovered through rates in future periods. In the future, as a result of deregulation, changes in state law, other changes in the regulatory environment or changes in accounting requirements or other adverse legislative or regulatory developments, the Company or Consolidated SCE&G could be required to write off all or a portion of its regulatory assets and liabilities. Such an event could have a material effect on the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded.

Unrecovered Nuclear Project costs represents expenditures by SCE&G that have been reclassified from construction work in progress and, pursuant to the Merger Approval Order and subsequent SCANA Combination, are to be recovered over a

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20-year period ending in 2039. In 2017, such amounts were recorded pending a final determination by the SCPSC. See Note 11 for a discussion of impairment charges related to the Nuclear Project.

AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 106 years.

Employee benefit plan costs of the regulated utilities 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 SCPSC regulatory orders. SCE&G recovers deferred pension costs through utility rates of approximately $2 million annually for electric operations, which will end in 2044, and approximately $1 million annually for gas operations, which will end in 2027. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees up to approximately 11 years.

Deferred losses or gains on interest rate derivatives represent (i) the effective portions of 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. Such deferred amounts are expected to be amortized to interest expense over the lives of the underlying debt which, with respect to (i), is through 2043, and with respect to (ii), is through 2065.

Other unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represent SCE&G's deferred costs associated with electric demand reduction programs, and such deferred costs are being recovered over approximately five years through an approved rate rider. 

Pipeline integrity management costs represent operating costs expended to comply with federal regulatory requirements related to natural gas pipelines. PSNC Energy is recovering costs totaling $4.1 million annually through 2021. PSNC Energy is continuing to defer pipeline integrity costs, and as of December 31, 2018 costs of $51.3 million have been deferred pending future approval of rate recovery. Effective November 2018, SCE&G began amortizing deferred pipeline integrity costs at an annual rate of $3.2 million. Prior to November 2018, such costs were amortized at an annual rate of $1.9 million annually.

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy. SCE&G's remediation costs are expected to be recovered over periods of up to approximately 16 years, and PSNC Energy's remediation costs of $3.8 million are being recovered over a period that will end in 2021.

Deferred storm damage costs represent storm restoration costs for which SCE&G expects to receive future recovery through customer rates.

Deferred transmission operating costs include deferred depreciation and property taxes associated with certain transmission assets for which SCE&G expects recovery from customers through future rates. See also Note 11.

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

Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement. In accordance with the Merger Approval Order, this balance, net of amounts that may be required to satisfy liens described in Note 11, will be refunded to electric customers over a period ending in 2039.

Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the Tax 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

47

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 approximately 85 years). See also Note 6.

Asset removal costs represent estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.

3.    REVENUE RECOGNITION

Identifying Revenue Streams and Related Performance Obligations

Operating Revenues

Operating revenues arise primarily from the sale and transmission of electricity and the sale and transportation of natural gas. Electric and Gas regulated revenues consist primarily of retail sales to residential, commercial and industrial customers under various tariff rates approved by state regulatory commissions. These tariff rates generally include charges for the energy consumed and a standard basic facilities or demand charge designed to recover certain fixed costs incurred to provide service to the customer. Tariff rates also include commission-approved regulatory mechanisms in the form of adjustments or riders, such as for weather normalization, fuel and environmental cost recovery, energy conservation programs, interruptible service and real time pricing provisions, among others. Electric revenues also include wholesale sales and transmission service, primarily to municipal customers and other service providers, under contracts or tariffs approved by the FERC.

Gas nonregulated revenues arise from natural gas sales at market-based rates. Such sales to residential and certain commercial customers include charges for natural gas delivered, at either variable or fixed prices, together with any applicable customer service charges, charges originating from an interstate pipeline company, and other incidental charges. The Company has determined that its gas marketing subsidiary serves as an agent for distribution services provided by a nonaffiliated company in its retail market. Accordingly, the pass-through charges to customers related to such services are not considered revenues. Sales to other commercial and to industrial customers include commodity and transportation charges for natural gas delivered at contracted rates, together with applicable fees for storage, injection, demand, and charges originating from one or more interstate pipeline companies.

Performance obligations which have not been satisfied by the Company or Consolidated SCE&G 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 the Company and Consolidated SCE&G for these charges is equal to the amount of consideration they have a right to invoice and corresponds directly to the value transferred to the customer. As a result, amounts related to performance obligations that have not been fully satisfied are not disclosed.

Contracts governing the transactions above do not have a significant financing component. Also, due to the nature of the commodities underlying these transactions, no performance obligations arise for returns, refunds or warranties. In addition, taxes billed to customers are excluded from the transaction price. Such amounts are recorded as liabilities until they are remitted to the respective taxing authority and are not included in revenues or expenses in the statements of operations.

Non-Operating Revenues

Non-operating revenues are derived from the sale of appliances and water heaters, as well as from contracts covering the repair of certain appliances, wiring, plumbing and similar systems and fees received for such repairs from customers not under a repair contract. In addition, the portion of fees received under asset management agreements that regulators have recognized to be incentives for the Company and Consolidated SCE&G to engage in such transactions is recorded as non-operating revenues.

Revenues from sales are recorded when the appliance or water heater is delivered to the customer. Repair contract coverage fees are recorded when invoiced, generally on a monthly basis in advance of the period of coverage. Additional charges for service calls and non-covered repairs are billed and collected at the time service is rendered. Revenues from asset management agreements are recorded when the related fixed monthly amounts are due, which corresponds to timing of the value received by the customer.

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The point at which the customer controls the use of a purchased product or has obtained substantially all of the benefits from repair services, corresponds to when revenues are recorded and performance obligations are fulfilled. Contract assets arising from invoicing repair contract fees in advance of the coverage period are not material. Income earned from financing sales of appliances and other products is recorded within interest income. Any performance obligations arising from returns, refunds or warranties are not material.

Non-operating revenues also arise from sources unrelated to contracts with customers, such as carrying costs recorded on certain regulatory assets, gains from property sales and income from rentals and from equity method investments, among others. In 2018, such amounts include gains realized upon the settlement of certain interest rate swaps (see Note 15). Such revenues are outside the scope of revenues from contracts with customers.

Non-operating revenues are further described in Note 15. Such revenues arising from contracts with customers were not material for any period presented, and accordingly, detailed disclosures regarding these revenues are not provided.

Significant Judgments and Estimates

Electricity and natural gas are sold and delivered to the customer for immediate consumption and the customer controls the use of, and obtains substantially all of the benefits from, the energy and related services as they are delivered. As such, the related performance obligations are satisfied over time and revenue is recognized over the same period. The Company and Consolidated SCE&G have determined that their right to consideration from a customer directly corresponds to the value of the performance completed at the date each customer invoice is rendered. As a result, the Company and Consolidated SCE&G recognize revenue in the amounts for which they have a right to invoice. This includes estimated amounts unbilled at a balance sheet date, but which are to be invoiced in the normal cycle.

Regulatory mechanisms exist within electric and gas tariffs or orders from regulators that result in adjustments to customer bills. These regulatory mechanisms are designed:

• To recover costs related to fuel, pension, pipeline integrity and energy conservation, among others;

• To recover carrying costs associated with debt-based financing;

• To replace revenues lost as a result of the utility implementing DER programs and DSM Programs; and

• For gas revenues, to achieve weather normalization or to decouple gas revenues from weather and other factors through the WNA at SCE&G or the CUT at PSNC Energy.

Recovery of deferred costs and carrying costs and the replacement of lost revenues are components of approved tariffs, and therefore, adjustments to customer bills occur as electricity or natural gas is sold and delivered to the customer. As such, the Company and Consolidated SCE&G have concluded that performance obligations related to these adjustments are not capable of being distinct from the underlying tariff based sales. Accordingly, revenues arising from these adjustments are recorded within Operating Revenues - Electric or Gas - regulated on the statements of operations, consistent with revenues from underlying tariff based sales.

Adjustments for SCE&G’s WNA increase gas customer bills when weather is milder than normal and decrease gas customer bills when weather is colder than normal. These adjustments are made during the same period that the underlying natural gas is sold and delivered to the customer, and the performance obligations associated with these adjustments are not capable of being distinct from tariff based sales. Such adjustments are recorded within Operating Revenues - Gas - regulated on the statements of operations. When weather is significantly milder than normal, SCE&G limits such adjustments on a gas customer’s bill to an amount that would be added if weather were 50% milder than normal. Adjustments exceeding this limit, though still recorded as operating revenue, are deferred within regulatory assets until customers are subsequently billed for the excess with the approval of the SCPSC.

PSNC Energy’s CUT is a decoupling mechanism that adjusts bills for residential and commercial customers based on per customer average consumption. When average consumption exceeds actual usage, PSNC Energy records increased revenue associated with this undercollection and defers it within regulatory assets. Likewise, when actual usage exceeds average consumption, a decrement to revenue associated with this overcollection is recorded and deferred within regulatory liabilities. PSNC Energy’s tariff based rates are adjusted semiannually, with the approval of the NCUC, to collect or refund these deferred amounts over the subsequent 12 month period.

Amounts deferred for the WNA and the CUT arise under specific arrangements with regulators rather than customers. As a result, the Company and Consolidated SCE&G have concluded that these arrangements represent alternative revenue programs. Revenue from alternative revenue programs is included within Operating Revenues - Gas - regulated on the statements of operations in the month such adjustments are deferred within regulatory accounts and is shown as Other

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operating revenues when disaggregated in the table below. As permitted, the Company and Consolidated SCE&G have elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues.

Disaggregation of Revenues

The impact of several factors on the amount, timing and uncertainty of operating revenues and cash flows can vary significantly by customer class. For electric revenues and nonregulated gas revenues, which do not have weather normalization mechanisms in place, weather and conservation measures on energy usage typically affect residential and commercial customers to a greater degree than other customer classes. For utilities, revenue requirements result in increases or decreases in tariff rates approved by regulatory bodies and often vary by customer class. Also, certain cost recovery and other mechanisms may have an uneven impact on a particular customer class depending on the underlying tariffs affected. For nonregulated gas, revenues are impacted by competitive market rates tailored to appeal to specific customer classes. The Company and Consolidated SCE&G have disaggregated operating revenues by customer class as follows:

The Company	Consolidated SCE&G				PSNC Energy		Total  Gas-regulated		Gas-nonregulated
Millions of dollars	Electric		Gas-regulated		Gas-regulated
2018
Customer class:
Residential	$	1,054	$	208	$	325	$	533	$	244
Commercial	744		117		125		242		92
Industrial	385		92		15		107		422
Transportation	—		13		32		45		—
Other	132		4		—		4		38
Revenues from contracts with customers	2,315		434		497		931		796
Other operating revenues	12		1		3		4		—
Total Operating Revenues	$	2,327	$	435	$	500	$	935	$	796

Contract Liabilities

Contract liabilities represent the obligation to transfer goods or services to a customer for which consideration has already been received from the customer. At December 31, 2018 and 2017, the Company had contract liability balances of $9.4 million and $8.3 million, respectively, and Consolidated SCE&G had contract liability balances of $3.6 million and $2.9 million, respectively. During the twelve months ended December 31, 2018, the Company and Consolidated SCE&G recognized all amounts from their respective December 31, 2017 contract liability balances as each of them fulfilled their obligations to provide service to their customers. Such obligations at December 31, 2018 are expected to be fulfilled within twelve months. 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, SCE&G provides economic development grants intended to support economic growth within SCE&G’s electric service territory and defers such grants as regulatory assets on the consolidated balance sheet. Whenever these grants are contingent on a customer entering into a long-term electric supply contract with SCE&G, 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:

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The Company and Consolidated SCE&G
Millions of dollars	Regulatory Assets
January 1, 2018	$	16.3
Additional costs	—
Amortization	(1.5		)
Impairment	—
December 31, 2018	$	14.8

4.COMMON EQUITY

Authorized shares of SCANA common stock were 200 million as of December 31, 2018 and 2017. Authorized shares of SCE&G common stock were 50 million as of December 31, 2018 and 2017. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were held by SCANA as of December 31, 2018 and 2017. As disclosed in Note 1, effective January 1, 2019, all common stock of SCANA is held by Dominion Energy.

In 2018, SCANA made equity contributions to GENCO and Fuel Company totaling approximately $23 million and $1 million, respectively.

In February 2019, SCANA received an equity contribution of $675 million from Dominion Energy, and SCANA made an equity contribution to SCE&G of $675 million. SCE&G used the funds from this equity contribution to reduce long-term debt. See Note 5.

SCANA’s articles of incorporation do not limit the dividends that may be paid on its common stock, and the articles of incorporation of each of SCANA's subsidiaries contain no such limitations on their respective common stock.

SCE&G’s bond indenture under which it issues First Mortgage Bonds contains provisions that could limit the payment of cash dividends on its common stock. SCE&G's bond indenture permits the payment of dividends on SCE&G'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 December 31, 2018 and 2017, retained earnings of approximately $115.0 million and $93.9 million, respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

Pursuant to the Merger Approval Order, the amount of any SCE&G dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry. There is no specific restriction on the payment of dividends by SCE&G.

PSNC Energy’s note purchase and debenture purchase agreements contain provisions that could limit the payment of cash distributions, including dividends, on PSNC Energy's common stock. These agreements generally limit the sum of distributions to an amount that does not exceed $30 million plus 85% of Consolidated Net Income (as therein defined) accumulated after December 31, 2008 plus the net proceeds of issuances by PSNC Energy of equity or convertible debt securities (as therein defined). As of December 31, 2018, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million.

The NCUC, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by PSNC Energy to (i) the amount of retained earnings at closing of the SCANA Combination plus (ii) any future earnings recorded by PSNC Energy after such date. In addition, notice to the NCUC is required if payment of dividends causes the equity component of PSNC Energy’s capital structure to fall below 45%.

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5.    LONG-TERM AND SHORT-TERM DEBT

Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows:

The Company
December 31,				2018					2017
Dollars in millions	Maturity			Balance			Rate		Balance			Rate
SCANA Medium Term Notes (unsecured)	2020	-	2022	$	800		5.42	%	$	800		5.42	%
SCANA Senior Notes (unsecured) (a)	2019	-	2034	70			3.44	%	75			2.18	%
SCE&G First Mortgage Bonds (secured)	2021	-	2065	4,990			5.52	%	4,840			5.80	%
GENCO Notes (secured)	2019	-	2024	40			5.49	%	207			5.94	%
Industrial and Pollution Control Bonds (b)	2028	-	2038	122			3.52	%	122			3.52	%
PSNC Energy Senior Debentures and Notes	2020	-	2047	700			5.07	%	600			5.19	%
Other	2019	-	2027	73			3.46	%	28			2.83	%
Total debt				6,795					6,672
Current maturities of long-term debt				(59		)			(727		)
Unamortized discount, net				(2		)			(1		)
Unamortized debt issuance costs				(39		)			(38		)
Total long-term debt, net				$	6,695				$	5,906

Consolidated SCE&G
December 31,				2018					2017
Dollars in millions	Maturity			Balance			Rate		Balance			Rate
First Mortgage Bonds (secured)	2021	-	2065	$	4,990		5.52	%	$	4,840		5.80	%
GENCO Notes (secured)	2019	-	2024	40			5.49	%	207			5.94	%
Industrial and Pollution Control Bonds (b)	2028	-	2038	122			3.52	%	122			3.52	%
Other	2019	-	2027	30			2.97	%	28			2.83	%
Total debt				5,182					5,197
Current maturities of long-term debt				(14		)			(723		)
Unamortized premium (discount), net				(1		)			1
Unamortized debt issuance costs				(35		)			(34		)
Total long-term debt, net				$	5,132				$	4,441

(a)  Variable rate notes hedged by a fixed interest rate swap (fixed rate of 6.17%).

(b) Includes variable rate debt of $67.8 million at December 31, 2018 (rate of 1.72%) and 2017 (rate of 1.85%) which are hedged by fixed swaps.

In September 2018, SCANA borrowed $40 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at December 31, 2018 was 3.87%. This draw was repaid January 10, 2019. Proceeds from the draw had been used to provide contractually required credit support, and this deposit is reflected within other assets on the consolidated balance sheet.

In August 2018, SCE&G issued $300 million of 3.50% first mortgage bonds due August 15, 2021, and $400 million of 4.25% first mortgage bonds due August 15, 2028. Proceeds from these sales were used on September 28, 2018, to repay prior to maturity $250 million of 5.25% first mortgage bonds and $300 million of 6.50% first mortgage bonds, each due November 1, 2018. In addition, proceeds were used for general corporate purposes.

In June 2018, GENCO redeemed at maturity $160 million of 6.06% secured notes. The repayment was funded using a combination of money pool borrowings and an equity contribution from SCANA.

In June 2018, PSNC Energy issued $100 million of 4.33% senior notes due June 15, 2028. In June 2017, PSNC Energy issued $150 million of 4.18% senior notes due June 30, 2047. Proceeds from each of these sales were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.

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In March 2018, SCE&G borrowed $100 million under the five-year credit agreement expiring December 2020. The proceeds of this draw were deposited with a natural gas supplier to provide contractually required credit support. In September 2018, SCE&G obtained a surety bond to replace this credit support and, as a result, the deposit was returned and this draw was repaid in September 2018. Also, SCANA obtained letters of credit in favor of natural gas suppliers to provide contractually required credit support.

As of December 31, 2018, the Company's long-term debt maturities are $59 million in 2019, $368 million in 2020, $797 million in 2021, $266 million in 2022 and $14 million in 2023. These amounts include, for Consolidated SCE&G, $14 million in 2019, $13 million in 2020, $342 million in 2021, $11 million in 2022 and $9 million in 2023.

In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any and all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of approximately $1.0 billion. SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer.

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

SCE&G 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, 2018, the Bond Ratio was 4.01. Adjusted Net Earnings, as therein defined, excludes the impairment loss.

Lines of Credit and Short-Term Borrowings

At December 31, 2018 and 2017, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC-related obligations and commercial paper borrowings:

Millions of dollars	Total		SCANA			SCE&G			PSNC  Energy
December 31, 2018
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	500.0		—			500.0			—
Total committed long-term	1,800.0		400.0			1,200.0			200.0
LOC advances	40.0		40.0			—			—
Weighted average interest rate			3.87		%
Outstanding commercial paper (270 or fewer days)	172.9		2.0			73.2			97.7
Weighted average interest rate			3.65		%	3.82		%	3.49		%
Letters of credit supported by LOC	37.6		37.3			0.3			—
Available	$	1,549.5	$	320.7		$	1,126.5		$	102.3

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December 31, 2017
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0	$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	500.0		—		500.0			—
Three-year, expiring December 2018	200.0		—		200.0			—
Total committed long-term	2,000.0		400.0		1,400.0			200.0
Outstanding commercial paper (270 or fewer days)	350.3		—		251.6			98.7
Weighted average interest rate					1.92		%	1.93		%
Letters of credit supported by LOC	3.3		3.0		0.3			—
Available	$	1,646.4	$	397.0	$	1,148.1		$	101.3

At December 31, 2018, SCANA, SCE&G (including Fuel Company) and PSNC Energy were parties to credit agreements in the amounts and for the terms described above. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N.A. and Morgan Stanley Bank, N.A. each provide 9.5% of the aggregate credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch, UBS Loan Finance LLC, MUFG Union Bank, N.A., and Branch Banking and Trust Company each provide 7.9%, and Royal Bank of Canada and U.S. Bank National Association each provide 5.5%. Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.

In December 2018, SCE&G's three-year credit facility expired and was not replaced. In February 2019, Fuel Company's commercial paper program and its credit facility were terminated. Fuel Company's financing needs in the future are expected to be met using the money pool described below.

SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2019, which reflects a one-year authorization period rather than the two-year period SCE&G and GENCO had requested. In granting the authorization for a shorter period, FERC cited several matters which, at the time, were ongoing, including proceedings involving the ORS and Act 258, as well as the merger between SCANA and Dominion Energy, that could affect SCE&G's and GENCO's circumstances. Were adverse developments to occur with respect to uncertainties highlighted elsewhere, the ability of SCE&G or GENCO to secure renewal of this short-term borrowing authority may be adversely impacted. In January 2019, SCE&G and GENCO applied to FERC for a two-year short-term borrowing authorization, and that application is pending.

Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. The letters of credit expire, subject to renewal, in the fourth quarter of 2019.

Consolidated SCE&G participates in a utility money pool with SCANA and another regulated subsidiary of SCANA. Money pool borrowings and investments bear interest at short-term market rates. For the twelve months ended December 31, 2018, Consolidated SCE&G recorded interest income from money pool transactions of $4.1 million and interest expense from money pool transactions of $4.1 million, respectively. Interest income and interest expense for periods in 2017 were not significant. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $282 million and investments due from an affiliate of $353 million at December 31, 2018. At December 31, 2017 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $37 million and investments due from an affiliate of $28 million. For each period presented, money pool borrowings were made by Fuel Company and GENCO, and money pool investments were made by SCE&G. On its consolidated balance sheet, Consolidated SCE&G includes money pool borrowings within Affiliated payables and money pool investments within Affiliated companies receivables.

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6.INCOME TAXES

Components of income tax expense (benefit) are as follows:

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
Current taxes (benefit):
Federal	$	(8	)	$	(414	)	$	36		$	(16	)	$	(410	)	$	50
State	5			18			13			—			(18		)	13
Total current taxes (benefit)	(3		)	(396		)	49			(16		)	(428		)	63
Deferred tax (benefit) expense, net:
Federal	(352		)	323			203			(346		)	261			167
State	(55		)	(37		)	21			(52		)	(2		)	20
Total deferred taxes (benefit)	(407		)	286			224			(398		)	259			187
Investment tax credits:
Amortization of amounts deferred-federal	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Total income tax expense (benefit)	$	(412	)	$	(112	)	$	271		$	(416	)	$	(171	)	$	248

In December 2017, the Tax Act was enacted, resulting in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory tax rate. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in excess deferred income tax balances within regulatory liabilities (see Note 2).

Included in the Company’s 2018 federal deferred income tax expense was $53 million for the utilization of operating loss carryforwards. Included in Consolidated SCE&G’s 2018 federal deferred income tax expense was $46 million for the utilization of operating loss carryforwards.

The difference between actual income tax expense and the amount calculated from the application of the statutory federal income tax rate to pre-tax income is reconciled as follows:

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
U.S. statutory rate	21		%	35		%	35		%	21		%	35		%	35		%
Net income (loss)	$	(528	)	$	(119	)	$	595		$	(614	)	$	(185	)	$	513
Income tax expense (benefit)	(412		)	(112		)	271			(416		)	(171		)	248
Noncontrolling interest	—			—			—			25			13			13
Total pre-tax income (loss)	$	(940	)	$	(231	)	$	866		$	(1,005	)	$	(343	)	$	774
Income taxes (benefit) on above at statutory federal income tax rate	$	(197	)	$	(81	)	$	303		$	(211	)	$	(120	)	$	271
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)	(37		)	(7		)	27			(38		)	(8		)	26
State investment tax credits (less federal income tax effect)	(3		)	(5		)	(5		)	(3		)	(5		)	(5		)
Allowance for equity funds used during construction	(4		)	(8		)	(10		)	(2		)	(5		)	(9		)
Deductible dividends—401(k) Retirement Savings Plan	(2		)	(9		)	(10		)	—			—			—
Amortization of federal investment tax credits	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Section 45 tax credits	(9		)	(8		)	(8		)	(9		)	(8		)	(8		)
Domestic production activities deduction	—			(18		)	(23		)	—			(18		)	(23		)
Remeasurement of deferred taxes in connection with enactment of Tax Act	(188		)	30			—			(176		)	(1		)	—
Nuclear Project impairment	23			—			—			23			—			—
Nondeductible merger-related costs	5			—			—			—			—			—
Other differences, net	2			(4		)	(1		)	2			(4		)	(2		)
Total income tax expense (benefit)	$	(412	)	$	(112	)	$	271		$	(416	)	$	(171	)	$	248

The Company and Consolidated SCE&G have completed their accounting for the effects of the Tax Act. In connection with the remeasurement of federal deferred income tax assets and liabilities, the Company recorded additional deferred income

55

tax expense of approximately $30 million, and Consolidated SCE&G recorded a deferred income tax benefit of approximately $1 million in their respective statements of operations for the year ended December 31, 2017. As a result of the eventual filing of the Company's 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 $188 million at the Company and approximately $176 million at Consolidated SCE&G were recorded. Also in connection with the additional impairment charges, the Company and Consolidated SCE&G recorded additional adjustments to deferred income taxes in the aggregate amount of approximately $23 million. Additional changes could occur as further Tax Act guidance is issued and finalized. In addition, certain states in which the Company and Consolidated SCE&G operate may or may not conform to some or all of the provisions of the Tax 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.

The State of North Carolina lowered its corporate income tax rate to 4.0% in 2016, 3.0% in 2017 and 2.5% effective January 1, 2019. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

The tax effects of significant temporary differences comprising net deferred tax liabilities are as follows:

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Deferred tax assets:
Net operating loss and tax credit carryforward	$	539	$	600	$	493	$	541
Toshiba settlement	274		273		274		273
Nondeductible accruals	84		88		40		42
Asset retirement obligation, including nuclear decommissioning	143		141		135		132
Regulatory liability, non-property accumulated deferred income tax	—		54		—		54
Financial instruments	10		15		—		—
Unamortized investment tax credits	7		8		7		8
Other	4		6		5		5
Total deferred tax assets	1,061		1,185		954		1,055
Deferred tax liabilities:
Property, plant and equipment	1,227		1,220		1,033		1,035
Regulatory asset, unrecovered nuclear plant costs	668		962		668		962
Deferred employee benefit plan costs	60		60		53		53
Regulatory asset, asset retirement obligation	94		91		88		85
Regulatory asset, other unrecovered plant	24		27		24		27
Demand side management costs	16		16		16		16
Prepayments	21		21		20		19
Other	63		49		41		31
Total deferred tax liabilities	2,173		2,446		1,943		2,228
Net deferred tax liabilities	$	1,112	$	1,261	$	989	$	1,173

The federal and state tax credits and NOL carryforwards are presented below:

	December 31, 2018
Millions of dollars	The Company		Consolidated SCE&G		Expiration Year
Federal NOL Carryforwards	$	1,807	$	1,642	2037
Federal Tax Credits	83		83		2035	-	2038
State NOL Carryforwards	2,447		2,198		2037
State Tax Credits	30		30		2026	-	2033
Total Tax Credits and NOL Carryforwards	$	4,367	$	3,953

A valuation allowance is needed when it is more likely than not that all or a portion of a deferred tax asset will not be realized. In determining whether a valuation allowance is required, the Company and Consolidated SCE&G consider such factors as prior earnings history, expected future earnings, carryback and carryforward periods, and tax strategies that could

56

potentially enhance the likelihood of the realization of a deferred tax asset. Based on this evaluation, management has concluded that a valuation allowance is not needed.    

The Company files consolidated federal income tax returns and certain state returns, including the return for South Carolina, which returns include Consolidated SCE&G. The Company and its subsidiaries file various other applicable state and local income tax returns. Consolidated SCE&G's NOL shown above represents their portion on a stand-alone company basis. There is no material amount due to or from the Company.

The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2009 are closed for additional assessment. The IRS is currently examining the Company's open federal returns through 2017 as a result of claims discussed below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010.

Changes in Unrecognized Tax Benefits

	The Company							Consolidated SCE&G
Millions of dollars	2018		2017			2016		2018		2017			2016
Unrecognized tax benefits, January 1	$	98	$	350		$	49	$	98	$	350		$	49
Gross increases—uncertain tax positions in prior period	8		—			94		8		—			94
Gross decreases—uncertain tax positions in prior period	—		(273		)	—		—		(273		)	—
Gross increases—current period uncertain tax positions	—		21			207		—		21			207
Unrecognized tax benefits, December 31	$	106	$	98		$	350	$	106	$	98		$	350

During 2013 and 2014, the Company amended certain of its income tax returns to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). The Company also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016 and 2017, the Company claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the Nuclear Project, in its 2015 and 2016 income tax returns. The Company claimed similar deductions and credits in its 2017 tax return when it was filed in 2018. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models.

The IRS examined the claims in the amended returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2017 income tax returns.

These IRC Section 174 income tax deductions and IRC Section 41 credits were considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities were recorded as unrecognized tax benefits in the financial statements. Following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G claimed an abandonment loss deduction under IRC Section 165 on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, are instead expected to be deductible in 2017 under IRC Section 165. The Company received a favorable PLR from the IRS stating the Company has a valid tax deduction for abandonment under IRC Section 165. Although the IRS does not verify the amount of the deduction, there is no reserve against these costs. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, Section 41 credits, and certain unrecognized state tax benefits.

As of December 31, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $106 million ($38 million net of the impact of state deductions on federal returns, net of NOL and credit carryforwards, and net of receivables related to the uncertain tax positions). If recognized, $106 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. Due to the merger with Dominion Energy, it is reasonably possible that these unrecognized tax benefits could increase within the next 12 months, although such increase cannot be reasonably estimated. It is reasonably possible that these unrecognized tax benefits may decrease by $11 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through December 31, 2018.

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The Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses. Amounts recorded for such interest income, interest expense or tax penalties have not been material for any period presented.

7.DERIVATIVE FINANCIAL INSTRUMENTS

Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

Policies and procedures, and in some cases risk limits, are established to control the level of market, credit, liquidity and operational and administrative risks.  Historically, SCANA’s Board of Directors delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries.  The Risk Management Committee, which was comprised of certain officers, apprised the Board of Directors with regard to the management of risk and brought to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the consolidated statements of cash flows.

PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options.  PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging.  PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes.

Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit.

As an accommodation to certain customers, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives.  These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  In cases in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

Forward starting swap agreements designated as cash flow hedges have been used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and its nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

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Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G 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 expense or have been applied as otherwise directed by the SCPSC. See Note 2 and Note 15 regarding the settlement gains realized in the first quarter of 2018.

Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.

Quantitative Disclosures Related to Derivatives

The Company was party to natural gas derivative contracts outstanding in the following quantities:

	Commodity and Energy Management Contracts (in bcf)
Hedge designation	Gas Distribution	Gas Marketing	Total
As of December 31, 2018
Commodity	6.4	12.9	19.3
Energy Management (a)	—	46.8	46.8
Total (a)	6.4	59.7	66.1
As of December 31, 2017
Commodity	6.4	13.4	19.8
Energy Management (a)	—	41.9	41.9
Total (a)	6.4	55.3	61.7

(a) Includes amounts related to basis swap contracts totaling 5.1 bcf in 2018 and 2.6 bcf in 2017.

The aggregate notional amounts of the interest rate swaps were as follows:

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	December 31, 2018		December 31, 2017		December 31, 2018		December 31, 2017
Designated as hedging instruments	$	106.8	$	111.2	$	36.4	$	36.4
Not designated as hedging instruments	35.0		735.0		35.0		735.0

The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown.

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Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of December 31, 2018
Designated as hedging instruments
Interest rate contracts
	Other current liabilities	—		$	2	—		$	1
	Other deferred credits and other liabilities	—		19		—		7
Commodity contracts
	Prepayments	—		1		—		—
Total		—		$	22	—		$	8
Not designated as hedging instruments
Interest rate contracts
	Other deferred credits and other liabilities	—		$	3	—		$	3
Commodity contracts
	Prepayments	$	1	—		—		—
Energy management contracts
	Prepayments	11		12		—		—
	Other current assets	1		—		—		—
	Other current liabilities	—		1		—		—
	Other deferred debits and other assets	1		—		—		—
Total		$	14	$	16	—		$	3
As of December 31, 2017
Designated as hedging instruments
Interest rate contracts
	Other current liabilities	—		$	3	—		$	1
	Other deferred credits and other liabilities	—		24		—		9
Commodity contracts
	Prepayments	—		2		—		—
	Other current liabilities	—		1		—		—
Total		—		$	30	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets and current liabilities	$	54	$	1	$	54	$	1
	Other deferred credits and other liabilities	—		4		—		4
Commodity contracts
	Other current assets	1		—		—		—
Energy management contracts
	Prepayments	—		1		—		—
	Other current assets	3		—		—		—
	Other deferred debits and other assets	1		—		—		—
	Other current liabilities	—		2		—		—
Total		$	59	$	8	$	54	$	5

Derivatives Designated as Fair Value Hedges

The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented.

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Derivatives in Cash Flow Hedging Relationships

The effect of derivative instruments on the consolidated statements of operations is as follows: 

The Company and Consolidated SCE&G:	Gain (Loss) Deferred in Regulatory Accounts			Loss Reclassified from Deferred Accounts into Income (Effective Portion)
Millions of dollars	(Effective Portion)			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	1		Interest expense	$	(1	)
Year Ended December 31, 2017
Interest rate contracts	$	(2	)	Interest expense	$	(2	)
Year Ended December 31, 2016
Interest rate contracts	—			Interest expense	$	(2	)

The Company:	Gain (Loss) Recognized in OCI, net of tax			Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion)
Millions of dollars	(Effective Portion)			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	1		Interest expense	$	(9	)
Commodity contracts	(3		)	Gas purchased for resale	(7		)
Total	$	(2	)		$	(16	)
Year Ended December 31, 2017
Interest rate contracts	—			Interest expense	$	(7	)
Commodity contracts	$	(7	)	Gas purchased for resale	1
Total	$	(7	)		$	(6	)
Year Ended December 31, 2016
Interest rate contracts	$	(1	)	Interest expense	$	(7	)
Commodity contracts	5			Gas purchased for resale	(6		)
Total	$	4			$	(13	)

As of December 31, 2018, the Company expects that during the next 12 months reclassifications from AOCI (loss) to earnings arising from cash flow hedges will include approximately $0.6 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $8.7 million as an increase to interest expense. Reclassifications related to commodity and energy management contracts are not expected to be significant. All of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2021.

As of December 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $0.9 million as an increase as an increase to interest expense.

Hedge Ineffectiveness

For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant for all periods presented.

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Derivatives Not Designated as Hedging Instruments

The Company and Consolidated SCE&G:	Gain (Loss) Deferred in			Gain (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	Regulatory Accounts			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	64		Interest Expense	$	(2	)
Interest rate contracts				Other Income	115
Year Ended December 31, 2017
Interest rate contracts	$	(32	)	Interest Expense	$	(3	)
Interest rate contracts				Impairment Loss	(173		)
Year Ended December 31, 2016
Interest rate contracts	$	(34	)	Other income	$	(2	)

Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. Loss reclassified to impairment loss is included in the 2017 impairment described in Note 11.

As of December 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $2.8 million as an increase to interest expense.

Credit Risk Considerations

Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral.

Derivative Contracts with Credit Contingent Features

	The Company				Consolidated SCE&G
Millions of dollars	December 31, 2018		December 31, 2017		December 31, 2018		December 31, 2017
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	24.8	$	33.7	$	11.2	$	14.7
Fair value of collateral already posted	24.3		28.9		11.0		10.1
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	0.5	$	4.8	$	0.2	$	4.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position	—		$	53.5	—		$	53.5
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	—		$	53.5	—		$	53.5

In addition, at December 31, 2018, the Company could not call on any letters of credit related to the $1.7 million in commodity derivatives that are in a net asset position. At December 31, 2017, the Company could have called on letters of credit in the amount of $1.2 million related to derivatives of $4.0 million if all the contingent features underlying these instruments had been fully triggered.

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Information related to the offsetting derivative assets follows:

Derivative Assets	The Company										Consolidated SCE&G
Millions of dollars	Interest Rate Contracts		Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2018
Gross Amounts of Recognized Assets	—		$	1	$	13		$	14		—
Gross Amounts Offset in Statement of Financial Position	—		—		(11		)	(11		)	—
Net Amounts Presented in Statement of Financial Position	—		1		2			3			—
Gross Amounts Not Offset - Financial Instruments	—		—		—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—			—			—
Net Amount	—		$	1	$	2		$	3		—
Balance sheet location
Prepayments								$	12		—
Other current assets								1			—
Other deferred debits and other assets								1			—
Total								$	14		—
As of December 31, 2017
Gross Amounts of Recognized Assets	$	54	$	1	$	4		$	59		$	54
Gross Amounts Offset in Statement of Financial Position	—		—		—			—			—
Net Amounts Presented in Statement of Financial Position	54		1		4			59			54
Gross Amounts Not Offset - Financial Instruments	—		—		—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—			—			—
Net Amount	$	54	$	1	$	4		$	59		$	54
Balance sheet location
Other current assets								$	58		$	54
Other deferred debits and other assets								1			—
Total								$	59		$	54

Information related to the offsetting of derivative liabilities follows:

Derivative Liabilities	The Company											Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2018
Gross Amounts of Recognized Liabilities	$	24		$	1	$	13		$	38		$	11
Gross Amounts Offset in Statement of Financial Position	—			—		(11		)	(11		)	—
Net Amounts Presented in Statement of Financial Position	24			1		2			27			11
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(24		)	—		—			(24		)	(11		)
Net Amount	—			$	1	$	2		$	3		—
Balance sheet location
Prepayments									$	13		—
Other current liabilities									3			$	1
Other deferred credits and other liabilities									22			10
Total									$	38		$	11

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Derivative Liabilities	The Company											Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2017
Gross Amounts of Recognized Liabilities	$	32		$	3	$	3		$	38		$	15
Gross Amounts Offset in Statement of Financial Position	—			—		(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	32			3		2			37			15
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(28		)	—		(1		)	(29		)	—
Net Amount	$	4		3		$	1		$	8		$	15
Balance sheet location
Other current assets									$	2		—
Other current liabilities									7			$	2
Other deferred credits and other liabilities									28			13
Total									$	37		$	15

8.             FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

The Company and Consolidated SCE&G value available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, on which the securities are actively traded or are open-ended mutual funds registered with the SEC and maintain a stable NAV and are invested in government money market agreements or fully collateralized repurchase agreements. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

	As of December 31, 2018							As of December 31, 2017
	The Company				Consolidated SCE&G			The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 1	Level 2		Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	—		—		—	—		$	119	—		$	100	—
Held to maturity securities	—		$	6	—	—		—		$	6	—		—
Interest rate contracts	—		—		—	—		—		54		—		$	54
Commodity contracts	$	1	—		—	—		1		—		—		—
Energy management contracts	11		2		—	—		—		4		—		—
Liabilities:
Interest rate contracts	—		24		—	$	11	—		32		—		15
Commodity contracts	1		—		—	—		2		1		—		—
Energy management contracts	12		3		—	—		1		4		—		—

The Company and Consolidated SCE&G had no Level 3 fair value measurements during either period presented.

Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2018 and December 31, 2017 were as follows:

	As of December 31, 2018				As of December 31, 2017
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,753.9	$	7,180.8	$	6,632.9	$	7,399.7
Consolidated SCE&G	5,145.6		5,469.7		5,163.3		5,790.3

 Fair values of long-term debt instruments are 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

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rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent.

Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.

In connection with the impairment loss described in Note 11, the Company and Consolidated SCE&G determined that the fair value of certain of their nuclear fuel was lower than its carrying amount. At December 31, 2018, this nuclear fuel had an estimated fair value of $40.2 million. This estimate is based on quoted prices received from vendors of nuclear fuel, which are considered to be Level 3 fair value measurements. The Company and Consolidated SCE&G assess the fair value of nuclear fuel in connection with the analysis of impairment described in Note 11 on a quarterly basis.

9.             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. SCE&G 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. SCE&G 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.

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.

	The Company												Consolidated SCE&G
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017			2018			2017			2018			2017
Benefit obligation, January 1	$	933.2		$	904.3		$	289.2		$	274.7		$	793.0		$	768.4		$	216.6		$	207.2
Service cost	21.0			21.7			4.6			4.5			17.1			18.1			3.6			3.7
Interest cost	34.1			37.4			10.1			11.5			29.0			31.9			8.0			9.5
Plan participants’ contributions	—			—			1.4			1.3			—			—			1.1			1.1
Actuarial (gain) loss	(53.1		)	42.2			(38.4		)	9.7			(45.5		)	36.6			(30.7		)	6.8
Benefits paid	(71.7		)	(72.4		)	(13.2		)	(12.5		)	(61.3		)	(62.0		)	(10.4		)	(10.3		)
Amounts funded to parent	n/a			n/a			n/a			n/a			—			—			(0.8		)	(1.4		)
Benefit obligation, December 31	$	863.5		$	933.2		$	253.7		$	289.2		$	732.3		$	793.0		$	187.4		$	216.6

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The accumulated benefit obligation for pension benefits for the Company was $842.4 million at the end of 2018 and $905.8 million at the end of 2017. The accumulated benefit obligation for pension benefits for Consolidated SCE&G was $714.3 million at the end of 2018 and $769.7 million at the end of 2017. 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
	2018		2017		2018		2017
Annual discount rate used to determine benefit obligation	4.35	%	3.71	%	4.38	%	3.74	%
Assumed annual rate of future salary increases for projected benefit obligation	3.00	%	3.00	%	3.00	%	3.00	%

A 6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018. 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 the Company would increase the postretirement benefit obligation by $0.7 million at December 31, 2018 and by $1.6 million at December 31, 2017. A one percent decrease in the assumed health care cost trend rate for the Company would decrease the postretirement benefit obligation by $0.6 million at December 31, 2018 and by $1.4 million at December 31, 2017. A one percent increase in the assumed health care cost trend rate for Consolidated SCE&G would increase the postretirement benefit obligation by $0.6 million at December 31, 2018 and by $1.3 million at December 31, 2017. A one percent decrease in the assumed health care cost trend rate for Consolidated SCE&G would decrease the postretirement benefit obligation by $0.5 million at December 31, 2018 and by $1.1 million at December 31, 2017.

Funded Status

	The Company												Consolidated SCE&G
Millions of Dollars	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
December 31,	2018			2017			2018			2017			2018			2017			2018			2017
Fair value of plan assets	$	727.3		$	849.6		—			—			$	676.7		$	781.3		—			—
Benefit obligation	863.5			933.2			$	253.7		$	289.2		732.3			793.0			$	187.4		$	216.6
Funded status	$	(136.2	)	$	(83.6	)	$	(253.7	)	$	(289.2	)	$	(55.6	)	$	(11.7	)	$	(187.4	)	$	(216.6	)

Amounts recognized on the consolidated balance sheets were as follows:

	The Company												Consolidated SCE&G
Millions of Dollars	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
December 31,	2018			2017			2018			2017			2018			2017			2018			2017
Current liability	—			—			$	(13.3	)	$	(13.5	)	—			—			$	(10.5	)	$	(10.8	)
Noncurrent liability	$	(136.2	)	$	(83.6	)	(240.4		)	(275.7		)	$	(55.6	)	$	(11.7	)	(176.9		)	(205.8		)

Amounts recognized in accumulated other comprehensive loss were as follows:

	The Company								Consolidated SCE&G
Millions of Dollars	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
December 31,	2018		2017		2018		2017		2018		2017		2018		2017
Net actuarial loss	$	12.8	$	8.8	$	1.1	$	3.5	$	3.4	$	2.1	$	0.5	$	1.5
Prior service cost	0.1		0.1		—		—		—		—		—		—
Total	$	12.9	$	8.9	$	1.1	$	3.5	$	3.4	$	2.1	$	0.5	$	1.5

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Amounts recognized in regulatory assets were as follows:

	The Company								Consolidated SCE&G
Millions of Dollars	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
December 31,	2018		2017		2018		2017		2018		2017		2018		2017
Net actuarial loss	$	230.4	$	194.8	$	10.9	$	43.3	$	202.4	$	171.4	$	9.0	$	35.9
Prior service cost	0.7		1.2		—		—		0.6		1.0		—		—
Total	$	231.1	$	196.0	$	10.9	$	43.3	$	203.0	$	172.4	$	9.0	$	35.9

In connection with the joint ownership of Summer Station, costs related to the pension benefit obligation attributable to Santee Cooper as of December 31, 2018 and 2017 totaled $24.9 million and $21.4 million, respectively, and were recorded within deferred debits. The unfunded postretirement benefit obligation attributable to Santee Cooper as of December 31, 2018 and 2017 totaled $12.4 million and $14.7 million, respectively, and was recorded within deferred debits.

Changes in Fair Value of Plan Assets

Pension Benefits	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Fair value of plan assets, January 1	$	849.6		$	793.6		$	781.3		$	732.9
Actual return (loss) on plan assets	(50.6		)	128.4			(43.3		)	110.4
Benefits paid	(71.7		)	(72.4		)	(61.3		)	(62.0		)
Fair value of plan assets, December 31	$	727.3		$	849.6		$	676.7		$	781.3

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. SCANA 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, 2018 and 2017 and the target allocation for 2019 are as follows: 

	Percentage of Plan Assets
	Target Allocation		December 31,
Asset Category	2019		2018		2017
Equity Securities	58	%	55	%	58	%
Fixed Income	33	%	34	%	31	%
Hedge Funds	9	%	11	%	11	%

For 2019, 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.

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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, 2018 and 2017, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Investments with fair value measure at Level 2:
Mutual funds	$	107	$	120	$	99	$	110
Short-term investment vehicles	20		17		19		16
US Treasury securities	7		15		7		14
Corporate debt instruments	92		91		86		84
Government and other debt instruments	18		17		16		15
Total assets in the fair value hierarchy	244		260		227		239
Investments at net asset value:
Common collective trust	400		498		373		458
Joint venture interests	83		92		77		84
Total investments at fair value	$	727	$	850	$	677	$	781

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 2018 or 2017.

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:

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Expected Benefit Payments

	The Company				Consolidated SCE&G
Millions of dollars	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
2019	$	71.5	$	13.6	$	71.5	$	10.8
2020	62.4		14.3		62.4		11.4
2021	65.6		14.9		65.6		11.8
2022	69.6		15.4		69.6		12.2
2023	66.6		15.8		66.6		12.6
2024-2028	284.9		82.3		284.9		65.4

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

The Company	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018		2017		2016
Service cost	$	21.0		$	21.7		$	20.7		$	4.6	$	4.5	$	4.4
Interest cost	34.1			37.4			39.4			10.1		11.5		12.1
Expected return on assets	(56.7		)	(54.7		)	(55.9		)	n/a		n/a		n/a
Prior service cost amortization	0.5			1.6			3.9			—		—		0.3
Amortization of actuarial losses	12.8			16.3			14.8			0.7		1.0		0.5
Net periodic benefit cost	$	11.7		$	22.3		$	22.9		$	15.4	$	17.0	$	17.3

Consolidated SCE&G	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018		2017		2016
Service cost	$	17.1		$	18.1		$	16.9		$	3.6	$	3.7	$	3.6
Interest cost	29.0			31.9			33.4			8.0		9.5		9.9
Expected return on assets	(48.1		)	(46.7		)	(47.4		)	n/a		n/a		n/a
Prior service cost amortization	0.4			1.4			3.4			—		—		0.3
Amortization of actuarial losses	10.9			13.9			12.5			0.6		0.8		0.4
Net periodic benefit cost	$	9.3		$	18.6		$	18.8		$	12.2	$	14.0	$	14.2

In connection with regulatory orders, SCE&G 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. PSNC Energy recovers pension costs through cost of service rates. 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, SCE&G amortizes certain previously deferred pension costs. See Note 2.

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

The Company	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017			2016
Current year actuarial (gain) loss	$	4.5		$	(1.0	)	$	0.6		$	(2.4	)	$	1.1		$	0.8
Amortization of actuarial losses	(0.5		)	(0.6		)	(0.6		)	—			(0.1		)	—
Amortization of prior service cost	—			—			(0.1		)	—			—			—
Total recognized in OCI	$	4.0		$	(1.6	)	$	(0.1	)	$	(2.4	)	$	1.0		$	0.8

Consolidated SCE&G	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017		2016
Current year actuarial loss	$	1.4		$	0.3		—			$	(1.0	)	$	0.5	$	0.3
Amortization of actuarial losses	(0.1		)	(0.1		)	$	(0.1	)	—			—		—
Total recognized in OCI	$	1.3		$	0.2		$	(0.1	)	$	(1.0	)	$	0.5	$	0.3

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

The Company	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017			2016
Current year actuarial (gain) loss	$	46.7		$	(27.1	)	$	29.4		$	(31.8	)	$	9.4		$	11.1
Amortization of actuarial losses	(11.1		)	(14.1		)	(12.7		)	(0.6		)	(0.8		)	(0.4		)
Amortization of prior service cost	(0.5		)	(1.4		)	(3.4		)	—			—			(0.3		)
Total recognized in regulatory assets	$	35.1		$	(42.6	)	$	13.3		$	(32.4	)	$	8.6		$	10.4

Consolidated SCE&G	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017			2016
Current year actuarial (gain) loss	$	40.7		$	(24.8	)	$	26.3		$	(26.4	)	$	7.3		$	9.2
Amortization of actuarial losses	(9.7		)	(12.5		)	(11.2		)	(0.5		)	(0.7		)	(0.3		)
Amortization of prior service cost	(0.4		)	(1.3		)	(3.0		)	—			—			(0.2		)
Total recognized in regulatory assets	$	30.6		$	(38.6	)	$	12.1		$	(26.9	)	$	6.6		$	8.7

Significant Assumptions Used in Determining Net Periodic Benefit Cost

	Pension Benefits						Other Postretirement Benefits
	2018		2017		2016		2018		2017		2016
Discount rate	3.71	%	4.22	%	4.68	%	3.74	%	4.30	%	4.78	%
Expected return on plan assets	7.00	%	7.25	%	7.50	%	n/a		n/a		n/a
Rate of compensation increase	3.00	%	3.00	%	3.00	%	3.00	%	3.00	%	3.00	%
Health care cost trend rate	n/a		n/a		n/a		7.00	%	6.60	%	7.00	%
Ultimate health care cost trend rate	n/a		n/a		n/a		5.00	%	5.00	%	5.00	%
Year achieved	n/a		n/a		n/a		2023		2021		2021

The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2019 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant:

Millions of Dollars	Pension Benefits		Other Postretirement Benefits
Actuarial loss	$	0.8	—

The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2019 are as follows:

	The Company			Consolidated SCE&G
Millions of Dollars	Pension Benefits		Other Postretirement Benefits	Pension Benefits		Other Postretirement Benefits
Actuarial loss	$	14.7	—	$	12.9	—
Prior service cost	0.3		—	0.3		—
Total	$	15.0	—	$	13.2	—

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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. SCE&G participates in this plan. Contributions are matched 100% up to 6% of an employee’s eligible earnings. Such matching contributions made by the Company totaled $24.1 million in 2018, $27.9 million in 2017 and $27.5 million in 2016. These matching contributions included those made by Consolidated SCE&G, which totaled $19.6 million in 2018, $23.4 million in 2017 and $22.9 million in 2016. Employee deferrals, matching contributions, and earnings on all contributions are fully vested and non-forfeitable at all times.

10.             SHARE-BASED COMPENSATION

The LTECP provided for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The LTECP authorized the issuance of up to five million shares of SCANA’s common stock, no more than one million of which could be granted in the form of restricted stock.

Compensation cost was measured based on the grant-date fair value of the instruments issued and was recognized over the period that an employee provided service in exchange for the award. Share-based payment awards did not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves did not vest, dividends or dividend equivalents which would have been paid on those awards did not vest.

For all periods presented, performance cycles provided for performance measurement and award determination based on performance over a single three-year cycle, with payment of awards being deferred until after the end of the three-year performance cycle. In each of these performance cycles, 30% of the performance awards were granted in the form of restricted share units, which were liability awards payable in cash, and 70% of the awards were granted in performance shares, each of which had a value equal to, and changed with, the value of a share of SCANA common stock. Dividend equivalents were accrued on the performance shares and the restricted share units. Performance awards and related dividend equivalents were subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to certain exceptions. Payouts of performance share awards were determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50%) and growth in GAAP-adjusted net earnings per share (weighted 50%). 

Compensation cost of liability awards was recognized over their respective three-year performance periods based on the estimated fair value of the award, which was periodically updated based on expected ultimate cash payout, and was reduced by estimated forfeitures. Cash-settled liabilities related to performance cycles totaled approximately $5.5 million in 2018, $28.0 million in 2017 and $18.4 million in 2016 for the Company and approximately $3.5 million in 2018, $20.2 million in 2017 and $13.2 million in 2016 for Consolidated SCE&G.

Fair value adjustments for all performance cycles resulted in compensation expense (benefit) recognized in the statements of operations totaling approximately $(1.7) million in 2018, $(9.0) million in 2017 and $25.6 million in 2016 for the Company and approximately $(0.9) million in 2018, $(6.3) million in 2017 and $17.3 million in 2016 for Consolidated SCE&G (including amounts allocated from SCANA Services). Such fair value adjustments also resulted in no capitalized compensation costs in 2018, $(1.3) million in 2017 and $3.3 million in 2016 for the Company and no capitalized compensation costs in 2018, $(0.9) million in 2017 and $3.1 million in 2016 for Consolidated SCE&G.

In connection with the SCANA Combination, effective January 1, 2019, all grants discussed above were deemed to be vested at their target levels and were converted into the right to receive lump sum amounts based on the value of Dominion Energy stock at that time. As such, additional compensation cost of $28.6 million will be recorded in the first quarter of 2019 as a result of the merger. Related cash-settlement payments totaling $19.6 million were made in January 2019, and further lump sum amounts of $6.7 million and $9.1 million are expected to be paid in 2020 and 2021, respectively, to the extent that those later payments are not accelerated in connection with employee retirements or other separations prior to those dates.

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11.          COMMITMENTS AND CONTINGENCIES

Abandoned Nuclear Project

SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. SCE&G's ownership share in these units 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 and Related Uncertainties below), and were the subject of comprehensive analyses performed by the Company and Santee Cooper.

Based on the results of the Company's analysis, and in light of Santee Cooper's decision to suspend construction on Unit 2 and Unit 3, on July 31, 2017, the Company 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 the Company became the focus of numerous legislative, regulatory and legal proceedings, and led to SCE&G recording pre-tax impairment charges in 2017 totaling approximately $1.118 billion (approximately $690 million net of tax). An additional pre-tax impairment loss was recorded in the first quarter of 2018 of approximately $3.6 million (approximately $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. See further discussion below under Impairment Considerations. These proceedings continued in 2018, and some of them remain unresolved and are described below and/or in Claims and Litigation.

On January 2, 2018, SCANA and Dominion Energy entered into the 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.

Merger Approval Order

On December 21, 2018, the SCPSC issued the Merger Approval Order. The order adopted Dominion Energy's Plan-B Levelized Customer Benefits Plan whereby the average bill for an SCE&G residential electric customer would approximate that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the SCPSC in August 2018. Among other things, the order also sets forth the following findings and merger conditions:

• No capital costs related to the Nuclear Project incurred after March 12, 2015 will be recoverable by SCE&G, which results in rate base associated with the Nuclear Project of $2.768 billion after recording an impairment charge of $1.372 billion (pre-tax, and incremental to impairment losses recorded in 2017).

• SCE&G will provide refunds and restitution to customers from prior years' revenues totaling an aggregate $2.039 billion, comprised of $1.032 billion to be credited to customers over 20 years and $1.007 billion credited to customers over approximately 11 years. These refunds include amounts to be refunded to customers related to the monetization of guaranty settlement described in Note 2.

• Except for rate adjustments for fuel and environmental costs, demand side management costs, and other rates routinely adjusted on an annual or biannual basis, SCE&G will freeze retail electric base rates at current levels until January 1, 2021.

• SCE&G's natural gas customers will receive refunds totaling $2.45 million in 2019, 2020 and 2021 combined.

• Corporate giving will increase by $1 million per year for at least five years above historical levels.

• SCE&G will not seek to pass on to ratepayers its initial capital investment in CEC, a 540-MW combined-cycle natural gas-fired generating facility, and will not seek to pass on to ratepayers any acquisition premium costs, transition costs, or transaction cost associated with the merger. SCE&G's decision to not seek recovery of the initial capital investment in CEC was included in the determination of impairment charges recorded in 2017.

In addition, the SCPSC order approved the removal of SCE&G's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of December 31, 2018, such investment in these assets included approximately $367 million within utility plant, net and approximately $15 million within regulatory assets, which amount represents certain deferred operating costs. The SCPSC also approved deferral of certain operating costs related to the

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investment. Recovery of the transmission capital costs and associated deferred operating costs will be addressed in a future rate proceeding.

Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. On February 12, 2019, the SCPSC issued a ruling (1) finding that SCE&G was imprudent in its actions by not disclosing material information to the ORS and the SCPSC, and (2) denying the petitions for rehearing or reconsideration as to other issues raised in the various petitions. The Merger Approval Order and the ruling are subject to appeal by various parties. The Company and Consolidated SCE&G cannot predict the outcome of these matters.

Contractor Bankruptcy Proceedings and Related Uncertainties

On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the Nuclear Project and similar units being built for an unaffiliated company as a material factor that caused WEC and WECTEC to seek protection under the bankruptcy laws. As part of such filing, WEC and WECTEC publicly announced their inability to complete Unit 2 and Unit 3 under the terms of the EPC Contract.

On September 1, 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of WEC and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by the Consortium of the EPC Contract, and asserted against WEC and WECTEC any and all claims that were based thereon or that may have been related thereto. These claims were sold to Citibank on September 27, 2017 as part of a monetization transaction discussed below. Notwithstanding the sale of the claims, SCE&G and Santee Cooper remain responsible for any claims that may be made by WEC and WECTEC against them relating to the EPC Contract.

WEC’s Reorganization Plan was confirmed by the Bankruptcy Court on March 28, 2018, and became effective August 1, 2018. In connection with the effectiveness of the Reorganization Plan, the EPC Contract was deemed rejected. Initially, WEC had projected that its Reorganization Plan would pay in full or nearly in full its pre-petition trade creditors, including several of the WEC Subcontractors which have alleged non-payment by the Consortium for amounts owed for work performed on the Nuclear Project and have filed liens on property in Fairfield County, South Carolina, where Unit 2 and Unit 3 were to be located (Unit 2/3 Property). SCE&G is contesting approximately $285 million of filed liens in Fairfield County. Most of these asserted liens are “pre-petition” claims that relate to work performed by WEC Subcontractors before the WEC bankruptcy, although some of them are “post-petition” claims arising from work performed after the WEC bankruptcy.

WEC has indicated that some unsecured creditors have sought or may seek amounts beyond what WEC allocated when it submitted the Reorganization Plan. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the Reorganization Plan allocated by WEC, 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. See also discussion below regarding limitations with respect to SCE&G’s pre-petition lien obligations arising from its monetization of the Toshiba Settlement.

SCE&G and Santee Cooper are responsible for amounts owed to WEC for valid work performed by WEC Subcontractors on the Nuclear Project after the WEC bankruptcy filing (i.e., post-petition) until termination of the IAA (the IAA Period). While SCE&G and Santee Cooper funded amounts to WEC for such IAA Period obligations on a weekly basis, SCE&G and Santee Cooper undertook a reconciliation to ensure that amounts advanced to WEC for such purposes while the IAA was in effect were paid to WEC Subcontractors. That reconciliation remains ongoing. In the WEC bankruptcy proceeding, deadlines were established for creditors of WEC (including the WEC Subcontractors on the Nuclear Project) to assert the amounts owed to such creditors prior to the WEC bankruptcy filing and during the IAA Period. Many of the WEC Subcontractors have filed such claims. SCE&G does not believe that the claims asserted related to the IAA Period will exceed the amounts previously funded for the currently asserted IAA-related claims, whether relating to claims already paid or those remaining to be paid. SCE&G intends to oppose any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the IAA. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.

Further, some WEC Subcontractors who have made claims against WEC in the bankruptcy proceeding also filed against SCE&G and Santee Cooper in South Carolina state court for damages. The WEC 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 Nuclear Project site. SCE&G also intends to oppose these claims and liens. With respect to claims of WEC Subcontractors during the IAA Period, SCE&G believes there were sufficient amounts previously funded during the IAA Period to pay such validly asserted claims. With respect to the WEC

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Subcontractor claims which relate to other periods, SCE&G understands that such claims will be paid pursuant to WEC’s confirmed Reorganization Plan. SCE&G further understands that the amounts paid under the plan may satisfy such claims in full.  Therefore, SCE&G believes that the WEC Subcontractors may be paid substantially (and potentially in full) from WEC. While SCE&G cannot be assured that it will not have any exposure on account of unpaid WEC Subcontractor claims, which claims SCE&G is presently disputing, SCE&G believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.

Toshiba Settlement and Subsequent Monetization

Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC. In 2015 Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. In satisfaction of such guaranty obligations, on July 27, 2017, the Toshiba Settlement was executed under which Toshiba was to make periodic settlement payments beginning in October 2017 in the total amount of approximately $2.2 billion ($1.2 billion for SCE&G’s 55% share), subject to certain offsets for payments by WEC in bankruptcy that would have the effect of satisfying the liens discussed above and below.

In September and October 2017, proceeds totaling approximately $1.997 billion were received in full satisfaction of the Toshiba Settlement ($1.098 billion for SCE&G's 55% share). The proceeds were obtained through the receipt of a payment from Toshiba and a payment from Citibank arising from its purchase of all other scheduled payments, including amounts related to the contractor liens discussed above. The purchase agreement with Citibank provides that SCE&G and Santee Cooper (each according to its pro rata share) would indemnify Citibank for its losses arising from misrepresentations or covenant defaults under the purchase agreement. SCE&G and Santee Cooper also assigned their claims under the WEC bankruptcy process to Citibank, and agreed to use commercially reasonable efforts to cooperate with Citibank and provide reasonable support necessary for its enforcement of those claims. Proceeds received from the Toshiba Settlement are recorded as a regulatory liability on the accompanying consolidated balance sheets, as the net value of the proceeds will be credited to customer bills over 20 years (see Merger Approval Order above).

Several WEC Subcontractors have filed liens against the Unit 2/3 Property, which SCE&G is contesting. Payments under the Toshiba Settlement are subject to reduction if WEC pays WEC Subcontractors holding pre-petition liens directly. Under these circumstances, SCE&G and Santee Cooper, each in its pro rata share, would be required to make Citibank whole for reductions related to valid subcontractor and vendor pre-petition liens up to $60 million ($33 million for SCE&G's 55% share).

Regulatory, Political and Legal Developments

In connection with the abandonment of the Nuclear Project, various state and local governmental authorities have attempted and may further attempt to challenge, reverse or revoke previously-approved tax or economic development incentives, benefits or exemptions and have attempted and may further attempt to apply such actions retroactively. No assurance can be given as to the timing or outcome of these matters. See Claims and Litigation for a description of specific challenges.

In July 2018, the SCPSC issued orders implementing a June 2018 legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from its electric utility customers under the BLRA and altering certain provisions previously applicable under the BLRA, including redefining the standard of care required by the associated regulations and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the Nuclear Project. These orders reduced the portion of SCE&G’s retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer’s bill, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. These lower rates remained in effect until February 2019, when the new rates pursuant to the Merger Approval Order became effective.

In June 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of the rate reductions under the BLRA. In the lawsuit, which was subsequently amended, SCE&G sought a declaration that the new laws were unconstitutional. On January 8, 2019, SCE&G voluntarily dismissed this lawsuit without prejudice.

Impairment Considerations

In 2017, the Company and Consolidated SC&G recognized pre-tax impairment losses of approximately $1.118 billion (approximately $690 million net of tax) related to the Nuclear Project. In the first quarter of 2018, the Company and

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Consolidated SCE&G recognized a pre-tax impairment loss of approximately $3.6 million (approximately $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. On December 21, 2018, the SCPSC issued the Merger Approval Order which, among other things, limited recovery of capital costs related to the Nuclear Project to $2.768 billion. As a result, the Company and Consolidated SCE&G concluded that Nuclear Project capital costs exceeding the amount established in the Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed, and recorded an impairment charge of approximately $1.372 billion (approximately $870.1 million net of tax) in the fourth quarter of 2018.

In addition, the Company and Consolidated SCE&G expect to record additional impairment charges and establish additional liabilities in the first quarter of 2019. These additional amounts arise from or are related to provisions in the Merger Approval Order and an order by the NCUC approving the SCANA Combination that required the successful consummation of the merger before they would become effective. Accordingly, the following impairment charges and liabilities are expected to be recorded by the Company and Consolidated SCE&G (unless otherwise indicated) in the first quarter of 2019:

• A pre-tax impairment charge of approximately $105 million (approximately $79 million net of tax) related to certain assets that had been constructed in connection with the Nuclear Project that were not abandoned but were instead transferred to Unit 1.

• A regulatory liability for refunds and restitution to electric customers of approximately $1.007 billion pre-tax (approximately $755 million net of tax).

• A regulatory liability for refunds to natural gas customers totaling $2.45 million pre-tax (approximately $1.8 million net of tax).

• A liability related to charitable contributions in South Carolina of approximately $22 million pre-tax (approximately $16 million net of tax). It is expected that an additional liability related to charitable contributions in North Carolina of approximately $0.7 million pre-tax (approximately $0.5 million net of tax) would be recorded by the Company.

• A write-off of excess deferred taxes of approximately $145 million related to the regulatory liability for the monetization of guaranty settlement.

In addition, the SCPSC order approved the removal of SCE&G's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of December 31, 2018, such investment in these assets included approximately $367 million within utility plant, net and approximately $15 million within regulatory assets, which amount represents certain deferred operating costs. The SCPSC also approved deferral of certain operating costs related to the investment. Recovery of the transmission capital costs and associated deferred operating costs will be addressed in a future rate proceeding. The Company and Consolidated SCE&G believe these transmission capital and deferred operating costs are probable of recovery; however, if the SCPSC were to disallow recovery of or a reasonable return on all or a portion of them, an impairment charge equal to the disallowed costs may be required.

Claims and Litigation

Ratepayer Class Actions

In May 2018, a consolidated complaint was filed in the State Court of Common Pleas in Hampton County, South Carolina (the Hampton County Court) against SCE&G, SCANA, and the State of South Carolina (the SCE&G Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that SCE&G was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the Nuclear Project, and that SCE&G committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that SCE&G may not charge its customers for any past or continuing costs of the Nuclear Project, sought to have SCANA and SCE&G’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 Nuclear Project.

In December 2018, the judge entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the SCE&G Ratepayer Case. The settlement agreement provides that SCANA and SCE&G would establish an escrow account (the Common Benefit Fund), and proceeds from the Common Benefit Fund would be distributed to the class members, after payment of certain taxes, attorneys' fees and other expenses and administrative costs. The Common Benefit Fund would include (1) the sum of $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 Common Benefit Fund in favor of class members over a period of time established by the SCPSC in its order related to the Concurrent Dockets, (2) a cash payment of $115 million, and (3) the transfer of certain SCE&G-owned real estate or sales proceeds from the sale of such properties, which counsel for the SCE&G Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA

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and SCE&G have funded this escrow account. The court has scheduled a fairness hearing on the settlement in May 2019. Any distribution from the Common Benefit Fund is subject to court approval. As a result, the Company and Consolidated SCE&G expect to reflect an approximately $157 million ($118 million after-tax) charge in the first quarter of 2019. In addition to court approval, this settlement was contingent on the consummation of the SCANA Combination, which became effective January 1, 2019. Therefore, as of December 31, 2018, no accrual for this potential loss has been included in the consolidated financial statements, but is expected to be recorded by the Company and Consolidated SCE&G in the first quarter of 2019.

In September 2017, a purported class action was filed against Santee Cooper, SCE&G, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the Hampton County Court (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the SCE&G 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 Nuclear 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. In December 2018, Santee Cooper filed its answer to the plaintiffs' fourth amended complaint and filed cross claims against SCE&G. These cross claims include breach of contract accompanied by a fraudulent act, gross negligence, breach of fiduciary duty, breach of contract accompanied by bad faith, waste and equitable indemnification. In January 2019, SCE&G filed a motion to dismiss Santee Cooper's cross claims or in the alternative to compel arbitration and a stay. A hearing has not been scheduled on this motion. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

In January 2018, a purported class action was filed, and subsequently amended, against SCANA, SCE&G and certain former executive officers in the District Court. The plaintiffs allege, among other things, that SCANA, SCE&G 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 SCE&G Ratepayer Case settlement described previously contemplates dismissal of claims by SCE&G ratepayers in this case against SCE&G, SCANA and their former officers. In January 2019, the plaintiffs filed an amended complaint which continues to make allegations on behalf of Santee Cooper ratepayers against SCANA, SCE&G and the individual former executive officers. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

State Court Shareholder Actions

In September 2017, a purported shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina (the Richland County Court). In September 2018, this action was consolidated with another action in the Business Court Pilot Program in Richland County. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the Nuclear Project, and that certain of the defendants were unjustly enriched by bonuses they were paid in connection with the project. The defendants have filed a motion to dismiss the consolidated action in favor of the pending federal derivative action. On January 7, 2019, the defendants filed a motion for judgment on the pleadings, asserting the shareholders in this action lost standing to assert derivative claims as a result of the SCANA Combination. These motions are pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren 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 District Court and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County, South Carolina. Dominion Energy appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with a similar appeal and remains pending. Motions to stay and to consolidate this case are being held in abeyance. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

In February 2018, a purported class action was filed against certain former executive officers and directors of SCANA and SCE&G and Dominion Energy in the Richland County Court. The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the City of Warren Lawsuit. In February 2018, Dominion Energy removed the

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case to the District Court and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the Richland County Court. Dominion Energy appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with the City of Warren Lawsuit. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

Federal Court Shareholder Actions

In November 2017, a purported shareholder derivative action was filed against SCANA and certain former executive officers and directors in the District Court. Another purported shareholder derivative action was filed against nearly all of these defendants. In January 2018, the District Court consolidated these suits, and the plaintiffs filed a consolidated amended complaint. The plaintiffs allege, among other things, that the defendants violated their fiduciary duties to shareholders by disseminating false and misleading information about the Nuclear Project, failing to maintain proper internal controls, failing to properly oversee and manage SCANA and that the individual defendants were unjustly enriched in their compensation. In June 2018, the court denied the defendants' motions to dismiss and in October 2018, the court denied SCANA's motion to stay all proceedings pending investigation by a Special Litigation Committee of its Board of Directors, with leave to refile after the SCPSC's decision on the merger between Dominion Energy and SCANA. On January 7, 2019, the defendants filed a motion for judgment on the pleadings, asserting the shareholders in this action lost standing to assert derivative claims as a result of the SCANA Combination. This motion is pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

In September 2017, a purported class action was filed against SCANA and certain former executive officers in the District Court. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants. In January 2018, the District Court consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and that the individually named defendants are liable under §20(a) of the Exchange Act. The defendants' motions to dismiss are pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

Employment Class Action and Indemnification

In July 2018, a case filed in the District Court was certified as a class action on behalf of persons who formerly worked at the Nuclear Project. The plaintiffs allege, among other things, that SCANA, Fluor Corporation and Fluor Enterprises, Inc. violated the WARN Act in connection with the decision to stop construction at the Nuclear Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment. While SCANA and SCE&G intend to contest this case, it is reasonably possible that a loss estimated to be as much as $75 million could be incurred, of which SCE&G's proportionate share as a co-owner of the Nuclear Project would be 55%. This potential loss could arise due to the Fluor Defendants seeking indemnification from SCE&G.

In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina (the Fairfield County Court) by the Fluor Defendants against SCE&G and Santee Cooper. The Fluor Defendants 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. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of these cases, but there could be a material impact to their results of operations, financial condition and/or cash flows.

FILOT Litigation

In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against SCE&G in the Fairfield County Court. The complaint makes allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty and unfair trade practices related to SCE&G’s termination of the FILOT agreement between SCE&G and Fairfield County related to the Nuclear Project. The plaintiff withdrew the motion for temporary injunction in December 2017. This case is pending. The Company and Consolidated SCE&G are currently unable to make an estimate of the potential impacts to their respective consolidated financial statements related to this matter.

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Other Proceedings and Investigations

In June 2018, SCE&G received a notice of proposed assessment of approximately $410 million, excluding interest, from the DOR following its audit of SCE&G's sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the Nuclear Project, is based on the DOR’s position that SCE&G’s sales and use tax exemption for the Nuclear Project does not apply because the facility will not become operational. SCE&G has protested the proposed assessment, which remains pending, and recorded an $11 million liability in its Consolidated Balance Sheet as of December 31, 2018 for its share of any taxes ultimately due.

On December 29, 2018, arbitration proceedings commenced between SCE&G and Cameco Corporation (Cameco) related to a supply agreement dated May 12, 2008.  This agreement provides the terms and conditions under which SCE&G agreed to purchase uranium hexafluoride from Cameco over a period from 2010 to 2020.  Cameco alleges that SCE&G violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for 2017 and 2018 delivery years.  SCE&G denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement.  The Company and Consolidated SCE&G cannot determine the outcome or timing of this matter.

In 2017 the Company was served with subpoenas issued by the United States Attorney’s Office for the District of South Carolina and the staff of the SEC's Division of Enforcement seeking documents relating to the Nuclear Project. Also, SLED is conducting a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. These investigations are ongoing, and the Company and Consolidated SCE&G intend to fully cooperate with them.

While the Company and Consolidated SCE&G intend to vigorously contest the lawsuits, claims, and audit positions which have been filed or initiated against them, except as noted above, they cannot predict the timing or outcome of these matters or others that may arise, and adverse outcomes from some of these matters would not be covered by insurance. Except as noted above, the various claims for damages do not specify an amount for those damages, and the number of plaintiffs that are ultimately certified in any class action lawsuit is unknown. In addition, most of the cases referred to above are in their early stages. For these reasons, the Company and Consolidated SCE&G (i) have not determined that a loss is probable and (ii) except as noted above, cannot provide any estimate or range of potential loss for these matters at this time. Therefore, no accrual for these potential losses has been included in the consolidated financial statements. However, outcomes could have a material adverse impact on the Company's and Consolidated SCE&G's results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G are subject to various other claims and litigation incidental to their business operations which management anticipates will be resolved without a material impact on the Company's and Consolidated SCE&G's results of operations, cash flows or financial condition.

Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Unit 1.  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 ANI 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 $137.7 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $20.5 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be $91.8 million per incident, but not more than $13.7 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 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, SCE&G’s portion of the retrospective premium assessment would not exceed $23.4 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 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, SCE&G's portion of the retrospective premium assessment would not exceed $2.0 million.

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To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G 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 the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position.

Environmental

The Company's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on the Company's and Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, the Company and Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company and Consolidated SCE&G expect to recover such expenditures and costs through existing ratemaking provisions.

From a regulatory perspective, SCANA, SCE&G 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. SCE&G 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.

In August 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO₂ from newly constructed fossil fuel-fired units. The final rule required all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds CO₂ per MWh and new natural gas units to meet 1,000 pounds CO₂ per MWh. In December 2018, the EPA proposed to revise the standard for newly constructed large coal-fired units to 1,900 pounds of CO₂ per MWh and for small units to 2,000 pounds CO₂ per MWh. The Company and Consolidated SCE&G are monitoring the proposed rule, but do not plan to construct new coal-fired units in the foreseeable future.

On August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The CPP rule included state-specific goals for reducing national CO₂ emissions by 32% from 2005 levels by 2030 and established a phased-in compliance approach beginning in 2022. The rule gave each state from one to three years to issue its SIP, which would ultimately define the specific compliance methodology that would be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. As a result of an Executive Order on March 28, 2017, the EPA placed the rule under review and the Court of Appeals agreed to hold the case in abeyance. On October 10, 2017, the Administrator of the EPA signed a notice proposing to repeal the rule on the grounds that it exceeds the EPA's statutory authority. The Company and Consolidated SCE&G expect any costs incurred to comply with such rule to be recoverable through rates.

On August 21, 2018, the EPA proposed the ACE rule which would replace the CPP. If implemented, the proposed ACE rule would define the “best system of emission reduction” for GHG emissions from existing power plants as on-site, heat-rate efficiency improvements; provide states with a list of “candidate technologies” that can be used to establish standards of performance and incorporated into their state plans; update the EPA’s NSR permitting program to incentivize efficiency improvements at existing power plants; and align CAA section 111(d) general implementing regulations to give states adequate time and flexibility to develop their state plans. The Company and Consolidated SCE&G are currently evaluating the ACE rule for potential impact at their coal fired units and expect any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of SO₂ and NO_X from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO₂ emissions and annual and ozone season NO_X emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO₂ and NO_X and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.

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In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G and GENCO are in compliance with the MATS rule and expect to remain in compliance.

The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits such that, as a facility’s NPDES permit is renewed, any new effluent limitations would be incorporated. The ELG Rule became effective on January 4, 2016, after which state regulators could modify facility NPDES permits to match more restrictive standards, which would require facilities to retrofit with new wastewater treatment technologies. Compliance dates varied by type of wastewater, and some were based on a facility's five-year permit cycle and thus could range from 2018 to 2023. However, the ELG Rule is under reconsideration by the EPA and has been stayed administratively. The EPA has decided to conduct a new rulemaking that could result in revisions to certain flue gas desulfurization wastewater and bottom ash transport water requirements in the ELG Rule. Accordingly, in September 2017 the EPA finalized a rule that resets compliance dates under the ELG Rule to a range from November 1, 2020 to December 31, 2023. The EPA indicates that the new rulemaking process may take up to three years to complete, such that any revisions to the ELG Rule likely would not be final until the summer of 2020. While the Company and Consolidated SCE&G expect that wastewater treatment technology retrofits will be required at Williams and Wateree Stations, any costs incurred to comply with the ELG Rule are expected to be recoverable through rates.

The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications to ensure compliance with this rule. Any costs incurred to comply with this rule are expected to be recoverable through rates.

The EPA's final rule for CCR became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at certain of SCE&G's and GENCO's coal-fired generating facilities. An August 2018 decision by the United States Court of Appeals for the District of Columbia also imposed the rule requirements on CCR ponds at a former generation site owned by SCE&G. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. The Company and Consolidated SCE&G do not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future rates.

In December 2016, the U.S. Congress passed and the President signed legislation that creates a framework for EPA- approved state CCR permit programs. Under this legislation, an approved state CCR permit program functions in lieu of the self-implementing Federal CCR rule. The legislation allows states more flexibility in developing permit programs to implement the environmental criteria in the CCR rule. 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. To date, South Carolina has not begun drafting a CCR rule.

The Nuclear Waste Act 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. SCE&G 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, 2018, the federal government has not accepted any spent fuel from Unit 1, and it remains unclear when the repository may become available. SCE&G has constructed an independent spent fuel storage installation to accommodate the spent nuclear fuel output for the life of Unit 1. SCE&G may evaluate other technology as it becomes available.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to

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date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by or under review by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2020 and will cost an additional $9.5 million. In September 2018, SCE&G submitted an updated remediation work plan for one site (Congaree River) to DHEC which, if approved and subsequently permitted by the USACE, would increase remediation cost for that site by approximately $8 million. DHEC is considering a revised remedy under a MRA but has not issued its direction or approval. SCE&G cannot predict if or when DHEC and the USACE may approve or issue permits for this work to proceed. Major remediation activities are accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheets. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At December 31, 2018, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $23.3 million and are included in regulatory assets.

Other

The Company and Consolidated SCE&G have recorded an estimated liability for amounts collected in customer rates during 2018 that arose from the impact of the Tax Act. Such amounts have been recorded subject to refund, and are described in Note 2.

Long-Term Purchase Agreements

At December 31, 2018, the Company and Consolidated SCE&G 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.

	Future Payments
Millions of dollars	2019		2020		2021		2022		2023		Thereafter
The Company and Consolidated SCE&G	$	40	$	39	$	39	$	38	$	38	$	396

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 approximately $23.7 million in 2018 and $3.6 million in 2017.

Operating Lease Commitments

The Company and Consolidated SCE&G are obligated under various operating leases for land, office space, furniture, equipment, rail cars, and for the Company, airplanes. Leases expire at various dates through 2057.

	Rent Expense						Future Minimum Rental Payments
Millions of dollars	2016		2017		2018		2019		2020		2021		2022		2023		Thereafter
The Company	$	10.2	$	10	$	9.7	$	10	$	8	$	7	$	6	$	4	$	30
Consolidated SCE&G	12.2		11.4		10.2		3		2		1		1		—		16

Guarantees, Surety Bonds and Letters of Credit

SCANA has issued guarantees on behalf of its consolidated subsidiaries to facilitate commercial transactions with third parties. These guarantees are in the form of performance guarantees, primarily for the purchase and transportation of natural gas, and credit support for certain tax-exempt bond issues. SCANA is not required to recognize a liability for such guarantees unless it becomes probable that performance under the guarantees will be required. SCANA believes the likelihood that it would be required to perform or otherwise incur any losses associated with these guarantees is not probable; therefore, no liability for these guarantees has been recognized. To the extent that a liability subject to a guarantee has been incurred, the liability is included in the consolidated financial statements. At December 31, 2018, the maximum future payments (undiscounted) that SCANA could be required to make under guarantees totaled approximately $444.6 million.

At December 31, 2018, SCE&G had purchased a $100.4 million surety bond to facilitate commercial transactions with Dominion Energy Carolina Gas Transmission LLC, which became an affiliate in connection with the SCANA Combination.

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Under the terms of the surety bond, SCE&G is obligated to indemnify the surety bond company for any amounts paid. Further, the Company had authorized the issuance of letters of credit by financial institutions of approximately $80.4 million, including approximately $39.3 million by Consolidated SCE&G, primarily to facilitate commercial transactions and to provide credit support for certain tax-exempt bond issues. Certain of these letters of credit are supported by lines of credit and are discussed in Note 5.

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 the Company’s regulated utility operations.  As of December 31, 2018, the Company and Consolidated SCE&G have recorded AROs of approximately $218 million for nuclear plant decommissioning (see Note 1). In addition, the Company has recorded AROs of approximately $359 million, including $323 million for Consolidated SCE&G, 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: 

	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Beginning balance	$	568		$	558		$	529		$	522
Liabilities incurred	—			—			—			—
Liabilities settled	(15		)	(10		)	(15		)	(9		)
Accretion expense	25			25			23			23
Revisions in estimated cash flows	(1		)	(5		)	4			(7		)
Ending balance	$	577		$	568		$	541		$	529

Revisions in estimated cash flows in 2018 and 2017 primarily related to ash pond retirement obligations settled and updates in the anticipated timing of cash flows as work is completed.

12.          SEGMENT OF BUSINESS INFORMATION

Reportable segments, which are described below, follow the same accounting policies as those described in Note 1. Intersegment sales and transfers of electricity and gas are recorded based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.

Electric Operations primarily generates, transmits and distributes electricity, and is regulated by the SCPSC and FERC. Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, purchases and sells natural gas, primarily at retail. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively. Gas Marketing is comprised of the marketing operations of SCANA Energy, which markets natural gas to retail customers in Georgia and to industrial and large commercial customers and municipalities in the Southeast.

All Other includes the parent company and a services company.

Regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations’ product differs from the other segments, as does its generation process and method of distribution. Gas Marketing operates in a deregulated environment.

Management uses operating income (loss) to measure segment profitability for its regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, no allocation is made to segments for interest charges, income tax expense (benefit) or assets other than utility plant. For nonregulated operations, management uses net income (loss) as the measure of segment profitability and evaluates total assets for financial position. Intersegment revenue for SCE&G was not significant. Interest income is not reported by segment and is not material. Deferred tax assets are netted with deferred tax liabilities for consolidated reporting purposes.

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The consolidated financial statements report operating revenues which are comprised of the energy-related and regulated segments. Revenues from non-reportable and nonregulated segments are included in Other Income. Therefore, the adjustments to total operating revenues remove revenues from non-reportable segments. Adjustments to net income (loss) consist of the unallocated net income (loss) of regulated reportable segments.

 Segment Assets include utility plant, net for SCE&G’s Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G.

Adjustments to Interest Expense, Income Tax Expense (Benefit), Expenditures for Assets and Deferred Tax Assets include primarily the amounts that are not allocated to the segments. Interest Expense is also adjusted to eliminate charges between affiliates. Adjustments to Depreciation and Amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Expenditures for Assets are adjusted for AFC and revisions to estimated cash flows related to AROs, and totals not allocated to other segments. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis.

Disclosure of Reportable Segments 

The Company:

Millions of dollars	Electric Operations			Gas Distribution		Gas Marketing		All Other			Adjustments/ Eliminations			Consolidated Total
2018
External Revenue	$	2,322		$	934	$	796	—			—			$	4,052
Intersegment Revenue	5			1		139		$	470		$	(615	)	—
Operating Income (Loss)	(894		)	173		n/a		—			(8		)	(729		)
Interest Expense	18			37		1		—			328			384
Depreciation and Amortization	307			94		2		15			(15		)	403
Income Tax Expense (Benefit)	9			26		15		(25		)	(437		)	(412		)
Net Income (Loss)	n/a			n/a		43		(90		)	(481		)	(528		)
Segment Assets	7,988			3,517		305		1,212			4,632			17,654
Expenditures for Assets	973			345		2		8			(438		)	890
Deferred Tax Assets	4			17		2		—			(23		)	—
2017
External Revenue	$	2,659		$	874	$	874	—			—			$	4,407
Intersegment Revenue	5			2		127		$	389		$	(523	)	—
Operating Income (Loss)	(154		)	187		n/a		—			52			85
Interest Expense	19			28		1		—			315			363
Depreciation and Amortization	295			85		2		16			(16		)	382
Income Tax Expense (Benefit)	8			41		25		(7		)	(179		)	(112		)
Net Income (Loss)	n/a			n/a		27		(46		)	(100		)	(119		)
Segment Assets	11,979			3,259		230		1,042			2,229			18,739
Expenditures for Assets	216			417		2		7			583			1,225
Deferred Tax Assets	6			25		9		—			(40		)	—
2016
External Revenue	$	2,614		$	788	$	825	—			—			$	4,227
Intersegment Revenue	5			2		111		$	414		$	(532	)	—
Operating Income	969			149		n/a		—			49			1,167
Interest Expense	17			25		1		—			299			342
Depreciation and Amortization	287			82		2		16			(16		)	371
Income Tax Expense	8			32		19		—			212			271
Net Income (Loss)	n/a			n/a		30		(18		)	583			595
Segment Assets	11,929			2,892		230		1,124			2,532			18,707
Expenditures for Assets	1,275			276		2		11			15			1,579

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Deferred Tax Assets 9 32 11 — (52 ) —

Consolidated SCE&G:

Millions of dollars	Electric Operations			Gas Distribution		Adjustments/ Eliminations			Consolidated Total
2018
External Revenue	$	2,327		$	435	—			$	2,762
Operating Income (Loss)	(894		)	63		—			(831		)
Interest Expense	18			—		$	285		303
Depreciation and Amortization	307			32		(12		)	327
Segment Assets	7,988			934		6,041			14,963
Expenditures for Assets	973			90		(430		)	633
Deferred Tax Assets	4			n/a		(4		)	—
2017
External Revenue	$	2,664		$	406	—			$	3,070
Operating Income (Loss)	(154		)	71		—			(83		)
Interest Expense	19			—		$	269		288
Depreciation and Amortization	295			30		(13		)	312
Segment Assets	11,979			869		3,098			15,946
Expenditures for Assets	216			65		647			928
Deferred Tax Assets	6			n/a		(6		)	—
2016
External Revenue	$	2,619		$	367	—			$	2,986
Operating Income	969			56		—			1,025
Interest Expense	17			—		$	253		270
Depreciation and Amortization	287			28		(13		)	302
Segment Assets	11,929			825		3,337			16,091
Expenditures for Assets	1,275			78		46			1,399
Deferred Tax Assets	9			n/a		(9		)	—

13.          UTILITY PLANT AND NONUTILITY PROPERTY

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

Millions of dollars	The Company		Consolidated SCE&G
Gross Utility Plant:
Generation	$	5,751	$	5,751
Transmission	2,417		1,758
Distribution	6,032		4,456
Storage	99		74
General and other	631		535
Intangible	241		229
Construction work in progress	527		350
Nuclear Fuel	611		611
Total Gross Utility Plant	$	16,309	$	13,764
Gross Nonutility Property	$	410	$	73

Jointly Owned Utility Plant

SCE&G jointly owns and is the operator of Unit 1. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. SCE&G’s share of the direct expenses is included in the

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corresponding operating expenses on its income statement. Unit 2 and Unit 3 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 2.

As of December 31,	2018			2017
	Unit 1			Unit 1
Percent owned	66.7%			66.7%
Plant in service	$	1.5	billion	$	1.5	billion
Accumulated depreciation	$	643.9	million	$	637.6	million
Construction work in progress	$	127.5	million	$	110.1	million

Included within other receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses. These amounts totaled $46.3 million at December 31, 2018 and $53.8 million at December 31, 2017.

14.          AFFILIATED TRANSACTIONS

The Company:

The Company received cash distributions from equity-method investees of $2.3 million in 2018, $2.8 million in 2017 and $3.7 million in 2016. The Company made investments in equity-method investees of $4.2 million in 2018, $4.6 million in 2017 and $5.5 million in 2016.

The Company and Consolidated SCE&G:

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of operations (for the Company) and of comprehensive income (for Consolidated SCE&G).

Millions of Dollars	2018		2017		2016
Purchases from Canadys Refined Coal, LLC	$	149.9	$	162.1	$	161.8
Sales to Canadys Refined Coal, LLC	149.0		161.1		160.8

Millions of Dollars	2018		2017
Receivable from Canadys Refined Coal, LLC	$	6.8	$	4.9
Payable to Canadys Refined Coal, LLC	6.8		4.9

Consolidated SCE&G:

SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. 

SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, 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, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in Other operation and maintenance - nonconsolidated affiliate and Other Income (Expense), net on the consolidated statements of comprehensive income.

Millions of Dollars	2018		2017		2016
Purchases from SCANA Energy	$	139.0	$	127.4	$	111.5
Direct and Allocated Costs from SCANA Services	283.3		302.8		337.7

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Millions of Dollars	2018		2017
Payable to SCANA Energy	$	14.1	$	10.0
Payable to SCANA Services	37.7		42.0

Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 5. Certain disclosures regarding SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 9.

15.          OTHER INCOME (EXPENSE), NET

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

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
Revenues from contracts with customers	$	20		—			—			$	5		—			—
Other income	180			$	79		$	64		141			$	45		$	29
Other expense	(46		)	(55		)	(52		)	(28		)	(32		)	(36		)
Allowance for equity funds used during construction	19			23			29			11			15			26
Other income (expense), net	$	173		$	47		$	41		$	129		$	28		$	19

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 3, and as permitted, prior periods have not been restated. For the Company and Consolidated SCE&G, other income in 2018 includes gains from the settlement of interest rate derivatives of approximately $114 million (see Note 7). For the Company and Consolidated SCE&G, non-service cost components of pension and other postretirement benefits are included in other expense.

16.          QUARTERLY FINANCIAL DATA (UNAUDITED)

The Company Millions of dollars, except per share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Annual
2018
Total Operating Revenues	$	1,180	$	843	$	926	$	1,103		$	4,052
Operating Income (Loss)	189		103		183		(1,204		)	(729		)
Net Income (Loss)	169		8		67		(772		)	(528		)
Earnings (Loss) Per Share of Common Stock	1.18		0.06		0.47		(5.41		)	(3.70		)
2017
Total Operating Revenues	$	1,173	$	1,001	$	1,076	$	1,157		$	4,407
Operating Income (Loss)	320		251		122		(608		)	85
Net Income (Loss)	171		121		34		(445		)	(119		)
Earnings (Loss) Per Share of Common Stock	1.19		0.85		0.24		(3.11		)	(0.83		)

Consolidated SCE&G Millions of dollars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Annual
2018
Total Operating Revenues	$	702	$	632	$	739	$	689		$	2,762
Operating Income (Loss)	121		107		212		(1,271		)	(831		)
Total Comprehensive Income (Loss)	128		31		104		(852		)	(589		)
Comprehensive Income Available (Loss Attributable) to Common Shareholder	124		26		98		(861		)	(613		)
2017
Total Operating Revenues	$	719	$	756	$	856	$	739		$	3,070
Operating Income (Loss)	226		247		124		(680		)	(83		)
Total Comprehensive Income (Loss)	112		126		42		(452		)	(172		)
Comprehensive Income Available (Loss Attributable) to Common Shareholder	109		123		39		(456		)	(185		)

86

See Note 11 for a discussion of impairment losses booked in the third and fourth quarter of 2017 and the first and fourth quarter of 2018.

87

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not Applicable.

ITEM 9A.  CONTROLS AND PROCEDURES

SCANA:

Evaluation of Disclosure Controls and Procedures:

As of December 31, 2018, SCANA conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of the effectiveness of the design and operation of SCANA’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based on this evaluation, the CEO and CFO concluded that, as of December 31, 2018, SCANA's disclosure controls and procedures were effective.

Management’s Evaluation of Internal Control Over Financial Reporting:

As of December 31, 2018, SCANA conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of any change in SCANA's internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended December 31, 2018. There has been no change in SCANA’s internal controls over financial reporting during the quarter ended December 31, 2018 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

The Management Report on Internal Control over Financial Reporting follows.

MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of SCANA is responsible for establishing and maintaining adequate internal control over financial reporting. SCANA’s internal control system was designed by or under the supervision of SCANA’s management, including its CEO and CFO, to provide reasonable assurance to SCANA’s management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of the internal control over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.

SCANA’s management assessed the effectiveness of SCANA’s internal control over financial reporting as of December 31, 2018.  In making this assessment, SCANA used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework (2013). Based on this assessment, SCANA’s management believes that, as of December 31, 2018, internal control over financial reporting is effective based on those criteria.

SCANA’s independent registered public accounting firm has issued an attestation report on SCANA’s internal control over financial reporting. This report follows.

88

ATTESTATION REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

SCANA Corporation

Cayce, South Carolina

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of SCANA Corporation and subsidiaries (the “Company”) as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2018, of the Company and our report dated February 28, 2019 expressed an unqualified opinion on those financial statements and financial statement schedule.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/DELOITTE & TOUCHE LLP

Charlotte, North Carolina

February 28, 2019

89

SCE&G:

Evaluation of Disclosure Controls and Procedures:

As of December 31, 2018, SCE&G conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of the effectiveness of the design and operation of SCE&G’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based on this evaluation, the CEO and CFO concluded that, as of December 31, 2018, SCE&G's disclosure controls and procedures were effective.

Management’s Evaluation of Internal Control Over Financial Reporting:

As of December 31, 2018, SCE&G conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of any change in SCE&G's internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended December 31, 2018. There has been no change in SCE&G’s internal controls over financial reporting during the quarter ended December 31, 2018 that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

The Management Report on Internal Control over Financial Reporting follows.

MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of SCE&G is responsible for establishing and maintaining adequate internal control over financial reporting. SCE&G’s internal control system was designed by or under the supervision of SCE&G’s management, including its CEO and CFO, to provide reasonable assurance to SCE&G’s management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of the internal control over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.

SCE&G’s management assessed the effectiveness of SCE&G’s internal control over financial reporting as of December 31, 2018. In making this assessment, SCE&G used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, SCE&G’s management believes that, as of December 31, 2018, internal control over financial reporting is effective based on those criteria.

ITEM 9B. OTHER INFORMATION

Not Applicable.

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Not applicable. 

ITEM 11.  EXECUTIVE COMPENSATION

Not applicable.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Not applicable.

90

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Not applicable.

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

SCANA and SCE&G:

The Audit Committee Charter required the Audit Committee to pre-approve all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed by the independent registered accounting firm. Pursuant to a policy adopted by the Audit Committee, its Chairman could pre-approve the rendering of services on behalf of the Audit Committee. Decisions by the Chairman to pre-approve the rendering of services would be presented to the Audit Committee at its next scheduled meeting.

Independent Registered Public Accounting Firm’s Fees

The following table sets forth the aggregate fees, all of which were approved by the Audit Committee, charged to the Company and Consolidated SCE&G for the fiscal years ended December 31, 2018 and 2017 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.

	The Company				Consolidated SCE&G
	2018		2017		2018		2017
Audit Fees (1)	$	3,670,000	$	3,670,360	$	2,621,562	$	3,127,191
Audit-Related Fees (2)	138,700		168,229		97,048		139,172
Tax Fees (3)	123,373		—		—		—
Total Fees	$	3,932,073	$	3,838,589	$	2,718,610	$	3,266,363

⁽¹⁾ Fees for audit services billed in 2018 and 2017 consisted of audits of annual financial statements, comfort letters for securities underwriters, statutory and regulatory audits, consents and other services related to SEC filings, and accounting research.

⁽²⁾ Fees primarily for employee benefit plan audits and non-statutory audit services.

⁽³⁾ Fees related to Internal Revenue Code Section 280G rules.

PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)    The following documents are filed or furnished as a part of this Form 10-K:

(1)    Financial Statements and Schedules:

The Report of Independent Registered Public Accounting Firm on the financial statements for each of SCANA and SCE&G is listed under Item 8 herein. The financial statements and supplementary financial data filed as part of this report for SCANA and SCE&G are listed under Item 8 herein. The financial statement schedules "Schedule II - Valuation and Qualifying Accounts" filed as part of this report for SCANA and SCE&G are included below.

(2)    Exhibits

Exhibits required to be filed or furnished with this Annual Report on Form 10-K are listed in the Exhibit Index immediately preceding the signature page. Certain of such exhibits which have heretofore been filed with the SEC and which are designated by reference to their exhibit number in prior filings are incorporated herein by reference and made a part hereof.

As permitted under Item 601(b)(4)(iii) of Regulation S-K, instruments defining the rights of holders of long-term debt of less than 10% of the total consolidated assets of SCANA, for itself and its subsidiaries and of SCE&G, for itself and its consolidated affiliates, have been omitted and SCANA and SCE&G agree to furnish a copy of such instruments to the SEC upon request.

91

Schedule II—Valuation and Qualifying Accounts

			Additions
Description (in millions)	Beginning Balance		Charged to Income		Charged to Other Accounts	Deductions from Reserves		Ending Balance
SCANA:
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2018	$	6	$	15	—	$	14	$	7
2017	6		13		—	13		6
2016	5		12		—	11		6
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2018	$	9	$	5	—	$	7	$	7
2017	9		8		—	8		9
2016	6		5		—	2		9
SCE&G:
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2018	$	4	$	7	—	$	7	$	4
2017	3		8		—	7		4
2016	3		6		—	6		3
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2018	$	8	$	5	—	$	7	$	6
2017	8		8		—	8		8
2016	5		5		—	2		8

ITEM 16.  FORM 10-K SUMMARY

Not Applicable.

92

EXHIBIT INDEX

Exhibit	Applicable to Form 10-K of
No.	SCANA	SCE&G	Description
2.01*	X		Agreement and Plan of Merger by and among Dominion Energy, Sedona Corp., and SCANA, dated as of January 2, 2018 (Filed as Exhibit 2.1 to Form 8-K on January 5, 2018 (File No. 001-08809 (SCANA)) and incorporated by reference herein)
3.01	X		Restated Articles of Incorporation of SCANA, as adopted on February 1, 2019 (Filed as Exhibit 3.1 to Form 8-K on February 8, 2019 (File No. 001-08809) and incorporated by reference herein).
3.02		X	Restated Articles of Incorporation of SCE&G, as adopted on December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File No. 000-53860) and incorporated by reference herein)
3.03	X		By-Laws of SCANA as amended and restated as of January 1, 2019 (Filed as Exhibit 3.1 to Form 8-K on January 2, 2019 (File No. 001-08809) and incorporated by reference herein)
3.04		X	By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein)
4.01	X	X	Articles of Exchange of SCE&G and SCANA (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	X		Indenture dated as of November 1, 1989 between SCANA and The Bank of New York Mellon Trust Company, N. A. (successor to The Bank of New York), as Trustee (Filed as Exhibit 4-A to Registration No. 33-32107 and incorporated by reference herein). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
4.03		X	Indenture dated as of April 1, 1993 from SCE&G 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 and incorporated by reference herein). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
4.04		X	First Supplemental Indenture to Indenture referred to in Exhibit 4.04 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421 and incorporated by reference herein). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
4.05		X	Second Supplemental Indenture to Indenture referred to in Exhibit 4.04 dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955 and incorporated by reference herein). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
4.06		X	Third Supplemental Indenture to Indenture referred to in Exhibit 4.04 dated as of September 1, 2013 (Filed as Exhibit 4.12 to Post-Effective Amendment to Registration Statement No. 333-184426-01 and incorporated by reference herein).
10.01	X	X	Contract for AP1000 Fuel Fabrication and Related Services between Westinghouse Electric Company LLC and SCE&G for V. C. Summer AP1000 Nuclear Plant Units 2 & 3 (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) (Filed as Exhibit 10.01 to Form 10-Q/A for the quarter ended June 30, 2011 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G)) and incorporated by reference herein)
10.02		X	Service Agreement between SCE&G and SCANA Services, Inc., effective January 1, 2004 (Filed as Exhibit 99.10 to Registration Statement No. 333-174796 and incorporated by reference herein)
10.03	X		Second Amended and Restated Five-Year Credit Agreement dated as of December 17, 2015, by and among SCANA; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; Morgan Stanley Bank, N.A., as Issuing Bank; Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents; and Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Bank, LTD., MUFG Union Bank, N.A., TD Bank N.A. and UBS Securities, LLC, as Documentation Agents (Filed as Exhibit 99.1 to Form 8-K on December 22, 2015 (File No. 001-08809) and incorporated by reference herein)

93

10.04	X	X	Second Amended and Restated Five-Year Credit Agreement dated as of December 17, 2015, by and among SCE&G; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; Bank of America, N.A., as Issuing Bank and Co-Syndication Agent; Morgan Stanley Senior Funding, Inc., as Co-Syndication Agent; and Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Bank, LTD., MUFG Union Bank, N.A., TD Bank N.A. and UBS Securities, LLC, as Documentation Agents (Filed as Exhibit 99.2 to Form 8-K on December 22, 2015 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G)) and incorporated by reference herein)
10.05	X		Second Amended and Restated Five-Year Credit Agreement dated as of December 17, 2015, by and among PSNC Energy; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents; and Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Bank, LTD., MUFG Union Bank, N.A., TD Bank N.A. and UBS Securities, LLC, as Documentation Agents (Filed as Exhibit 99.5 to Form 8-K on December 22, 2015 (File No. 001-08809) and incorporated by reference herein)
10.06	X	X	Settlement Agreement dated as of July 27, 2017, by and among Toshiba, SCE&G and Santee Cooper (Filed as Exhibit 99.2 to Form 8-K dated July 27, 2017 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G)) and incorporated by reference herein)
10.07	X	X	Trade Confirmation dated September 25, 2017, between SCE&G, Santee Cooper and Citibank, N.A., and associated Assignment and Purchase Agreement, dated September 27, 2017, by and among SCE&G, Santee Cooper and Citibank, N. A. (Filed as Exhibit 10.03 to Form 10-Q for the quarter ended September 30, 2017 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G)) and incorporated by reference herein)
10.08	X	X	Settlement Agreement and an Addendum dated as of November 24, 2018, by and among SCANA, SCE&G, Richard Lightsey, LeBrian Cleckley, Phillip Cooper and the State of South Carolina. (Filed herewith)
31.01	X		Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.02	X		Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.03		X	Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.04		X	Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
32.01	X		Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02		X	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
101. INS**	X	X	XBRL Instance Document
101. SCH**	X	X	XBRL Taxonomy Extension Schema
101. CAL**	X	X	XBRL Taxonomy Extension Calculation Linkbase
101. DEF**	X	X	XBRL Taxonomy Extension Definition Linkbase
101. LAB**	X	X	XBRL Taxonomy Extension Label Linkbase
101. PRE**	X	X	XBRL Taxonomy Extension Presentation Linkbase
* Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. SCANA agrees to furnish supplementally to the SEC a copy of any omitted schedule upon request by the SEC.
** Pursuant to Rule 406T of Regulation S-T, this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

94

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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

		SCANA CORPORATION
	BY:	/s/ Thomas F. Farrell, II
		(Thomas F. Farrell, II, Chairman of the Board of Directors)
DATE:	February 28, 2019

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 and on the dates indicated on the 28th day of February, 2019.

Signature	Title
/s/ Thomas F. Farrell, II	Chairman of the Board of Directors
Thomas F. Farrell, II
/s/ P. Rodney Blevins	Director, President and Chief Executive Officer
P. Rodney Blevins
/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

95

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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries or consolidated affiliates thereof. 

		SOUTH CAROLINA ELECTRIC & GAS COMPANY
	BY:	/s/ Thomas F. Farrell, II
		(Thomas F. Farrell, II, Chairman of the Board of Directors)
DATE:	February 28, 2019

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 and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries or consolidated affiliates thereof. 

Signature	Title
/s/ Thomas F. Farrell, II	Chairman of the Board of Directors
Thomas F. Farrell, II
/s/ P. Rodney Blevins	Director, President and Chief Executive Officer
P. Rodney Blevins
/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

DATE: February 28, 2019

96

EX-10.08

Exhibit 10.08

EX-31.01

Exhibit 31.01

CERTIFICATION

I, P. Rodney Blevins, certify that:

1.             I have reviewed this annual report on Form 10-K of SCANA Corporation;

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.

February 28, 2019	/s/P. Rodney Blevins
	P. Rodney Blevins
	Chief Executive Officer

EX-31.02

Exhibit 31.02

CERTIFICATION

I, James R. Chapman, certify that:

1.             I have reviewed this annual report on Form 10-K of SCANA Corporation;

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.

February 28, 2019	/s/James R. Chapman
	James R. Chapman
	Chief Financial Officer

EX-31.03

Exhibit 31.03

CERTIFICATION

I, P. Rodney Blevins, certify that:

1.             I have reviewed this annual report on Form 10-K of South Carolina Electric & Gas Company;

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.

February 28, 2019	/s/P. Rodney Blevins
	P. Rodney Blevins
	Chief Executive Officer

EX-31.04

Exhibit 31.04 

CERTIFICATION

I, James R. Chapman, certify that:

1.             I have reviewed this annual report on Form 10-K of South Carolina Electric & Gas Company;

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.

February 28, 2019	/s/James R. Chapman
	James R. Chapman
	Chief Financial Officer

EX-32.01

Exhibit 32.01 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of SCANA Corporation (the “Company”) on Form 10-K for the year ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 28, 2019
/s/ P. Rodney Blevins	/s/ James R. Chapman
P. Rodney Blevins	James R. Chapman
Chief Executive Officer	Chief Financial Officer

EX-32.02

Exhibit 32.02

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of South Carolina Electric & Gas Company (the “Company”) on Form 10-K for the year ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 28, 2019
/s/ P. Rodney Blevins	/s/ James R. Chapman
P. Rodney Blevins	James R. Chapman
Chief Executive Officer	Chief Financial Officer

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 15, 2019	Jun. 30, 2018
Document Information [Line Items]
Entity Registrant Name	SCANA CORP
Entity Central Index Key	0000754737
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Shell Company	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		100
Entity Public Float			$ 5,486,355,874
SCE&G
Document Information [Line Items]
Entity Registrant Name	SOUTH CAROLINA ELECTRIC & GAS CO
Entity Central Index Key	0000091882
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,296,147

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Assets
Utility Plant In Service	$ 15,171	$ 14,370
Accumulated Depreciation and Amortization	(5,109)	(4,611)
Construction Work in Progress	527	471
Nuclear Fuel, Net of Accumulated Amortization	211	208
Goodwill, Net of Writedown of $230	210	210
Utility Plant, Net	11,010	10,648
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	267	270
Assets held in trust, net-nuclear decommissioning	190	136
Other investments	22	68
Nonutility Property and Investments, Net	479	474
Current Assets:
Cash and cash equivalents	389	409
Receivables, net of allowance for uncollectible accounts	632	665
Income taxes	0	198
Accounts and Other Receivables, Net, Current	88	105
Inventories (at average cost):
Fuel	153	143
Materials and supplies	170	161
Prepaid Expense	105	99
Other Assets, Current	12	71
Total Current Assets	1,549	1,851
Deferred Debits and Other Assets:
Regulatory assets	4,380	5,580
Other	236	186
Regulated Entity, Other Assets, Noncurrent	4,616	5,766
Total	17,654	18,739
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,389	2,390
Retained Earnings, Unappropriated	2,247	2,915
Accumulated Other Comprehensive Income (Loss), Net of Tax	(34)	(50)
Common equity	4,602	5,255
Long-term Debt, Excluding Current Maturities	6,695	5,906
Total Capitalization	11,297	11,161
Current Liabilities:
Short-term borrowings	173	350
Long-term Debt, Current Maturities	59	727
Accounts payable	430	438
Customer deposits and customer prepayments	114	112
Taxes accrued	245	214
Interest accrued	89	87
Dividends declared	17	86
Other	72	99
Total Current Liabilities	1,276	2,113
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,112	1,261
Asset retirement obligations	577	568
Pension and other postretirement benefits	376	360
Unrecognized tax benefits	38	19
Regulatory liabilities	2,789	3,059
Other	189	198
Total Deferred Credits and Other Liabilities	5,081	5,465
Commitments and Contingencies (Note 10)
Total	17,654	18,739
SCE&G
Assets
Utility Plant In Service	12,803	12,161
Accumulated Depreciation and Amortization	(4,581)	(4,124)
Construction Work in Progress	350	375
Nuclear Fuel, Net of Accumulated Amortization	211	208
Utility Plant, Net	8,783	8,620
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	72	71
Assets held in trust, net-nuclear decommissioning	190	136
Other investments	1	2
Nonutility Property and Investments, Net	263	209
Current Assets:
Cash and cash equivalents	377	395
Receivables, net of allowance for uncollectible accounts	344	390
Income taxes	0	198
Due from Affiliate, Current	359	32
Accounts and Other Receivables, Net, Current	68	85
Inventories (at average cost):
Fuel	89	90
Materials and supplies	158	149
Prepayments	82	82
Other Assets, Current	1	56
Total Current Assets	1,478	1,477
Deferred Debits and Other Assets:
Regulatory assets	4,256	5,476
Other	183	164
Regulated Entity, Other Assets, Noncurrent	4,439	5,640
Total	14,963	15,946
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,860	2,860
Retained Earnings, Unappropriated	1,279	1,982
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)	(4)
Common equity	4,136	4,838
Stockholders' Equity Attributable to Noncontrolling Interest	179	142
Total Equity	4,315	4,980
Long-term Debt, Excluding Current Maturities	5,132	4,441
Total Capitalization	9,447	9,421
Current Liabilities:
Short-term borrowings	73	252
Long-term Debt, Current Maturities	14	723
Accounts payable	267	251
Due to Affiliate, Current	347	102
Customer deposits and customer prepayments	83	70
Taxes accrued	239	208
Interest accrued	72	67
Dividends declared	10	82
Other	32	49
Total Current Liabilities	1,214	1,804
Deferred Credits and Other Liabilities:
Deferred income taxes, net	989	1,173
Asset retirement obligations	542	529
Pension and other postretirement benefits	232	217
Unrecognized tax benefits	38	19
Regulatory liabilities	2,380	2,667
Other	105	97
Due to Affiliate, Noncurrent	16	19
Total Deferred Credits and Other Liabilities	4,302	4,721
Commitments and Contingencies (Note 10)
Total	$ 14,963	$ 15,946

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Public Utilities, Property, Plant and Equipment, Net	$ 11,010	$ 10,648
Regulated Entity, Other Assets, Noncurrent	4,616	5,766
Nonutility property, accumulated depreciation	143	133
Receivables, net of allowance for uncollectible accounts	7	6
Assets, Current	$ 1,549	$ 1,851
Common Stock, Shares, Outstanding	143.0	143.0
SCE&G
Public Utilities, Property, Plant and Equipment, Net	$ 8,783	$ 8,620
Regulated Entity, Other Assets, Noncurrent	4,439	5,640
Receivables, net of allowance for uncollectible accounts	4	4
Assets, Current	$ 1,478	$ 1,477
Common Stock, Shares, Outstanding	40.3	40.3
VIEs | SCE&G
Public Utilities, Property, Plant and Equipment, Net	$ 711	$ 711
Regulated Entity, Other Assets, Noncurrent	34	50
Assets, Current	$ 90	$ 191

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenues:
Electric Regulated Revenue	$ 2,322.0	$ 2,659.0	$ 2,614.0
Regulated Operating Revenue, Gas	934.0	874.0	788.0
Gas-nonregulated	796.0	874.0	825.0
Regulated and Unregulated Operating Revenue	4,052.0	4,407.0	4,227.0
Utilities Operating Expense [Abstract]
Fuel used in electric generation	671.0	594.0	576.0
Purchased power	92.0	80.0	64.0
Utilities Operating Expense, Gas and Petroleum Purchased	1,128.0	1,156.0	1,054.0
Other operation and maintenance	835.0	728.0	741.0
Utilities Operating Expense, Maintenance and Operations, Affiliate	18.4
Utilities Operating Expense, Impairments	1,376.0	1,118.0
Depreciation and amortization	403.0	382.0	371.0
Other taxes	276.0	264.0	254.0
Utilities Operating Expense	4,781.0	4,322.0	3,060.0
Operating Income	(729.0)	85.0	1,167.0
Other Nonoperating Income (Expense)	173.0	47.0	41.0
Other Income (Expense):
Other income	180.0	79.0	64.0
Other expenses	(46.0)	(55.0)	(52.0)
Interest charges, net of allowance for borrowed funds used during construction	(384.0)	(363.0)	(342.0)
Allowance for equity funds used during construction	19.0	23.0	29.0
Total Other Expense	173.0	47.0	41.0
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(940.0)	(231.0)	866.0
Income Tax Expense (Benefit)	(412.0)	(112.0)	271.0
Income Available to Common Shareholders	$ (528.0)	$ (119.0)	$ 595.0
Earnings Per Share, Basic and Diluted	$ (3.70)	$ (0.83)	$ 4.16
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ (512.0)	$ (120.0)	$ 611.0
Weighted Average Common Shares Outstanding (millions)
Weighted Average Number of Shares Outstanding, Basic	143	143	143
SCE&G
Operating Revenues:
Electric Regulated Revenue	$ 2,322.0	$ 2,659.0	$ 2,614.0
Electric Domestic Regulated Revenues - Affiliate	5.0	5.0	5.0
Regulated Operating Revenue, Gas	434.0	405.0	366.0
Regulated Operating Revenue Gas, Affiliate	1.0	1.0	1.0
Regulated Operating Revenue	2,762.0	3,070.0	2,986.0
Utilities Operating Expense [Abstract]
Fuel used in electric generation	531.0	465.0	472.0
Utilities Operating Expense, Fuel Used, Affiliate	140.0	129.0	104.0
Purchased power	92.0	80.0	64.0
Utilities Operating Expense, Gas and Petroleum Purchased	239.0	206.0	174.0
Utilities Operating Expense, Gas and Petroleum Purchased, affiliate			9.0
Other operation and maintenance	449.0	417.0	403.0
Utilities Operating Expense, Maintenance and Operations, Affiliate	182.0	180.0	199.0
Utilities Operating Expense, Impairments	1,376.0	1,118.0
Depreciation and amortization	327.0	312.0	302.0
Other taxes	251.0	241.0	227.0
Utilities Operating Expense, Taxes, Affiliate	6.0	5.0	7.0
Utilities Operating Expense	3,593.0	3,153.0	1,961.0
Operating Income	(831.0)	(83.0)	1,025.0
Other Nonoperating Income (Expense)	129.0	28.0	19.0
Other Income (Expense):
Other income	141.0	45.0	29.0
Other expenses	(28.0)	(32.0)	(36.0)
Interest charges, net of allowance for borrowed funds used during construction	(303.0)	(288.0)	(270.0)
Allowance for equity funds used during construction	11.0	15.0	26.0
Total Other Expense	129.0	28.0	19.0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	(1,005.0)	(343.0)	774.0
Income Tax Expense (Benefit)	(416.0)	(171.0)	248.0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(589.0)	(172.0)	526.0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent	1.0	(1.0)	0.0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(588.0)	(173.0)	526.0
Net Income (Loss) Attributable to Noncontrolling Interest	25.0	13.0	13.0
Earnings Available to Common Shareholder	(613.0)	$ (185.0)	$ 513.0
Subsidiaries [Member] | SCE&G
Other Income (Expense):
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (589.0)

XML

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Interest charges, allowance for borrowed funds used during construction	$ 12	$ 18	$ 19
SCE&G
Interest charges, allowance for borrowed funds used during construction	$ 9	$ 15	$ 18

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Available to Common Shareholders	$ (528)	$ (119)	$ 595
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, after Tax	(2)	(7)	4
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	14	(1)	(17)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	0	0	(1)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	2	0	(1)
Other Comprehensive Income (Loss), Net of Tax	16	(1)	16
Net Income (Loss) Attributable to Parent [Abstract]
Total Comprehensive Income (Loss)	(512)	(120)	611
SCE&G
Other Comprehensive Income (Loss), Net of Tax	1	(1)	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(589)	(172)	526
Other Comprehensive Income (Loss)
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax	0	(1)	0
Less comprehensive income attributable to noncontrolling interest	25	13	13
Net Income (Loss) Attributable to Parent [Abstract]
Total Comprehensive Income (Loss)	(588)	(173)	526
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	(588)	(173)	526
SCEG excluding VIEs [Member]
Income Available to Common Shareholders	(614)	(185)	513
Net Income (Loss) Attributable to Parent [Abstract]
Total Comprehensive Income (Loss)	(613)	(186)	513
Interest Rate Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	9	7	7
Commodity Contract [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 7	$ (1)	$ 6

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ 2	$ 2	$ 2
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	4	4	4
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax	4	4	4
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	$ 0	$ 0	$ 0

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Flows from Operating Activities
Net Income (Loss) Available to Common Stockholders, Basic	$ (528)	$ (119)	$ 595
Adjustments to reconcile net income to net cash provided from operating activities:
Utilities Operating Expense, Impairments	1,376	1,118
Gain on Sale of Investments	(30)
Deferred income taxes, net	(151)	(911)	242
Depreciation and amortization	434	406	389
Amortization of nuclear fuel	47	44	57
Allowance for equity funds used during construction	(19)	(23)	(29)
Carrying cost recovery	(6)	(34)	(17)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	(37)	56	112
Increase (Decrease) in Income Taxes Receivable	198	(56)	(142)
Increase (Decrease) in Inventories	88	93	43
Increase (Decrease) in Prepaid Expense	4	5	(11)
Increase (Decrease) in Other Regulatory Assets	199	(181)	114
Increase (Decrease) in Regulatory liabilities	(350)	1,051	(2)
Increase (Decrease) in Accounts Payable	61	24	44
Unrecognized tax benefits, increase (decrease)	19	(224)	175
Increase (Decrease) Revenue Subject to Refund	77
Increase (Decrease) in Taxes accrued	31	13	(41)
Increase (Decrease) in Obligation, Pension and Other Postretirement Benefits	16	(20)	51
Changes in other assets	(61)	47	44
Changes in other liabilities	(18)	(80)	72
Net Cash Provided from Operating Activities	964	1,169	1,092
Cash Flows From Investing Activities
Property additions and construction expenditures	(890)	(1,225)	(1,579)
Proceeds from Sale of Other Receivables	0	1,096
Proceeds from investments (including derivative collateral posted)	227	145	860
Purchase of investments (including derivative collateral posted)	(155)	(143)	(788)
Payments upon interest rate contract settlement		(39)	(113)
Payments for (Proceeds from) Hedge, Investing Activities	115		0
Net Cash Used for Investing Activities	(703)	(166)	(1,620)
Cash Flows from Financing Activities
Proceeds from issuance of long-term debt	935	150	592
Repayments of Long-term Debt	(830)	(17)	(117)
Dividends	(209)	(344)	(325)
Short-term borrowings, net	(177)	(591)	410
Net Cash Provided From Financing Activities	(281)	(802)	560
Net (Decrease) Increase in Cash and Cash Equivalents	(20)	201	32
Cash and Cash Equivalents, January 1	409	208	176
Cash and Cash Equivalents, December 31	389	409	208
Supplemental Cash Flow Information
Cash paid for-Interest (net of capitalized interest )	356	346	328
Cash paid for-Income taxes	4	2	229
Proceeds from Income Tax Refunds	206	184
Cash Flow, Noncash Investing and Financing Activities Disclosure
Accrued construction expenditures	85	139	109
Capital Lease Obligations Incurred	11	8	15
Proceeds from Contribution in Aid of Construction	6
SCE&G
Cash Flows from Operating Activities
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(589)	(172)	526
Adjustments to reconcile net income to net cash provided from operating activities:
Utilities Operating Expense, Impairments	1,376	1,118
Deferred income taxes, net	(184)	(780)	207
Depreciation and amortization	342	323	310
Amortization of nuclear fuel	47	44	57
Allowance for equity funds used during construction	(11)	(15)	(26)
Carrying cost recovery	(6)	(34)	(17)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	(50)	32	47
Increase (Decrease) in Due from Affiliates, Current	(2)	12	(3)
Increase (Decrease) in Income Taxes Receivable	198	(145)	(53)
Increase (Decrease) in Inventories	54	60	35
Increase (Decrease) in Prepaid Expense	0	(6)	4
Increase (Decrease) in Other Regulatory Assets	179	(185)	94
Increase (Decrease) in Regulatory liabilities	(360)	899	(5)
Increase (Decrease) in Accounts Payable	61	20	8
Unrecognized tax benefits, increase (decrease)	19	(241)	192
Increase (Decrease) in Due to Affiliates, Current	0	(28)	13
Increase (Decrease) Revenue Subject to Refund	77
Increase (Decrease) in Taxes accrued	31	13	(104)
Increase (Decrease) in Obligation, Pension and Other Postretirement Benefits	15	(21)	39
Changes in other assets	(77)	46	99
Changes in other liabilities	22	(43)	58
Increase (Decrease) in Due to Affiliates	(3)	3	(1)
Net Cash Provided from Operating Activities	927	1,006	922
Cash Flows From Investing Activities
Property additions and construction expenditures	(633)	(928)	(1,399)
Proceeds from Sale of Other Receivables	0	1,096
Proceeds from investments (including derivative collateral posted)	40	118	794
Purchase of investments (including derivative collateral posted)	(29)	(122)	(740)
Payments to Acquire Interest in Subsidiaries and Affiliates	(111)
Payments upon interest rate contract settlement	0	(39)	(113)
Payments for (Proceeds from) Hedge, Investing Activities	115	0	0
Proceeds from Investment In Affiliate	111	0	9
Investment In Affiliate	(325)	(28)
Net Cash Used for Investing Activities	(832)	97	(1,449)
Cash Flows from Financing Activities
Proceeds from issuance of long-term debt	795	0	494
Repayments of Long-term Debt	(825)	(12)	(112)
Dividends	(173)	(319)	(301)
Short-term borrowings, net	(179)	(552)	384
Short-term borrowings-affiliate,net	245	8	(4)
Contributions from parent	24	3	100
Net Cash Provided From Financing Activities	(113)	(872)	561
Net (Decrease) Increase in Cash and Cash Equivalents	(18)	231	34
Cash and Cash Equivalents, January 1	395	164	130
Cash and Cash Equivalents, December 31	377	395	164
Supplemental Cash Flow Information
Cash paid for-Interest (net of capitalized interest )	264	269	251
Cash paid for-Income taxes	3	47	289
Proceeds from Income Tax Refunds	216	145	189
Cash Flow, Noncash Investing and Financing Activities Disclosure
Accrued construction expenditures	69	99	95
Capital Lease Obligations Incurred	8	$ 8	$ 14
Proceeds from Contribution in Aid of Construction	$ 6

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parentheticals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash paid for interest, capitalized interest	$ 12	$ 18	$ 19
SCE&G
Cash paid for interest, capitalized interest	$ 9	$ 15	$ 18

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CONSOLIDATED STATEMENTS OF COMMON EQUITY - USD ($) shares in Millions, $ in Millions	Total	AOCI Attributable to Parent [Member]	SCE&G	SCEG excluding VIEs [Member]	SCEG and GENCO [Member]	Subsidiaries [Member] SCE&G
Common Stock, Value, Outstanding				$ 2,760
Stockholders' Equity Attributable to Noncontrolling Interest					$ 129
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			$ 5,151
Stockholders' Equity Attributable to Parent at Dec. 31, 2015	$ 5,443
Shares, Outstanding at Dec. 31, 2015	143			40
Stockholders' Equity before Treasury Stock at Dec. 31, 2015	$ 2,402
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2015	(53)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax at Dec. 31, 2015	(12)
Retained Earnings, Unappropriated at Dec. 31, 2015	3,118			$ 2,265
Treasury Stock, Value at Dec. 31, 2015	(12)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2015	(65)			(3)
Dividends, Common Stock	(329)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	17
Net Income (Loss) Attributable to Noncontrolling Interest			13		13
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			526
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent			0	0
Contributions from parent			100		0
Dividends			(305)	(297)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(8)
Other Comprehensive Income (Loss), Net of Tax	16		0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	4
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	(1)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	13
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Reclassified During Period, Net of Tax	0		0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	611		526	513
Proceeds from Contribution from Parent, net of return of Proceeds			100	100
Income Available to Common Shareholders	$ 595			$ 513
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 2.30
Shares, Outstanding at Dec. 31, 2016	143			40
Stockholders' Equity before Treasury Stock at Dec. 31, 2016	$ 2,402
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2016	(36)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax at Dec. 31, 2016	(13)
Retained Earnings, Unappropriated at Dec. 31, 2016	3,384			$ 2,481
Treasury Stock, Value at Dec. 31, 2016	(12)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2016	(49)			(3)
Stockholders' Equity Attributable to Parent at Dec. 31, 2016	5,725
Common Stock, Value, Outstanding				2,860
Stockholders' Equity Attributable to Noncontrolling Interest					134
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			5,472
AOCI before Tax, Attributable to Parent	(13)	$ 3
Dividends, Common Stock	(350)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(1)
Net Income (Loss) Attributable to Noncontrolling Interest			13		13
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			(172)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent			1	(1)
Contributions from parent			3		3
Dividends			(322)	(314)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(8)
Other Comprehensive Income (Loss), Net of Tax	(1)		(1)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(7)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	6
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Reclassified During Period, Net of Tax	0		0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(120)		(173)	(186)
Proceeds from Contribution from Parent, net of return of Proceeds			100	0
Income Available to Common Shareholders	$ (119)			$ (185)
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 2.45
Shares, Outstanding at Dec. 31, 2017	143			40
Stockholders' Equity before Treasury Stock at Dec. 31, 2017	$ 2,402
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2017	(37)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax at Dec. 31, 2017	(13)
Retained Earnings, Unappropriated at Dec. 31, 2017	2,915		1,982	$ 1,982
Treasury Stock, Value at Dec. 31, 2017	(12)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2017	(50)			(4)
Stockholders' Equity Attributable to Parent at Dec. 31, 2017	5,255		4,838
Common Stock, Value, Outstanding	2,390		2,860	2,860
Stockholders' Equity Attributable to Noncontrolling Interest			142		142
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			4,980
AOCI before Tax, Attributable to Parent	(6)	(7)
Dividends, Common Stock	(140)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	14
Net Income (Loss) Attributable to Noncontrolling Interest			25		25
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			(589)			$ (589)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent			(1)	1
Contributions from parent			24		24
Dividends			(101)	(89)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(12)
Other Comprehensive Income (Loss), Net of Tax	16		1
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(2)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	2
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	16
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Reclassified During Period, Net of Tax	2		0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(512)		(588)	(613)
treasury stock issued	(1)
Proceeds from Contribution from Parent, net of return of Proceeds	24			0
Income Available to Common Shareholders	$ (528)			$ (614)
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.98
Shares, Outstanding at Dec. 31, 2018	143			40
Stockholders' Equity before Treasury Stock at Dec. 31, 2018	$ 2,402
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2018	(23)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax at Dec. 31, 2018	(11)
Retained Earnings, Unappropriated at Dec. 31, 2018	2,247		1,279	$ 1,279
Treasury Stock, Value at Dec. 31, 2018	(13)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2018	(34)			(3)
Stockholders' Equity Attributable to Parent at Dec. 31, 2018	4,602		4,136
Common Stock, Value, Outstanding	2,389		2,860	$ 2,860
Stockholders' Equity Attributable to Noncontrolling Interest			179		$ 179
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			$ 4,315
AOCI before Tax, Attributable to Parent	$ (16)	$ 0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2018

Significant Accounting Policies

Significant Accounting Policies [Text Block]

   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Principles of Consolidation

Effective January 1, 2019, SCANA became a wholly-owned subsidiary of Dominion Energy under the terms of the Merger Agreement. See additional discussion in Note 2 and Note 11.

The Company

SCANA, a South Carolina corporation, is a holding company created in 1984. The Company primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina, and the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia.

The accompanying consolidated financial statements reflect the accounts of SCANA and the following wholly-owned subsidiaries.

Regulated businesses	Nonregulated businesses
South Carolina Electric & Gas Company	SCANA Energy Marketing, Inc.
South Carolina Fuel Company, Inc.	SCANA Services, Inc.
South Carolina Generating Company, Inc.	SCANA Corporate Security Services, Inc.
Public Service Company of North Carolina, Incorporated	SCANA Communications Holdings, Inc.

SCANA reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. Discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

Consolidated SCE&G

SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA. Consolidated SCE&G primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s 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, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $500 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

No estimate is made for legal costs expected to be incurred in connection with loss contingencies. Such costs are recorded when incurred.

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 AFC, 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.

AFC 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. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 7.7% for 2018, 5.6% for 2017, and 5.3% for 2016. Consolidated SCE&G calculated AFC using average composite rates of 7.0% for 2018, 3.9% for 2017, and 4.7% for 2016. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.

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 2018 composite weighted average depreciation rates for utility plant by function were as follows:

	The Company		Consolidated SCE&G
Generation	2.61	%	2.61	%
Transmission	2.47	%	2.74	%
Distribution	2.48	%	2.41	%
Storage	2.48	%	2.71	%
General and other	5.64	%	3.18	%

SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization 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 SCPSC 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.

SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2018, and 2017, SCE&G incurred $16.3 million and $26.1 million, respectively, for turbine maintenance.

Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 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 SCE&G was responsible totaled $28.6 million in 2018 and $23.2 million in 2017.

Goodwill

The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company has tested goodwill for impairment annually as of January 1, unless indicators, events or circumstances required interim testing to be performed. The Company performed its test on January 1, 2019 and intends to test goodwill annually on April 1, effective April 1, 2019. Under current accounting guidance, the Company may perform a qualitative assessment of impairment. Based on this assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to make a quantitative estimate of the fair value of the reporting unit and to compare that amount to its carrying value. If the Company is required to make a quantitative assessment or if it chooses to do so without first performing a qualitative one, and if the quantitative assessment indicates a carrying value in excess of fair value, an impairment charge would be required. Any such charge would be treated as an operating expense.

For each period presented, assets with a carrying value of $210 million for PSNC Energy (Gas Distribution segment), net of a writedown of $230 million taken in 2002, were classified as goodwill. The Company performed a quantitative assessment of goodwill in its evaluation as of January 1, 2019 and performed a qualitative assessment of goodwill in its evaluation as of January 1, 2018. No impairment of goodwill was required based on these evaluations.

Nuclear Decommissioning

Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $625.8 million, stated in 2018 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. 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 SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ($3.2 million pre-tax 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 Unit 1 on an after-tax basis.

Cash and Cash Equivalents

Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds. At December 31, 2018, cash and cash equivalents at the Company and Consolidated SCE&G included approximately $115.3 million held in escrow pending consummation of the merger with Dominion Energy and final approval of a legal settlement in the SCE&G Ratepayer Case. As such, the Company and Consolidated SCE&G did not consider these amounts to be restricted at December 31, 2018. See Claims and Litigation in Note 11 for additional discussion.

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 3. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $217.5 million at December 31, 2018 and $220.9 million at December 31, 2017 for the Company. Unbilled revenues totaled $129.3 million at December 31, 2018 and $140.3 million at December 31, 2017 for Consolidated SCE&G.

Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station.

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 SCPSC or NCUC, as applicable.

PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 46% and 39% of PSNC Energy’s natural gas inventory at December 31, 2018 and December 31, 2017, respectively, with a carrying value of $13.9 million and $11.5 million, respectively. Under the terms of this agreement, PSNC Energy receives storage asset management feesof which 75% are credited to customers. This agreement has been extended and expires October 31, 2020.

Income Taxes

SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 6 for a discussion of the impact of adjustments recorded in connection with enactment of the Tax Act.

Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA for all periods presented. Also, under provisions of an income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions.

Regulatory Assets and Regulatory Liabilities

The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods that differ from those in which the costs would be charged to expense, or record revenues in periods that differ from those in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified on the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively.

Debt Issuance Premiums, Discounts and Other Costs

Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred credits or debits and are amortized over the term of the replacement debt, also as interest charges.

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 and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense).

Revenue Recognition

Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed.

Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings.

SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews.

Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of operations. 

Earnings (Loss) Per Share

The Company computes basic earnings (loss) per share by dividing net income (loss) by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings (loss) per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.

New Accounting Matters

Recently Adopted

In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact or no significant impact on their respective financial statements except as indicated.

• Goodwill impairment guidance, issued in January 2017, removed Step 2 of the goodwill impairment test.

• Guidance for revenue arising from contracts with customers uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods were not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3.

• The required presentation of net periodic pension and postretirement benefit costs has been changed to distinguish between service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees. Non-service cost components are now excluded from operating income. This guidance has been applied retrospectively for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017 and 2016.

Increase (Decrease) Millions of dollars	The Company						Consolidated SCE&G
Year Ended December 31	2017			2016			2017			2016
Other operation and maintenance	$	(9	)	$	(14	)	$	(7	)	$	(12	)
Total Operating Expenses	(9		)	(14		)	(7		)	(12		)
Operating Income	9			14			7			12
Other Income (Expense), Net	(9		)	(14		)	(7		)	(12		)

In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost component, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs. Effective January 1, 2018, amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets.

• Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things.

• Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented.

• Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented.

Pending Adoption

The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below.

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 currently 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 is effective for the Company's and Consolidated SCE&G's interim and annual reporting periods beginning January 1, 2019. This revised accounting guidance will be adopted using a modified-retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Company and Consolidated SCE&G are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Company and Consolidated SCE&G will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. The Company and Consolidated SCE&G anticipate that the adoption of this guidance will result in approximately $30 million to $35 million and $15 million to $20 million, respectively, of offsetting right-of-use assets and liabilities added to their consolidated balance sheets for operating leases in effect at the adoption date. No material changes are expected to the Company's and Consolidated SCE&G's results of operations.

In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 and do not expect it to have a significant impact on their respective financial statements.

In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 on a prospective basis. Upon adoption, the Company and Consolidated SCE&G expect to record cumulative effect adjustments to retained earnings and AOCI in their statements of changes in common equity (in the amount of $8 million and $1 million at the Company and Consolidated SCE&G, respectively) and do not expect any other significant impact on their financial statements. The amounts to be reclassified reflect the impact of the reduction in the federal income tax rate arising from the Tax Act, and the related federal benefit of state income taxes, on the components of the Company’s and Consolidated SCE&G’s AOCI.

In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. A modified-retrospective approach is required upon adoption, whereby a cumulative-effect adjustment to retained earnings is made as of the beginning of the first reporting period in which the guidance is effective. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements.

In August 2018, the FASB issued accounting guidance to modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance must be applied retrospectively to all periods presented. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position.

SCE&G

Significant Accounting Policies

Significant Accounting Policies [Text Block]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Principles of Consolidation

Effective January 1, 2019, SCANA became a wholly-owned subsidiary of Dominion Energy under the terms of the Merger Agreement. See additional discussion in Note 2 and Note 11.

The Company

SCANA, a South Carolina corporation, is a holding company created in 1984. The Company primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina, and the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia.

The accompanying consolidated financial statements reflect the accounts of SCANA and the following wholly-owned subsidiaries.

Regulated businesses	Nonregulated businesses
South Carolina Electric & Gas Company	SCANA Energy Marketing, Inc.
South Carolina Fuel Company, Inc.	SCANA Services, Inc.
South Carolina Generating Company, Inc.	SCANA Corporate Security Services, Inc.
Public Service Company of North Carolina, Incorporated	SCANA Communications Holdings, Inc.

SCANA reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. Discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

Consolidated SCE&G

SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA. Consolidated SCE&G primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s 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, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $500 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

No estimate is made for legal costs expected to be incurred in connection with loss contingencies. Such costs are recorded when incurred.

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 AFC, 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.

AFC 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. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 7.7% for 2018, 5.6% for 2017, and 5.3% for 2016. Consolidated SCE&G calculated AFC using average composite rates of 7.0% for 2018, 3.9% for 2017, and 4.7% for 2016. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.

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 2018 composite weighted average depreciation rates for utility plant by function were as follows:

	The Company		Consolidated SCE&G
Generation	2.61	%	2.61	%
Transmission	2.47	%	2.74	%
Distribution	2.48	%	2.41	%
Storage	2.48	%	2.71	%
General and other	5.64	%	3.18	%

SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization 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 SCPSC 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.

SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2018, and 2017, SCE&G incurred $16.3 million and $26.1 million, respectively, for turbine maintenance.

Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 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 SCE&G was responsible totaled $28.6 million in 2018 and $23.2 million in 2017.

Goodwill

The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company has tested goodwill for impairment annually as of January 1, unless indicators, events or circumstances required interim testing to be performed. The Company performed its test on January 1, 2019 and intends to test goodwill annually on April 1, effective April 1, 2019. Under current accounting guidance, the Company may perform a qualitative assessment of impairment. Based on this assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to make a quantitative estimate of the fair value of the reporting unit and to compare that amount to its carrying value. If the Company is required to make a quantitative assessment or if it chooses to do so without first performing a qualitative one, and if the quantitative assessment indicates a carrying value in excess of fair value, an impairment charge would be required. Any such charge would be treated as an operating expense.

For each period presented, assets with a carrying value of $210 million for PSNC Energy (Gas Distribution segment), net of a writedown of $230 million taken in 2002, were classified as goodwill. The Company performed a quantitative assessment of goodwill in its evaluation as of January 1, 2019 and performed a qualitative assessment of goodwill in its evaluation as of January 1, 2018. No impairment of goodwill was required based on these evaluations.

Nuclear Decommissioning

Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $625.8 million, stated in 2018 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. 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 SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ($3.2 million pre-tax 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 Unit 1 on an after-tax basis.

Cash and Cash Equivalents

Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds. At December 31, 2018, cash and cash equivalents at the Company and Consolidated SCE&G included approximately $115.3 million held in escrow pending consummation of the merger with Dominion Energy and final approval of a legal settlement in the SCE&G Ratepayer Case. As such, the Company and Consolidated SCE&G did not consider these amounts to be restricted at December 31, 2018. See Claims and Litigation in Note 11 for additional discussion.

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 3. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $217.5 million at December 31, 2018 and $220.9 million at December 31, 2017 for the Company. Unbilled revenues totaled $129.3 million at December 31, 2018 and $140.3 million at December 31, 2017 for Consolidated SCE&G.

Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station.

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 SCPSC or NCUC, as applicable.

PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 46% and 39% of PSNC Energy’s natural gas inventory at December 31, 2018 and December 31, 2017, respectively, with a carrying value of $13.9 million and $11.5 million, respectively. Under the terms of this agreement, PSNC Energy receives storage asset management feesof which 75% are credited to customers. This agreement has been extended and expires October 31, 2020.

Income Taxes

SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 6 for a discussion of the impact of adjustments recorded in connection with enactment of the Tax Act.

Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA for all periods presented. Also, under provisions of an income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions.

Regulatory Assets and Regulatory Liabilities

The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods that differ from those in which the costs would be charged to expense, or record revenues in periods that differ from those in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified on the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively.

Debt Issuance Premiums, Discounts and Other Costs

Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred credits or debits and are amortized over the term of the replacement debt, also as interest charges.

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 and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense).

Revenue Recognition

Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed.

Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings.

SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews.

Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of operations. 

Earnings (Loss) Per Share

The Company computes basic earnings (loss) per share by dividing net income (loss) by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings (loss) per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.

New Accounting Matters

Recently Adopted

In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact or no significant impact on their respective financial statements except as indicated.

• Goodwill impairment guidance, issued in January 2017, removed Step 2 of the goodwill impairment test.

• Guidance for revenue arising from contracts with customers uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods were not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3.

• The required presentation of net periodic pension and postretirement benefit costs has been changed to distinguish between service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees. Non-service cost components are now excluded from operating income. This guidance has been applied retrospectively for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017 and 2016.

Increase (Decrease) Millions of dollars	The Company						Consolidated SCE&G
Year Ended December 31	2017			2016			2017			2016
Other operation and maintenance	$	(9	)	$	(14	)	$	(7	)	$	(12	)
Total Operating Expenses	(9		)	(14		)	(7		)	(12		)
Operating Income	9			14			7			12
Other Income (Expense), Net	(9		)	(14		)	(7		)	(12		)

In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost component, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs. Effective January 1, 2018, amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets.

• Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things.

• Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented.

• Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented.

Pending Adoption

The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below.

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 currently 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 is effective for the Company's and Consolidated SCE&G's interim and annual reporting periods beginning January 1, 2019. This revised accounting guidance will be adopted using a modified-retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Company and Consolidated SCE&G are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Company and Consolidated SCE&G will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. The Company and Consolidated SCE&G anticipate that the adoption of this guidance will result in approximately $30 million to $35 million and $15 million to $20 million, respectively, of offsetting right-of-use assets and liabilities added to their consolidated balance sheets for operating leases in effect at the adoption date. No material changes are expected to the Company's and Consolidated SCE&G's results of operations.

In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 and do not expect it to have a significant impact on their respective financial statements.

In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 on a prospective basis. Upon adoption, the Company and Consolidated SCE&G expect to record cumulative effect adjustments to retained earnings and AOCI in their statements of changes in common equity (in the amount of $8 million and $1 million at the Company and Consolidated SCE&G, respectively) and do not expect any other significant impact on their financial statements. The amounts to be reclassified reflect the impact of the reduction in the federal income tax rate arising from the Tax Act, and the related federal benefit of state income taxes, on the components of the Company’s and Consolidated SCE&G’s AOCI.

In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. A modified-retrospective approach is required upon adoption, whereby a cumulative-effect adjustment to retained earnings is made as of the beginning of the first reporting period in which the guidance is effective. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements.

In August 2018, the FASB issued accounting guidance to modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance must be applied retrospectively to all periods presented. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position.

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RATE AND OTHER REGULATORY MATTERS

12 Months Ended

Dec. 31, 2018

Rate Matters [Line Items]

Schedule of Regulatory Assets and Liabilities [Text Block]

   RATE AND OTHER REGULATORY MATTERS

Rate Matters

Tax Act Regulatory Proceedings

The Tax Act lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the SCPSC and NCUC have required SCE&G and PSNC Energy to track and defer impacts related to the Tax 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 Tax Act. Certain of these amounts are protected under normalization rules and will be amortized over the remaining regulatory life of the property, and certain of these amounts will be amortized to the benefit of customers, as instructed by regulators, which ranges from 5 years to 50 years.

As of December 31, 2018, SCE&G has recorded approximately $73.7 million as Revenue subject to refund and approximately $3.7 million as Regulatory liabilities on the consolidated balance sheet for the Company and Consolidated SCE&G, and PSNC Energy has recorded approximately $15.4 million of such deferrals within Regulatory liabilities on the consolidated balance sheet for the Company. These amounts were collected through customer rates in 2018 and include the accrual of estimated carrying costs. In addition, the Company and Consolidated SCE&G have recorded amounts related to excess deferred income taxes arising from the Tax Act within Regulatory liabilities. For a discussion of related actions taken by the SCPSC and NCUC, see Electric - Other, Gas - SCE&G, and Gas - PSNC Energy below.

Electric - BLRA and Merger Approval Order

In 2016, the SCPSC approved revised rates under the BLRA to incorporate financing cost of SCE&G's incremental construction work in progress incurred for the Nuclear Project. Rate adjustments resulted in approximately $64.4 million in additional revenue on an annual basis and were effective for bills rendered on and after November 27, 2016. Such rate adjustments were based on SCE&G's updated cost of debt and capital structure and on an allowed ROE of 10.5% applied prospectively for purposes of calculating revised rates under the BLRA on and after January 1, 2016. No revised rates filings were pursued after this 2016 approval.

In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for Unit 2 and Unit 3 which had been developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, the ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option included in that October 2015 contract amendment. By order dated February 28, 2017, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement, and that denial was not appealed.

On July 2 and 3, 2018, the SCPSC issued orders implementing a legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from customers under the BLRA. These orders reduced the portion of SCE&G's retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer's bill to approximately 3.2%, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. These lower rates remained in effect until February 2019 pursuant to the Merger Approval Order.

On December 21, 2018, the SCPSC issued the Merger Approval Order. The order adopted Dominion Energy's Plan-B Levelized Customer Benefits Plan whereby the average bill for an SCE&G residential electric customer would approximate that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the SCPSC retroactive to April 1, 2018. The Merger Approval Order established an allowed ROE of 9.9% on unrecovered Nuclear Project costs, and resulted in the following findings and conditions:

• No capital costs related to the Nuclear Project incurred after March 12, 2015 will be recoverable by SCE&G.

• SCE&G will provide refunds and restitution to customers from prior years' revenues totaling an aggregate $2.039 billion, comprised of $1.032 billion to be credited to customers over 20 years and $1.007 billion credited to customers over approximately 11 years.

• Except for rate adjustments for fuel and environmental costs, demand side management costs, and other rates routinely adjusted on an annual or biannual basis, SCE&G will freeze retail electric base rates at current levels until January 1, 2021.

• SCE&G's natural gas customers will receive a refund totaling $2.45 million in 2019, 2020 and 2021 combined.

• Corporate giving will increase above historical levels by $1 million per year for at least five years.

• SCE&G will not seek to pass on to ratepayers its initial capital investment in CEC, a 540-MW combined-cycle natural gas-fired generating facility, and will not seek to pass on to ratepayers any acquisition premium costs, transition costs, or transaction cost associated with the merger.

Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. On February 12, 2019, the SCPSC issued a ruling (1) finding that SCE&G was imprudent in its actions by not disclosing material information to the ORS and the SCPSC, and (2) denying the petitions for rehearing or reconsideration as to other issues raised in the various petitions. The Merger Approval Order and the ruling are subject to appeal by various parties. The Company and Consolidated SCE&G cannot predict the outcome of these matters. See also Note 11.

Electric - Cost of Fuel

SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G.

By order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G reduced the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G also began to recover projected DER program costs of approximately $6.9 million beginning with the first billing cycle of May 2016.

By order dated April 27, 2017, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component to produce a projected under recovery of $61.0 million over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately $16.5 million. Additionally, deferral of carrying costs would be allowed for base fuel component under-collected balances as they occurred.

On April 25, 2018, the SCPSC approved SCE&G’s proposal to increase the total fuel cost component of retail electric rates. Specifically, the SCPSC approved an increase to certain environmental, avoided capacity and DER program cost components and SCE&G’s agreement to maintain its base fuel component to produce a projected under-recovered balance of approximately $1.3 million at the end of the 12-month period beginning with the first billing cycle of May 2018. This projected under-recovered balance includes the effect of offsetting fuel cost recovery with gains realized from the settlement of certain interest rate derivatives in 2018. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2018, projected DER program costs of approximately $29.3 million. Petitions for rehearing and reconsideration were filed by various parties, and on October 30, 2018, the SCPSC issued an order granting one such petition related to SCE&G 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 SCE&G is required to pay to solar energy developers, and these appeals are pending. The Company and Consolidated SCE&G cannot predict the outcome of these matters.

On February 8, 2019, SCE&G filed with the SCPSC a proposal to decrease the total fuel cost component of retail electric rates. In the filing, SCE&G proposed to maintain its base fuel component at the current level to produce a projected under-recovered balance of approximately $35.4 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. SCE&G also proposed to reduce its variable environmental component and maintain or reduce its DER components.  A public hearing on this matter is scheduled to be held in April 2019.

Electric - Base Rates

Pursuant to an SCPSC order, SCE&G removed from rate base certain deferred income tax assets arising from capital expenditures related to Unit 2 and Unit 3 and accrued carrying costs on those amounts during periods in which they were not included in rate base. Such carrying costs were determined at SCE&G’s weighted average long-term debt borrowing rate and were recorded as a regulatory asset and other income. Carrying costs totaled $18.8 million during 2017 and $14.0 million during 2016. As part of the Nuclear Project impairment loss described in Note 11, accumulated carrying costs related to these deferred income tax assets totaling $51.0 million were written off in 2017.

Electric - Other

The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues (both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below:

Year	Effective	Amount
2018	First billing cycle of May	$33.0 million
2017	First billing cycle of May	$37.0 million
2016	First billing cycle of May	$37.6 million

In January 2019, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved the filing would allow recovery of approximately $30.3 million of costs and net lost revenues associated with DSM Programs, along with an incentive to invest in such programs.

SCE&G utilizes a pension costs rider approved by the SCPSC which is designed to allow recovery of projected pension costs, including under-collected balances or net of over-collected balances, as applicable. The rider is typically reviewed for adjustment every 12 months with any resulting increase or decrease going into effect beginning with the first billing cycle in May. In 2017, this rider was adjusted to decrease annual revenue by approximately $11.9 million. No adjustment was made in 2018. No adjustment has been proposed in 2019.

As part of the Merger Approval Order, the SCPSC approved refunds of approximately $100 million by SCE&G for the impact of the lower federal tax rate resulting from the Tax Act. The refunds include amounts which had been collected through customer rates in 2018 and January 2019 and also include the effects of the amortization of certain excess deferred taxes during the same period. At December 31, 2018, amounts to be refunded to electric customers totaled approximately $91 million, and were comprised of approximately $70 million included within Revenue subject to refund and approximately $21 million included within Regulatory liabilities. These refunds have been included in bills rendered on and after the first billing cycle of February 2019. In addition, the SCPSC 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 Tax Act will be amortized to the benefit of customers. This tax rider is expected to reduce base rates to customers by approximately $67 million in each of 2019 and 2020, effective with the first billing cycle of February 2019. Unamortized excess deferred income taxes that remain at the end of 2020 will be considered in future rate proceedings.

Gas - SCE&G

The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: 

Year	Action			Amount
2018	4.6	%	Decrease	$19.7 million	*
2017	2.2	%	Increase	$8.6 million
2016	1.2	%	Increase	$4.1 million

*Includes the impact of the lower federal corporate tax rate resulting from the Tax Act. The SCPSC also approved revised rate schedules for natural gas service that include a rider to refund certain amounts previously collected from customers for SCE&G's income taxes.

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G'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 SCPSC.

Gas - PSNC Energy

PSNC Energy's Rider D rate mechanism allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales.

PSNC Energy establishes rates using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.

On October 28, 2016, the NCUC granted PSNC Energy a net annual increase of approximately $19.1 million, or 4.39%, in rates and charges to customers, and set PSNC Energy's authorized ROE at 9.7%. In addition, the NCUC has authorized PSNC Energy to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy files biannual applications to adjust its rates for this purpose. The NCUC has approved those applications for the incremental increase to annual revenue requirements, as follows:

Rates Effective	2018	2017
March 1	$14.7 million	$1.9 million
September 1	$1.1 million	$0.7 million

On February 15, 2019, PSNC Energy submitted its biannual application to adjust rates associated with its pipeline integrity tracker. As approved by the NCUC, the filing increases PSNC Energy's allowed recovery by approximately $1.7 million effective March 1, 2019.    

On November 19, 2018, the NCUC issued an order approving the SCANA Combination subject to a stipulation agreement with the following provisions: (1) customer bill credits of $1.25 million in each of January 2019, 2020 and 2021; (2) a rate moratorium until November 1, 2021 other than for rate adjustments pursuant to the CUT, the Integrity Management Tracker and the PGA; and (3) an agreement that direct merger-related expenses will be excluded from PSNC Energy regulated expenses for ratemaking purposes.

On December 17, 2018, the NCUC issued an order approving PSNC Energy's proposed adjustments to customer rates to reflect the reduction in the federal corporate tax rate arising from the Tax Act. These lower rates became effective for service rendered on and after January 1, 2019. The impact of the lower tax rate collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC Energy's next general rate case proceeding or in three years, whichever is sooner (i.e., no later than October 25, 2021). The reduction in the federal corporate tax rate and its impact on PSNC Energy's various rate riders will be addressed in future proceedings related to those riders.

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, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Except for certain unrecovered nuclear project costs and other unrecovered plant, 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.

	The Company				Consolidated SCE&G
	December 31,				December 31,
Millions of dollars	2018		2017		2018		2017
Regulatory Assets:
Unrecovered Nuclear Project costs	$	2,768	3,976		$	2,768	3,976
AROs and related funding	406		434		380		410
Deferred employee benefit plan costs	302		305		272		273
Deferred losses on interest rate derivatives	448		456		448		456
Other unrecovered plant	93		105		93		105
DSM Programs	65		59		65		59
Pipeline integrity management costs	73		51		9		8
Environmental remediation costs	27		30		24		25
Deferred storm damage costs	35		24		35		24
Deferred transmission operating costs	15		—		15		—
Other	148		140		147		140
Total Regulatory Assets	$	4,380	$	5,580	$	4,256	$	5,476

Regulatory Liabilities:
Monetization of guaranty settlement	$	1,098	1,095		$	1,098	1,095
Accumulated deferred income taxes	814		1,076		659		914
Asset removal costs	779		757		541		527
Deferred gains on interest rate derivatives	77		131		77		131
Other	21		—		5		—
Total Regulatory Liabilities	$	2,789	$	3,059	$	2,380	$	2,667

The carrying amount of the regulatory asset for unrecovered Nuclear Project costs has been recorded based on such amount not being probable of loss in accordance with the accounting guidance on abandonments, whereas the other regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under applicable GAAP for regulated operations. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include 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 further discussed above and in Note 11. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts embodied in rate orders or applicable state law. The costs are currently not being recovered but are expected to be recovered through rates in future periods. In the future, as a result of deregulation, changes in state law, other changes in the regulatory environment or changes in accounting requirements or other adverse legislative or regulatory developments, the Company or Consolidated SCE&G could be required to write off all or a portion of its regulatory assets and liabilities. Such an event could have a material effect on the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded.

Unrecovered Nuclear Project costs represents expenditures by SCE&G that have been reclassified from construction work in progress and, pursuant to the Merger Approval Order and subsequent SCANA Combination, are to be recovered over a 20-year period ending in 2039. In 2017, such amounts were recorded pending a final determination by the SCPSC. See Note 11 for a discussion of impairment charges related to the Nuclear Project.

AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 106 years.

Employee benefit plan costs of the regulated utilities 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 SCPSC regulatory orders. SCE&G recovers deferred pension costs through utility rates of approximately $2 million annually for electric operations, which will end in 2044, and approximately $1 million annually for gas operations, which will end in 2027. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees up to approximately 11 years.

Deferred losses or gains on interest rate derivatives represent (i) the effective portions of 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. Such deferred amounts are expected to be amortized to interest expense over the lives of the underlying debt which, with respect to (i), is through 2043, and with respect to (ii), is through 2065.

Other unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represent SCE&G's deferred costs associated with electric demand reduction programs, and such deferred costs are being recovered over approximately five years through an approved rate rider. 

Pipeline integrity management costs represent operating costs expended to comply with federal regulatory requirements related to natural gas pipelines. PSNC Energy is recovering costs totaling $4.1 million annually through 2021. PSNC Energy is continuing to defer pipeline integrity costs, and as of December 31, 2018 costs of $51.3 million have been deferred pending future approval of rate recovery. Effective November 2018, SCE&G began amortizing deferred pipeline integrity costs at an annual rate of $3.2 million. Prior to November 2018, such costs were amortized at an annual rate of $1.9 million annually.

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy. SCE&G's remediation costs are expected to be recovered over periods of up to approximately 16 years, and PSNC Energy's remediation costs of $3.8 million are being recovered over a period that will end in 2021.

Deferred storm damage costs represent storm restoration costs for which SCE&G expects to receive future recovery through customer rates.

Deferred transmission operating costs include deferred depreciation and property taxes associated with certain transmission assets for which SCE&G expects recovery from customers through future rates. See also Note 11.

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

Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement. In accordance with the Merger Approval Order, this balance, net of amounts that may be required to satisfy liens described in Note 11, will be refunded to electric customers over a period ending in 2039.

Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the Tax 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 approximately 85 years). See also Note 6.

Asset removal costs represent estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.

SCE&G

Rate Matters [Line Items]

Schedule of Regulatory Assets and Liabilities [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Tax Act Regulatory Proceedings

The Tax Act lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the SCPSC and NCUC have required SCE&G and PSNC Energy to track and defer impacts related to the Tax 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 Tax Act. Certain of these amounts are protected under normalization rules and will be amortized over the remaining regulatory life of the property, and certain of these amounts will be amortized to the benefit of customers, as instructed by regulators, which ranges from 5 years to 50 years.

As of December 31, 2018, SCE&G has recorded approximately $73.7 million as Revenue subject to refund and approximately $3.7 million as Regulatory liabilities on the consolidated balance sheet for the Company and Consolidated SCE&G, and PSNC Energy has recorded approximately $15.4 million of such deferrals within Regulatory liabilities on the consolidated balance sheet for the Company. These amounts were collected through customer rates in 2018 and include the accrual of estimated carrying costs. In addition, the Company and Consolidated SCE&G have recorded amounts related to excess deferred income taxes arising from the Tax Act within Regulatory liabilities. For a discussion of related actions taken by the SCPSC and NCUC, see Electric - Other, Gas - SCE&G, and Gas - PSNC Energy below.

Electric - BLRA and Merger Approval Order

In 2016, the SCPSC approved revised rates under the BLRA to incorporate financing cost of SCE&G's incremental construction work in progress incurred for the Nuclear Project. Rate adjustments resulted in approximately $64.4 million in additional revenue on an annual basis and were effective for bills rendered on and after November 27, 2016. Such rate adjustments were based on SCE&G's updated cost of debt and capital structure and on an allowed ROE of 10.5% applied prospectively for purposes of calculating revised rates under the BLRA on and after January 1, 2016. No revised rates filings were pursued after this 2016 approval.

In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for Unit 2 and Unit 3 which had been developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, the ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option included in that October 2015 contract amendment. By order dated February 28, 2017, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement, and that denial was not appealed.

On July 2 and 3, 2018, the SCPSC issued orders implementing a legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from customers under the BLRA. These orders reduced the portion of SCE&G's retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer's bill to approximately 3.2%, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. These lower rates remained in effect until February 2019 pursuant to the Merger Approval Order.

On December 21, 2018, the SCPSC issued the Merger Approval Order. The order adopted Dominion Energy's Plan-B Levelized Customer Benefits Plan whereby the average bill for an SCE&G residential electric customer would approximate that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the SCPSC retroactive to April 1, 2018. The Merger Approval Order established an allowed ROE of 9.9% on unrecovered Nuclear Project costs, and resulted in the following findings and conditions:

• No capital costs related to the Nuclear Project incurred after March 12, 2015 will be recoverable by SCE&G.

• SCE&G will provide refunds and restitution to customers from prior years' revenues totaling an aggregate $2.039 billion, comprised of $1.032 billion to be credited to customers over 20 years and $1.007 billion credited to customers over approximately 11 years.

• Except for rate adjustments for fuel and environmental costs, demand side management costs, and other rates routinely adjusted on an annual or biannual basis, SCE&G will freeze retail electric base rates at current levels until January 1, 2021.

• SCE&G's natural gas customers will receive a refund totaling $2.45 million in 2019, 2020 and 2021 combined.

• Corporate giving will increase above historical levels by $1 million per year for at least five years.

• SCE&G will not seek to pass on to ratepayers its initial capital investment in CEC, a 540-MW combined-cycle natural gas-fired generating facility, and will not seek to pass on to ratepayers any acquisition premium costs, transition costs, or transaction cost associated with the merger.

Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. On February 12, 2019, the SCPSC issued a ruling (1) finding that SCE&G was imprudent in its actions by not disclosing material information to the ORS and the SCPSC, and (2) denying the petitions for rehearing or reconsideration as to other issues raised in the various petitions. The Merger Approval Order and the ruling are subject to appeal by various parties. The Company and Consolidated SCE&G cannot predict the outcome of these matters. See also Note 11.

Electric - Cost of Fuel

SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G.

By order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G reduced the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G also began to recover projected DER program costs of approximately $6.9 million beginning with the first billing cycle of May 2016.

By order dated April 27, 2017, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component to produce a projected under recovery of $61.0 million over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately $16.5 million. Additionally, deferral of carrying costs would be allowed for base fuel component under-collected balances as they occurred.

On April 25, 2018, the SCPSC approved SCE&G’s proposal to increase the total fuel cost component of retail electric rates. Specifically, the SCPSC approved an increase to certain environmental, avoided capacity and DER program cost components and SCE&G’s agreement to maintain its base fuel component to produce a projected under-recovered balance of approximately $1.3 million at the end of the 12-month period beginning with the first billing cycle of May 2018. This projected under-recovered balance includes the effect of offsetting fuel cost recovery with gains realized from the settlement of certain interest rate derivatives in 2018. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2018, projected DER program costs of approximately $29.3 million. Petitions for rehearing and reconsideration were filed by various parties, and on October 30, 2018, the SCPSC issued an order granting one such petition related to SCE&G 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 SCE&G is required to pay to solar energy developers, and these appeals are pending. The Company and Consolidated SCE&G cannot predict the outcome of these matters.

On February 8, 2019, SCE&G filed with the SCPSC a proposal to decrease the total fuel cost component of retail electric rates. In the filing, SCE&G proposed to maintain its base fuel component at the current level to produce a projected under-recovered balance of approximately $35.4 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. SCE&G also proposed to reduce its variable environmental component and maintain or reduce its DER components.  A public hearing on this matter is scheduled to be held in April 2019.

Electric - Base Rates

Pursuant to an SCPSC order, SCE&G removed from rate base certain deferred income tax assets arising from capital expenditures related to Unit 2 and Unit 3 and accrued carrying costs on those amounts during periods in which they were not included in rate base. Such carrying costs were determined at SCE&G’s weighted average long-term debt borrowing rate and were recorded as a regulatory asset and other income. Carrying costs totaled $18.8 million during 2017 and $14.0 million during 2016. As part of the Nuclear Project impairment loss described in Note 11, accumulated carrying costs related to these deferred income tax assets totaling $51.0 million were written off in 2017.

Electric - Other

The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues (both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below:

Year	Effective	Amount
2018	First billing cycle of May	$33.0 million
2017	First billing cycle of May	$37.0 million
2016	First billing cycle of May	$37.6 million

In January 2019, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved the filing would allow recovery of approximately $30.3 million of costs and net lost revenues associated with DSM Programs, along with an incentive to invest in such programs.

SCE&G utilizes a pension costs rider approved by the SCPSC which is designed to allow recovery of projected pension costs, including under-collected balances or net of over-collected balances, as applicable. The rider is typically reviewed for adjustment every 12 months with any resulting increase or decrease going into effect beginning with the first billing cycle in May. In 2017, this rider was adjusted to decrease annual revenue by approximately $11.9 million. No adjustment was made in 2018. No adjustment has been proposed in 2019.

As part of the Merger Approval Order, the SCPSC approved refunds of approximately $100 million by SCE&G for the impact of the lower federal tax rate resulting from the Tax Act. The refunds include amounts which had been collected through customer rates in 2018 and January 2019 and also include the effects of the amortization of certain excess deferred taxes during the same period. At December 31, 2018, amounts to be refunded to electric customers totaled approximately $91 million, and were comprised of approximately $70 million included within Revenue subject to refund and approximately $21 million included within Regulatory liabilities. These refunds have been included in bills rendered on and after the first billing cycle of February 2019. In addition, the SCPSC 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 Tax Act will be amortized to the benefit of customers. This tax rider is expected to reduce base rates to customers by approximately $67 million in each of 2019 and 2020, effective with the first billing cycle of February 2019. Unamortized excess deferred income taxes that remain at the end of 2020 will be considered in future rate proceedings.

Gas - SCE&G

The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: 

Year	Action			Amount
2018	4.6	%	Decrease	$19.7 million	*
2017	2.2	%	Increase	$8.6 million
2016	1.2	%	Increase	$4.1 million

*Includes the impact of the lower federal corporate tax rate resulting from the Tax Act. The SCPSC also approved revised rate schedules for natural gas service that include a rider to refund certain amounts previously collected from customers for SCE&G's income taxes.

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G'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 SCPSC.

Gas - PSNC Energy

PSNC Energy's Rider D rate mechanism allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales.

PSNC Energy establishes rates using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.

On October 28, 2016, the NCUC granted PSNC Energy a net annual increase of approximately $19.1 million, or 4.39%, in rates and charges to customers, and set PSNC Energy's authorized ROE at 9.7%. In addition, the NCUC has authorized PSNC Energy to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy files biannual applications to adjust its rates for this purpose. The NCUC has approved those applications for the incremental increase to annual revenue requirements, as follows:

Rates Effective	2018	2017
March 1	$14.7 million	$1.9 million
September 1	$1.1 million	$0.7 million

On February 15, 2019, PSNC Energy submitted its biannual application to adjust rates associated with its pipeline integrity tracker. As approved by the NCUC, the filing increases PSNC Energy's allowed recovery by approximately $1.7 million effective March 1, 2019.    

On November 19, 2018, the NCUC issued an order approving the SCANA Combination subject to a stipulation agreement with the following provisions: (1) customer bill credits of $1.25 million in each of January 2019, 2020 and 2021; (2) a rate moratorium until November 1, 2021 other than for rate adjustments pursuant to the CUT, the Integrity Management Tracker and the PGA; and (3) an agreement that direct merger-related expenses will be excluded from PSNC Energy regulated expenses for ratemaking purposes.

On December 17, 2018, the NCUC issued an order approving PSNC Energy's proposed adjustments to customer rates to reflect the reduction in the federal corporate tax rate arising from the Tax Act. These lower rates became effective for service rendered on and after January 1, 2019. The impact of the lower tax rate collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC Energy's next general rate case proceeding or in three years, whichever is sooner (i.e., no later than October 25, 2021). The reduction in the federal corporate tax rate and its impact on PSNC Energy's various rate riders will be addressed in future proceedings related to those riders.

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, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Except for certain unrecovered nuclear project costs and other unrecovered plant, 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.

	The Company				Consolidated SCE&G
	December 31,				December 31,
Millions of dollars	2018		2017		2018		2017
Regulatory Assets:
Unrecovered Nuclear Project costs	$	2,768	3,976		$	2,768	3,976
AROs and related funding	406		434		380		410
Deferred employee benefit plan costs	302		305		272		273
Deferred losses on interest rate derivatives	448		456		448		456
Other unrecovered plant	93		105		93		105
DSM Programs	65		59		65		59
Pipeline integrity management costs	73		51		9		8
Environmental remediation costs	27		30		24		25
Deferred storm damage costs	35		24		35		24
Deferred transmission operating costs	15		—		15		—
Other	148		140		147		140
Total Regulatory Assets	$	4,380	$	5,580	$	4,256	$	5,476

Regulatory Liabilities:
Monetization of guaranty settlement	$	1,098	1,095		$	1,098	1,095
Accumulated deferred income taxes	814		1,076		659		914
Asset removal costs	779		757		541		527
Deferred gains on interest rate derivatives	77		131		77		131
Other	21		—		5		—
Total Regulatory Liabilities	$	2,789	$	3,059	$	2,380	$	2,667

The carrying amount of the regulatory asset for unrecovered Nuclear Project costs has been recorded based on such amount not being probable of loss in accordance with the accounting guidance on abandonments, whereas the other regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under applicable GAAP for regulated operations. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include 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 further discussed above and in Note 11. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts embodied in rate orders or applicable state law. The costs are currently not being recovered but are expected to be recovered through rates in future periods. In the future, as a result of deregulation, changes in state law, other changes in the regulatory environment or changes in accounting requirements or other adverse legislative or regulatory developments, the Company or Consolidated SCE&G could be required to write off all or a portion of its regulatory assets and liabilities. Such an event could have a material effect on the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded.

Unrecovered Nuclear Project costs represents expenditures by SCE&G that have been reclassified from construction work in progress and, pursuant to the Merger Approval Order and subsequent SCANA Combination, are to be recovered over a 20-year period ending in 2039. In 2017, such amounts were recorded pending a final determination by the SCPSC. See Note 11 for a discussion of impairment charges related to the Nuclear Project.

AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 106 years.

Employee benefit plan costs of the regulated utilities 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 SCPSC regulatory orders. SCE&G recovers deferred pension costs through utility rates of approximately $2 million annually for electric operations, which will end in 2044, and approximately $1 million annually for gas operations, which will end in 2027. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees up to approximately 11 years.

Deferred losses or gains on interest rate derivatives represent (i) the effective portions of 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. Such deferred amounts are expected to be amortized to interest expense over the lives of the underlying debt which, with respect to (i), is through 2043, and with respect to (ii), is through 2065.

Other unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represent SCE&G's deferred costs associated with electric demand reduction programs, and such deferred costs are being recovered over approximately five years through an approved rate rider. 

Pipeline integrity management costs represent operating costs expended to comply with federal regulatory requirements related to natural gas pipelines. PSNC Energy is recovering costs totaling $4.1 million annually through 2021. PSNC Energy is continuing to defer pipeline integrity costs, and as of December 31, 2018 costs of $51.3 million have been deferred pending future approval of rate recovery. Effective November 2018, SCE&G began amortizing deferred pipeline integrity costs at an annual rate of $3.2 million. Prior to November 2018, such costs were amortized at an annual rate of $1.9 million annually.

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy. SCE&G's remediation costs are expected to be recovered over periods of up to approximately 16 years, and PSNC Energy's remediation costs of $3.8 million are being recovered over a period that will end in 2021.

Deferred storm damage costs represent storm restoration costs for which SCE&G expects to receive future recovery through customer rates.

Deferred transmission operating costs include deferred depreciation and property taxes associated with certain transmission assets for which SCE&G expects recovery from customers through future rates. See also Note 11.

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

Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement. In accordance with the Merger Approval Order, this balance, net of amounts that may be required to satisfy liens described in Note 11, will be refunded to electric customers over a period ending in 2039.

Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the Tax 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 approximately 85 years). See also Note 6.

Asset removal costs represent estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.

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REVENUE RECOGNITION (Notes)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Text Block]

REVENUE RECOGNITION

Identifying Revenue Streams and Related Performance Obligations

Operating Revenues

Operating revenues arise primarily from the sale and transmission of electricity and the sale and transportation of natural gas. Electric and Gas regulated revenues consist primarily of retail sales to residential, commercial and industrial customers under various tariff rates approved by state regulatory commissions. These tariff rates generally include charges for the energy consumed and a standard basic facilities or demand charge designed to recover certain fixed costs incurred to provide service to the customer. Tariff rates also include commission-approved regulatory mechanisms in the form of adjustments or riders, such as for weather normalization, fuel and environmental cost recovery, energy conservation programs, interruptible service and real time pricing provisions, among others. Electric revenues also include wholesale sales and transmission service, primarily to municipal customers and other service providers, under contracts or tariffs approved by the FERC.

Gas nonregulated revenues arise from natural gas sales at market-based rates. Such sales to residential and certain commercial customers include charges for natural gas delivered, at either variable or fixed prices, together with any applicable customer service charges, charges originating from an interstate pipeline company, and other incidental charges. The Company has determined that its gas marketing subsidiary serves as an agent for distribution services provided by a nonaffiliated company in its retail market. Accordingly, the pass-through charges to customers related to such services are not considered revenues. Sales to other commercial and to industrial customers include commodity and transportation charges for natural gas delivered at contracted rates, together with applicable fees for storage, injection, demand, and charges originating from one or more interstate pipeline companies.

Performance obligations which have not been satisfied by the Company or Consolidated SCE&G 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 the Company and Consolidated SCE&G for these charges is equal to the amount of consideration they have a right to invoice and corresponds directly to the value transferred to the customer. As a result, amounts related to performance obligations that have not been fully satisfied are not disclosed.

Contracts governing the transactions above do not have a significant financing component. Also, due to the nature of the commodities underlying these transactions, no performance obligations arise for returns, refunds or warranties. In addition, taxes billed to customers are excluded from the transaction price. Such amounts are recorded as liabilities until they are remitted to the respective taxing authority and are not included in revenues or expenses in the statements of operations.

Non-Operating Revenues

Non-operating revenues are derived from the sale of appliances and water heaters, as well as from contracts covering the repair of certain appliances, wiring, plumbing and similar systems and fees received for such repairs from customers not under a repair contract. In addition, the portion of fees received under asset management agreements that regulators have recognized to be incentives for the Company and Consolidated SCE&G to engage in such transactions is recorded as non-operating revenues.

Revenues from sales are recorded when the appliance or water heater is delivered to the customer. Repair contract coverage fees are recorded when invoiced, generally on a monthly basis in advance of the period of coverage. Additional charges for service calls and non-covered repairs are billed and collected at the time service is rendered. Revenues from asset management agreements are recorded when the related fixed monthly amounts are due, which corresponds to timing of the value received by the customer.

The point at which the customer controls the use of a purchased product or has obtained substantially all of the benefits from repair services, corresponds to when revenues are recorded and performance obligations are fulfilled. Contract assets arising from invoicing repair contract fees in advance of the coverage period are not material. Income earned from financing sales of appliances and other products is recorded within interest income. Any performance obligations arising from returns, refunds or warranties are not material.

Non-operating revenues also arise from sources unrelated to contracts with customers, such as carrying costs recorded on certain regulatory assets, gains from property sales and income from rentals and from equity method investments, among others. In 2018, such amounts include gains realized upon the settlement of certain interest rate swaps (see Note 15). Such revenues are outside the scope of revenues from contracts with customers.

Non-operating revenues are further described in Note 15. Such revenues arising from contracts with customers were not material for any period presented, and accordingly, detailed disclosures regarding these revenues are not provided.

Significant Judgments and Estimates

Electricity and natural gas are sold and delivered to the customer for immediate consumption and the customer controls the use of, and obtains substantially all of the benefits from, the energy and related services as they are delivered. As such, the related performance obligations are satisfied over time and revenue is recognized over the same period. The Company and Consolidated SCE&G have determined that their right to consideration from a customer directly corresponds to the value of the performance completed at the date each customer invoice is rendered. As a result, the Company and Consolidated SCE&G recognize revenue in the amounts for which they have a right to invoice. This includes estimated amounts unbilled at a balance sheet date, but which are to be invoiced in the normal cycle.

Regulatory mechanisms exist within electric and gas tariffs or orders from regulators that result in adjustments to customer bills. These regulatory mechanisms are designed:

• To recover costs related to fuel, pension, pipeline integrity and energy conservation, among others;

• To recover carrying costs associated with debt-based financing;

• To replace revenues lost as a result of the utility implementing DER programs and DSM Programs; and

• For gas revenues, to achieve weather normalization or to decouple gas revenues from weather and other factors through the WNA at SCE&G or the CUT at PSNC Energy.

Recovery of deferred costs and carrying costs and the replacement of lost revenues are components of approved tariffs, and therefore, adjustments to customer bills occur as electricity or natural gas is sold and delivered to the customer. As such, the Company and Consolidated SCE&G have concluded that performance obligations related to these adjustments are not capable of being distinct from the underlying tariff based sales. Accordingly, revenues arising from these adjustments are recorded within Operating Revenues - Electric or Gas - regulated on the statements of operations, consistent with revenues from underlying tariff based sales.

Adjustments for SCE&G’s WNA increase gas customer bills when weather is milder than normal and decrease gas customer bills when weather is colder than normal. These adjustments are made during the same period that the underlying natural gas is sold and delivered to the customer, and the performance obligations associated with these adjustments are not capable of being distinct from tariff based sales. Such adjustments are recorded within Operating Revenues - Gas - regulated on the statements of operations. When weather is significantly milder than normal, SCE&G limits such adjustments on a gas customer’s bill to an amount that would be added if weather were 50% milder than normal. Adjustments exceeding this limit, though still recorded as operating revenue, are deferred within regulatory assets until customers are subsequently billed for the excess with the approval of the SCPSC.

PSNC Energy’s CUT is a decoupling mechanism that adjusts bills for residential and commercial customers based on per customer average consumption. When average consumption exceeds actual usage, PSNC Energy records increased revenue associated with this undercollection and defers it within regulatory assets. Likewise, when actual usage exceeds average consumption, a decrement to revenue associated with this overcollection is recorded and deferred within regulatory liabilities. PSNC Energy’s tariff based rates are adjusted semiannually, with the approval of the NCUC, to collect or refund these deferred amounts over the subsequent 12 month period.

Amounts deferred for the WNA and the CUT arise under specific arrangements with regulators rather than customers. As a result, the Company and Consolidated SCE&G have concluded that these arrangements represent alternative revenue programs. Revenue from alternative revenue programs is included within Operating Revenues - Gas - regulated on the statements of operations in the month such adjustments are deferred within regulatory accounts and is shown as Other operating revenues when disaggregated in the table below. As permitted, the Company and Consolidated SCE&G have elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues.

Disaggregation of Revenues

The impact of several factors on the amount, timing and uncertainty of operating revenues and cash flows can vary significantly by customer class. For electric revenues and nonregulated gas revenues, which do not have weather normalization mechanisms in place, weather and conservation measures on energy usage typically affect residential and commercial customers to a greater degree than other customer classes. For utilities, revenue requirements result in increases or decreases in tariff rates approved by regulatory bodies and often vary by customer class. Also, certain cost recovery and other mechanisms may have an uneven impact on a particular customer class depending on the underlying tariffs affected. For nonregulated gas, revenues are impacted by competitive market rates tailored to appeal to specific customer classes. The Company and Consolidated SCE&G have disaggregated operating revenues by customer class as follows:

The Company	Consolidated SCE&G				PSNC Energy		Total  Gas-regulated		Gas-nonregulated
Millions of dollars	Electric		Gas-regulated		Gas-regulated
2018
Customer class:
Residential	$	1,054	$	208	$	325	$	533	$	244
Commercial	744		117		125		242		92
Industrial	385		92		15		107		422
Transportation	—		13		32		45		—
Other	132		4		—		4		38
Revenues from contracts with customers	2,315		434		497		931		796
Other operating revenues	12		1		3		4		—
Total Operating Revenues	$	2,327	$	435	$	500	$	935	$	796

Contract Liabilities

Contract liabilities represent the obligation to transfer goods or services to a customer for which consideration has already been received from the customer. At December 31, 2018 and 2017, the Company had contract liability balances of $9.4 million and $8.3 million, respectively, and Consolidated SCE&G had contract liability balances of $3.6 million and $2.9 million, respectively. During the twelve months ended December 31, 2018, the Company and Consolidated SCE&G recognized all amounts from their respective December 31, 2017 contract liability balances as each of them fulfilled their obligations to provide service to their customers. Such obligations at December 31, 2018 are expected to be fulfilled within twelve months. 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, SCE&G provides economic development grants intended to support economic growth within SCE&G’s electric service territory and defers such grants as regulatory assets on the consolidated balance sheet. Whenever these grants are contingent on a customer entering into a long-term electric supply contract with SCE&G, 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:

The Company and Consolidated SCE&G
Millions of dollars	Regulatory Assets
January 1, 2018	$	16.3
Additional costs	—
Amortization	(1.5		)
Impairment	—
December 31, 2018	$	14.8

SCE&G

Revenue from Contract with Customer [Text Block]

REVENUE RECOGNITION

Identifying Revenue Streams and Related Performance Obligations

Operating Revenues

Operating revenues arise primarily from the sale and transmission of electricity and the sale and transportation of natural gas. Electric and Gas regulated revenues consist primarily of retail sales to residential, commercial and industrial customers under various tariff rates approved by state regulatory commissions. These tariff rates generally include charges for the energy consumed and a standard basic facilities or demand charge designed to recover certain fixed costs incurred to provide service to the customer. Tariff rates also include commission-approved regulatory mechanisms in the form of adjustments or riders, such as for weather normalization, fuel and environmental cost recovery, energy conservation programs, interruptible service and real time pricing provisions, among others. Electric revenues also include wholesale sales and transmission service, primarily to municipal customers and other service providers, under contracts or tariffs approved by the FERC.

Gas nonregulated revenues arise from natural gas sales at market-based rates. Such sales to residential and certain commercial customers include charges for natural gas delivered, at either variable or fixed prices, together with any applicable customer service charges, charges originating from an interstate pipeline company, and other incidental charges. The Company has determined that its gas marketing subsidiary serves as an agent for distribution services provided by a nonaffiliated company in its retail market. Accordingly, the pass-through charges to customers related to such services are not considered revenues. Sales to other commercial and to industrial customers include commodity and transportation charges for natural gas delivered at contracted rates, together with applicable fees for storage, injection, demand, and charges originating from one or more interstate pipeline companies.

Performance obligations which have not been satisfied by the Company or Consolidated SCE&G 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 the Company and Consolidated SCE&G for these charges is equal to the amount of consideration they have a right to invoice and corresponds directly to the value transferred to the customer. As a result, amounts related to performance obligations that have not been fully satisfied are not disclosed.

Contracts governing the transactions above do not have a significant financing component. Also, due to the nature of the commodities underlying these transactions, no performance obligations arise for returns, refunds or warranties. In addition, taxes billed to customers are excluded from the transaction price. Such amounts are recorded as liabilities until they are remitted to the respective taxing authority and are not included in revenues or expenses in the statements of operations.

Non-Operating Revenues

Non-operating revenues are derived from the sale of appliances and water heaters, as well as from contracts covering the repair of certain appliances, wiring, plumbing and similar systems and fees received for such repairs from customers not under a repair contract. In addition, the portion of fees received under asset management agreements that regulators have recognized to be incentives for the Company and Consolidated SCE&G to engage in such transactions is recorded as non-operating revenues.

Revenues from sales are recorded when the appliance or water heater is delivered to the customer. Repair contract coverage fees are recorded when invoiced, generally on a monthly basis in advance of the period of coverage. Additional charges for service calls and non-covered repairs are billed and collected at the time service is rendered. Revenues from asset management agreements are recorded when the related fixed monthly amounts are due, which corresponds to timing of the value received by the customer.

The point at which the customer controls the use of a purchased product or has obtained substantially all of the benefits from repair services, corresponds to when revenues are recorded and performance obligations are fulfilled. Contract assets arising from invoicing repair contract fees in advance of the coverage period are not material. Income earned from financing sales of appliances and other products is recorded within interest income. Any performance obligations arising from returns, refunds or warranties are not material.

Non-operating revenues also arise from sources unrelated to contracts with customers, such as carrying costs recorded on certain regulatory assets, gains from property sales and income from rentals and from equity method investments, among others. In 2018, such amounts include gains realized upon the settlement of certain interest rate swaps (see Note 15). Such revenues are outside the scope of revenues from contracts with customers.

Non-operating revenues are further described in Note 15. Such revenues arising from contracts with customers were not material for any period presented, and accordingly, detailed disclosures regarding these revenues are not provided.

Significant Judgments and Estimates

Electricity and natural gas are sold and delivered to the customer for immediate consumption and the customer controls the use of, and obtains substantially all of the benefits from, the energy and related services as they are delivered. As such, the related performance obligations are satisfied over time and revenue is recognized over the same period. The Company and Consolidated SCE&G have determined that their right to consideration from a customer directly corresponds to the value of the performance completed at the date each customer invoice is rendered. As a result, the Company and Consolidated SCE&G recognize revenue in the amounts for which they have a right to invoice. This includes estimated amounts unbilled at a balance sheet date, but which are to be invoiced in the normal cycle.

Regulatory mechanisms exist within electric and gas tariffs or orders from regulators that result in adjustments to customer bills. These regulatory mechanisms are designed:

• To recover costs related to fuel, pension, pipeline integrity and energy conservation, among others;

• To recover carrying costs associated with debt-based financing;

• To replace revenues lost as a result of the utility implementing DER programs and DSM Programs; and

• For gas revenues, to achieve weather normalization or to decouple gas revenues from weather and other factors through the WNA at SCE&G or the CUT at PSNC Energy.

Recovery of deferred costs and carrying costs and the replacement of lost revenues are components of approved tariffs, and therefore, adjustments to customer bills occur as electricity or natural gas is sold and delivered to the customer. As such, the Company and Consolidated SCE&G have concluded that performance obligations related to these adjustments are not capable of being distinct from the underlying tariff based sales. Accordingly, revenues arising from these adjustments are recorded within Operating Revenues - Electric or Gas - regulated on the statements of operations, consistent with revenues from underlying tariff based sales.

Adjustments for SCE&G’s WNA increase gas customer bills when weather is milder than normal and decrease gas customer bills when weather is colder than normal. These adjustments are made during the same period that the underlying natural gas is sold and delivered to the customer, and the performance obligations associated with these adjustments are not capable of being distinct from tariff based sales. Such adjustments are recorded within Operating Revenues - Gas - regulated on the statements of operations. When weather is significantly milder than normal, SCE&G limits such adjustments on a gas customer’s bill to an amount that would be added if weather were 50% milder than normal. Adjustments exceeding this limit, though still recorded as operating revenue, are deferred within regulatory assets until customers are subsequently billed for the excess with the approval of the SCPSC.

PSNC Energy’s CUT is a decoupling mechanism that adjusts bills for residential and commercial customers based on per customer average consumption. When average consumption exceeds actual usage, PSNC Energy records increased revenue associated with this undercollection and defers it within regulatory assets. Likewise, when actual usage exceeds average consumption, a decrement to revenue associated with this overcollection is recorded and deferred within regulatory liabilities. PSNC Energy’s tariff based rates are adjusted semiannually, with the approval of the NCUC, to collect or refund these deferred amounts over the subsequent 12 month period.

Amounts deferred for the WNA and the CUT arise under specific arrangements with regulators rather than customers. As a result, the Company and Consolidated SCE&G have concluded that these arrangements represent alternative revenue programs. Revenue from alternative revenue programs is included within Operating Revenues - Gas - regulated on the statements of operations in the month such adjustments are deferred within regulatory accounts and is shown as Other operating revenues when disaggregated in the table below. As permitted, the Company and Consolidated SCE&G have elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues.

Disaggregation of Revenues

The impact of several factors on the amount, timing and uncertainty of operating revenues and cash flows can vary significantly by customer class. For electric revenues and nonregulated gas revenues, which do not have weather normalization mechanisms in place, weather and conservation measures on energy usage typically affect residential and commercial customers to a greater degree than other customer classes. For utilities, revenue requirements result in increases or decreases in tariff rates approved by regulatory bodies and often vary by customer class. Also, certain cost recovery and other mechanisms may have an uneven impact on a particular customer class depending on the underlying tariffs affected. For nonregulated gas, revenues are impacted by competitive market rates tailored to appeal to specific customer classes. The Company and Consolidated SCE&G have disaggregated operating revenues by customer class as follows:

The Company	Consolidated SCE&G				PSNC Energy		Total  Gas-regulated		Gas-nonregulated
Millions of dollars	Electric		Gas-regulated		Gas-regulated
2018
Customer class:
Residential	$	1,054	$	208	$	325	$	533	$	244
Commercial	744		117		125		242		92
Industrial	385		92		15		107		422
Transportation	—		13		32		45		—
Other	132		4		—		4		38
Revenues from contracts with customers	2,315		434		497		931		796
Other operating revenues	12		1		3		4		—
Total Operating Revenues	$	2,327	$	435	$	500	$	935	$	796

Contract Liabilities

Contract liabilities represent the obligation to transfer goods or services to a customer for which consideration has already been received from the customer. At December 31, 2018 and 2017, the Company had contract liability balances of $9.4 million and $8.3 million, respectively, and Consolidated SCE&G had contract liability balances of $3.6 million and $2.9 million, respectively. During the twelve months ended December 31, 2018, the Company and Consolidated SCE&G recognized all amounts from their respective December 31, 2017 contract liability balances as each of them fulfilled their obligations to provide service to their customers. Such obligations at December 31, 2018 are expected to be fulfilled within twelve months. 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, SCE&G provides economic development grants intended to support economic growth within SCE&G’s electric service territory and defers such grants as regulatory assets on the consolidated balance sheet. Whenever these grants are contingent on a customer entering into a long-term electric supply contract with SCE&G, 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:

The Company and Consolidated SCE&G
Millions of dollars	Regulatory Assets
January 1, 2018	$	16.3
Additional costs	—
Amortization	(1.5		)
Impairment	—
December 31, 2018	$	14.8

XML

COMMON EQUITY

12 Months Ended

Dec. 31, 2018

Schedule of Capitalization, Equity [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

COMMON EQUITY

Authorized shares of SCANA common stock were 200 million as of December 31, 2018 and 2017. Authorized shares of SCE&G common stock were 50 million as of December 31, 2018 and 2017. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were held by SCANA as of December 31, 2018 and 2017. As disclosed in Note 1, effective January 1, 2019, all common stock of SCANA is held by Dominion Energy.

In 2018, SCANA made equity contributions to GENCO and Fuel Company totaling approximately $23 million and $1 million, respectively.

In February 2019, SCANA received an equity contribution of $675 million from Dominion Energy, and SCANA made an equity contribution to SCE&G of $675 million. SCE&G used the funds from this equity contribution to reduce long-term debt. See Note 5.

SCANA’s articles of incorporation do not limit the dividends that may be paid on its common stock, and the articles of incorporation of each of SCANA's subsidiaries contain no such limitations on their respective common stock.

SCE&G’s bond indenture under which it issues First Mortgage Bonds contains provisions that could limit the payment of cash dividends on its common stock. SCE&G's bond indenture permits the payment of dividends on SCE&G'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 December 31, 2018 and 2017, retained earnings of approximately $115.0 million and $93.9 million, respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

Pursuant to the Merger Approval Order, the amount of any SCE&G dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry. There is no specific restriction on the payment of dividends by SCE&G.

PSNC Energy’s note purchase and debenture purchase agreements contain provisions that could limit the payment of cash distributions, including dividends, on PSNC Energy's common stock. These agreements generally limit the sum of distributions to an amount that does not exceed $30 million plus 85% of Consolidated Net Income (as therein defined) accumulated after December 31, 2008 plus the net proceeds of issuances by PSNC Energy of equity or convertible debt securities (as therein defined). As of December 31, 2018, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million.

The NCUC, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by PSNC Energy to (i) the amount of retained earnings at closing of the SCANA Combination plus (ii) any future earnings recorded by PSNC Energy after such date. In addition, notice to the NCUC is required if payment of dividends causes the equity component of PSNC Energy’s capital structure to fall below 45%.

SCE&G

Schedule of Capitalization, Equity [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

.COMMON EQUITY

Authorized shares of SCANA common stock were 200 million as of December 31, 2018 and 2017. Authorized shares of SCE&G common stock were 50 million as of December 31, 2018 and 2017. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were held by SCANA as of December 31, 2018 and 2017. As disclosed in Note 1, effective January 1, 2019, all common stock of SCANA is held by Dominion Energy.

In 2018, SCANA made equity contributions to GENCO and Fuel Company totaling approximately $23 million and $1 million, respectively.

In February 2019, SCANA received an equity contribution of $675 million from Dominion Energy, and SCANA made an equity contribution to SCE&G of $675 million. SCE&G used the funds from this equity contribution to reduce long-term debt. See Note 5.

SCANA’s articles of incorporation do not limit the dividends that may be paid on its common stock, and the articles of incorporation of each of SCANA's subsidiaries contain no such limitations on their respective common stock.

SCE&G’s bond indenture under which it issues First Mortgage Bonds contains provisions that could limit the payment of cash dividends on its common stock. SCE&G's bond indenture permits the payment of dividends on SCE&G'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 December 31, 2018 and 2017, retained earnings of approximately $115.0 million and $93.9 million, respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

Pursuant to the Merger Approval Order, the amount of any SCE&G dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry. There is no specific restriction on the payment of dividends by SCE&G.

PSNC Energy’s note purchase and debenture purchase agreements contain provisions that could limit the payment of cash distributions, including dividends, on PSNC Energy's common stock. These agreements generally limit the sum of distributions to an amount that does not exceed $30 million plus 85% of Consolidated Net Income (as therein defined) accumulated after December 31, 2008 plus the net proceeds of issuances by PSNC Energy of equity or convertible debt securities (as therein defined). As of December 31, 2018, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million.

The NCUC, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by PSNC Energy to (i) the amount of retained earnings at closing of the SCANA Combination plus (ii) any future earnings recorded by PSNC Energy after such date. In addition, notice to the NCUC is required if payment of dividends causes the equity component of PSNC Energy’s capital structure to fall below 45%.

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LONG-TERM AND SHORT-TERM DEBT

12 Months Ended

Dec. 31, 2018

Debt Instrument [Line Items]

Debt Disclosure [Text Block]

    LONG-TERM AND SHORT-TERM DEBT

Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows:

The Company
December 31,				2018					2017
Dollars in millions	Maturity			Balance			Rate		Balance			Rate
SCANA Medium Term Notes (unsecured)	2020	-	2022	$	800		5.42	%	$	800		5.42	%
SCANA Senior Notes (unsecured) (a)	2019	-	2034	70			3.44	%	75			2.18	%
SCE&G First Mortgage Bonds (secured)	2021	-	2065	4,990			5.52	%	4,840			5.80	%
GENCO Notes (secured)	2019	-	2024	40			5.49	%	207			5.94	%
Industrial and Pollution Control Bonds (b)	2028	-	2038	122			3.52	%	122			3.52	%
PSNC Energy Senior Debentures and Notes	2020	-	2047	700			5.07	%	600			5.19	%
Other	2019	-	2027	73			3.46	%	28			2.83	%
Total debt				6,795					6,672
Current maturities of long-term debt				(59		)			(727		)
Unamortized discount, net				(2		)			(1		)
Unamortized debt issuance costs				(39		)			(38		)
Total long-term debt, net				$	6,695				$	5,906

Consolidated SCE&G
December 31,				2018					2017
Dollars in millions	Maturity			Balance			Rate		Balance			Rate
First Mortgage Bonds (secured)	2021	-	2065	$	4,990		5.52	%	$	4,840		5.80	%
GENCO Notes (secured)	2019	-	2024	40			5.49	%	207			5.94	%
Industrial and Pollution Control Bonds (b)	2028	-	2038	122			3.52	%	122			3.52	%
Other	2019	-	2027	30			2.97	%	28			2.83	%
Total debt				5,182					5,197
Current maturities of long-term debt				(14		)			(723		)
Unamortized premium (discount), net				(1		)			1
Unamortized debt issuance costs				(35		)			(34		)
Total long-term debt, net				$	5,132				$	4,441

(a)  Variable rate notes hedged by a fixed interest rate swap (fixed rate of 6.17%).

(b) Includes variable rate debt of $67.8 million at December 31, 2018 (rate of 1.72%) and 2017 (rate of 1.85%) which are hedged by fixed swaps.

In September 2018, SCANA borrowed $40 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at December 31, 2018 was 3.87%. This draw was repaid January 10, 2019. Proceeds from the draw had been used to provide contractually required credit support, and this deposit is reflected within other assets on the consolidated balance sheet.

In August 2018, SCE&G issued $300 million of 3.50% first mortgage bonds due August 15, 2021, and $400 million of 4.25% first mortgage bonds due August 15, 2028. Proceeds from these sales were used on September 28, 2018, to repay prior to maturity $250 million of 5.25% first mortgage bonds and $300 million of 6.50% first mortgage bonds, each due November 1, 2018. In addition, proceeds were used for general corporate purposes.

In June 2018, GENCO redeemed at maturity $160 million of 6.06% secured notes. The repayment was funded using a combination of money pool borrowings and an equity contribution from SCANA.

In June 2018, PSNC Energy issued $100 million of 4.33% senior notes due June 15, 2028. In June 2017, PSNC Energy issued $150 million of 4.18% senior notes due June 30, 2047. Proceeds from each of these sales were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.

In March 2018, SCE&G borrowed $100 million under the five-year credit agreement expiring December 2020. The proceeds of this draw were deposited with a natural gas supplier to provide contractually required credit support. In September 2018, SCE&G obtained a surety bond to replace this credit support and, as a result, the deposit was returned and this draw was repaid in September 2018. Also, SCANA obtained letters of credit in favor of natural gas suppliers to provide contractually required credit support.

As of December 31, 2018, the Company's long-term debt maturities are $59 million in 2019, $368 million in 2020, $797 million in 2021, $266 million in 2022 and $14 million in 2023. These amounts include, for Consolidated SCE&G, $14 million in 2019, $13 million in 2020, $342 million in 2021, $11 million in 2022 and $9 million in 2023.

In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any and all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of approximately $1.0 billion. SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer.

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

SCE&G 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, 2018, the Bond Ratio was 4.01. Adjusted Net Earnings, as therein defined, excludes the impairment loss.

Lines of Credit and Short-Term Borrowings

At December 31, 2018 and 2017, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC-related obligations and commercial paper borrowings:

Millions of dollars	Total		SCANA			SCE&G			PSNC  Energy
December 31, 2018
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	500.0		—			500.0			—
Total committed long-term	1,800.0		400.0			1,200.0			200.0
LOC advances	40.0		40.0			—			—
Weighted average interest rate			3.87		%
Outstanding commercial paper (270 or fewer days)	172.9		2.0			73.2			97.7
Weighted average interest rate			3.65		%	3.82		%	3.49		%
Letters of credit supported by LOC	37.6		37.3			0.3			—
Available	$	1,549.5	$	320.7		$	1,126.5		$	102.3

December 31, 2017
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0	$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	500.0		—		500.0			—
Three-year, expiring December 2018	200.0		—		200.0			—
Total committed long-term	2,000.0		400.0		1,400.0			200.0
Outstanding commercial paper (270 or fewer days)	350.3		—		251.6			98.7
Weighted average interest rate					1.92		%	1.93		%
Letters of credit supported by LOC	3.3		3.0		0.3			—
Available	$	1,646.4	$	397.0	$	1,148.1		$	101.3

At December 31, 2018, SCANA, SCE&G (including Fuel Company) and PSNC Energy were parties to credit agreements in the amounts and for the terms described above. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N.A. and Morgan Stanley Bank, N.A. each provide 9.5% of the aggregate credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch, UBS Loan Finance LLC, MUFG Union Bank, N.A., and Branch Banking and Trust Company each provide 7.9%, and Royal Bank of Canada and U.S. Bank National Association each provide 5.5%. Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.

In December 2018, SCE&G's three-year credit facility expired and was not replaced. In February 2019, Fuel Company's commercial paper program and its credit facility were terminated. Fuel Company's financing needs in the future are expected to be met using the money pool described below.

SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2019, which reflects a one-year authorization period rather than the two-year period SCE&G and GENCO had requested. In granting the authorization for a shorter period, FERC cited several matters which, at the time, were ongoing, including proceedings involving the ORS and Act 258, as well as the merger between SCANA and Dominion Energy, that could affect SCE&G's and GENCO's circumstances. Were adverse developments to occur with respect to uncertainties highlighted elsewhere, the ability of SCE&G or GENCO to secure renewal of this short-term borrowing authority may be adversely impacted. In January 2019, SCE&G and GENCO applied to FERC for a two-year short-term borrowing authorization, and that application is pending.

Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. The letters of credit expire, subject to renewal, in the fourth quarter of 2019.

Consolidated SCE&G participates in a utility money pool with SCANA and another regulated subsidiary of SCANA. Money pool borrowings and investments bear interest at short-term market rates. For the twelve months ended December 31, 2018, Consolidated SCE&G recorded interest income from money pool transactions of $4.1 million and interest expense from money pool transactions of $4.1 million, respectively. Interest income and interest expense for periods in 2017 were not significant. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $282 million and investments due from an affiliate of $353 million at December 31, 2018. At December 31, 2017 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $37 million and investments due from an affiliate of $28 million. For each period presented, money pool borrowings were made by Fuel Company and GENCO, and money pool investments were made by SCE&G. On its consolidated balance sheet, Consolidated SCE&G includes money pool borrowings within Affiliated payables and money pool investments within Affiliated companies receivables.

SCE&G

Debt Instrument [Line Items]

Debt Disclosure [Text Block]

LONG-TERM AND SHORT-TERM DEBT

Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows:

The Company
December 31,				2018					2017
Dollars in millions	Maturity			Balance			Rate		Balance			Rate
SCANA Medium Term Notes (unsecured)	2020	-	2022	$	800		5.42	%	$	800		5.42	%
SCANA Senior Notes (unsecured) (a)	2019	-	2034	70			3.44	%	75			2.18	%
SCE&G First Mortgage Bonds (secured)	2021	-	2065	4,990			5.52	%	4,840			5.80	%
GENCO Notes (secured)	2019	-	2024	40			5.49	%	207			5.94	%
Industrial and Pollution Control Bonds (b)	2028	-	2038	122			3.52	%	122			3.52	%
PSNC Energy Senior Debentures and Notes	2020	-	2047	700			5.07	%	600			5.19	%
Other	2019	-	2027	73			3.46	%	28			2.83	%
Total debt				6,795					6,672
Current maturities of long-term debt				(59		)			(727		)
Unamortized discount, net				(2		)			(1		)
Unamortized debt issuance costs				(39		)			(38		)
Total long-term debt, net				$	6,695				$	5,906

Consolidated SCE&G
December 31,				2018					2017
Dollars in millions	Maturity			Balance			Rate		Balance			Rate
First Mortgage Bonds (secured)	2021	-	2065	$	4,990		5.52	%	$	4,840		5.80	%
GENCO Notes (secured)	2019	-	2024	40			5.49	%	207			5.94	%
Industrial and Pollution Control Bonds (b)	2028	-	2038	122			3.52	%	122			3.52	%
Other	2019	-	2027	30			2.97	%	28			2.83	%
Total debt				5,182					5,197
Current maturities of long-term debt				(14		)			(723		)
Unamortized premium (discount), net				(1		)			1
Unamortized debt issuance costs				(35		)			(34		)
Total long-term debt, net				$	5,132				$	4,441

(a)  Variable rate notes hedged by a fixed interest rate swap (fixed rate of 6.17%).

(b) Includes variable rate debt of $67.8 million at December 31, 2018 (rate of 1.72%) and 2017 (rate of 1.85%) which are hedged by fixed swaps.

In September 2018, SCANA borrowed $40 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at December 31, 2018 was 3.87%. This draw was repaid January 10, 2019. Proceeds from the draw had been used to provide contractually required credit support, and this deposit is reflected within other assets on the consolidated balance sheet.

In August 2018, SCE&G issued $300 million of 3.50% first mortgage bonds due August 15, 2021, and $400 million of 4.25% first mortgage bonds due August 15, 2028. Proceeds from these sales were used on September 28, 2018, to repay prior to maturity $250 million of 5.25% first mortgage bonds and $300 million of 6.50% first mortgage bonds, each due November 1, 2018. In addition, proceeds were used for general corporate purposes.

In June 2018, GENCO redeemed at maturity $160 million of 6.06% secured notes. The repayment was funded using a combination of money pool borrowings and an equity contribution from SCANA.

In June 2018, PSNC Energy issued $100 million of 4.33% senior notes due June 15, 2028. In June 2017, PSNC Energy issued $150 million of 4.18% senior notes due June 30, 2047. Proceeds from each of these sales were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.

In March 2018, SCE&G borrowed $100 million under the five-year credit agreement expiring December 2020. The proceeds of this draw were deposited with a natural gas supplier to provide contractually required credit support. In September 2018, SCE&G obtained a surety bond to replace this credit support and, as a result, the deposit was returned and this draw was repaid in September 2018. Also, SCANA obtained letters of credit in favor of natural gas suppliers to provide contractually required credit support.

As of December 31, 2018, the Company's long-term debt maturities are $59 million in 2019, $368 million in 2020, $797 million in 2021, $266 million in 2022 and $14 million in 2023. These amounts include, for Consolidated SCE&G, $14 million in 2019, $13 million in 2020, $342 million in 2021, $11 million in 2022 and $9 million in 2023.

In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any and all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of approximately $1.0 billion. SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer.

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

SCE&G 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, 2018, the Bond Ratio was 4.01. Adjusted Net Earnings, as therein defined, excludes the impairment loss.

Lines of Credit and Short-Term Borrowings

At December 31, 2018 and 2017, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC-related obligations and commercial paper borrowings:

Millions of dollars	Total		SCANA			SCE&G			PSNC  Energy
December 31, 2018
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	500.0		—			500.0			—
Total committed long-term	1,800.0		400.0			1,200.0			200.0
LOC advances	40.0		40.0			—			—
Weighted average interest rate			3.87		%
Outstanding commercial paper (270 or fewer days)	172.9		2.0			73.2			97.7
Weighted average interest rate			3.65		%	3.82		%	3.49		%
Letters of credit supported by LOC	37.6		37.3			0.3			—
Available	$	1,549.5	$	320.7		$	1,126.5		$	102.3

December 31, 2017
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0	$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	500.0		—		500.0			—
Three-year, expiring December 2018	200.0		—		200.0			—
Total committed long-term	2,000.0		400.0		1,400.0			200.0
Outstanding commercial paper (270 or fewer days)	350.3		—		251.6			98.7
Weighted average interest rate					1.92		%	1.93		%
Letters of credit supported by LOC	3.3		3.0		0.3			—
Available	$	1,646.4	$	397.0	$	1,148.1		$	101.3

At December 31, 2018, SCANA, SCE&G (including Fuel Company) and PSNC Energy were parties to credit agreements in the amounts and for the terms described above. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N.A. and Morgan Stanley Bank, N.A. each provide 9.5% of the aggregate credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch, UBS Loan Finance LLC, MUFG Union Bank, N.A., and Branch Banking and Trust Company each provide 7.9%, and Royal Bank of Canada and U.S. Bank National Association each provide 5.5%. Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.

In December 2018, SCE&G's three-year credit facility expired and was not replaced. In February 2019, Fuel Company's commercial paper program and its credit facility were terminated. Fuel Company's financing needs in the future are expected to be met using the money pool described below.

SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2019, which reflects a one-year authorization period rather than the two-year period SCE&G and GENCO had requested. In granting the authorization for a shorter period, FERC cited several matters which, at the time, were ongoing, including proceedings involving the ORS and Act 258, as well as the merger between SCANA and Dominion Energy, that could affect SCE&G's and GENCO's circumstances. Were adverse developments to occur with respect to uncertainties highlighted elsewhere, the ability of SCE&G or GENCO to secure renewal of this short-term borrowing authority may be adversely impacted. In January 2019, SCE&G and GENCO applied to FERC for a two-year short-term borrowing authorization, and that application is pending.

Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. The letters of credit expire, subject to renewal, in the fourth quarter of 2019.

Consolidated SCE&G participates in a utility money pool with SCANA and another regulated subsidiary of SCANA. Money pool borrowings and investments bear interest at short-term market rates. For the twelve months ended December 31, 2018, Consolidated SCE&G recorded interest income from money pool transactions of $4.1 million and interest expense from money pool transactions of $4.1 million, respectively. Interest income and interest expense for periods in 2017 were not significant. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $282 million and investments due from an affiliate of $353 million at December 31, 2018. At December 31, 2017 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $37 million and investments due from an affiliate of $28 million. For each period presented, money pool borrowings were made by Fuel Company and GENCO, and money pool investments were made by SCE&G. On its consolidated balance sheet, Consolidated SCE&G includes money pool borrowings within Affiliated payables and money pool investments within Affiliated companies receivables.

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INCOME TAXES

12 Months Ended

Dec. 31, 2018

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

Components of income tax expense (benefit) are as follows:

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
Current taxes (benefit):
Federal	$	(8	)	$	(414	)	$	36		$	(16	)	$	(410	)	$	50
State	5			18			13			—			(18		)	13
Total current taxes (benefit)	(3		)	(396		)	49			(16		)	(428		)	63
Deferred tax (benefit) expense, net:
Federal	(352		)	323			203			(346		)	261			167
State	(55		)	(37		)	21			(52		)	(2		)	20
Total deferred taxes (benefit)	(407		)	286			224			(398		)	259			187
Investment tax credits:
Amortization of amounts deferred-federal	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Total income tax expense (benefit)	$	(412	)	$	(112	)	$	271		$	(416	)	$	(171	)	$	248

In December 2017, the Tax Act was enacted, resulting in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory tax rate. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in excess deferred income tax balances within regulatory liabilities (see Note 2).

Included in the Company’s 2018 federal deferred income tax expense was $53 million for the utilization of operating loss carryforwards. Included in Consolidated SCE&G’s 2018 federal deferred income tax expense was $46 million for the utilization of operating loss carryforwards.

The difference between actual income tax expense and the amount calculated from the application of the statutory federal income tax rate to pre-tax income is reconciled as follows:

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
U.S. statutory rate	21		%	35		%	35		%	21		%	35		%	35		%
Net income (loss)	$	(528	)	$	(119	)	$	595		$	(614	)	$	(185	)	$	513
Income tax expense (benefit)	(412		)	(112		)	271			(416		)	(171		)	248
Noncontrolling interest	—			—			—			25			13			13
Total pre-tax income (loss)	$	(940	)	$	(231	)	$	866		$	(1,005	)	$	(343	)	$	774
Income taxes (benefit) on above at statutory federal income tax rate	$	(197	)	$	(81	)	$	303		$	(211	)	$	(120	)	$	271
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)	(37		)	(7		)	27			(38		)	(8		)	26
State investment tax credits (less federal income tax effect)	(3		)	(5		)	(5		)	(3		)	(5		)	(5		)
Allowance for equity funds used during construction	(4		)	(8		)	(10		)	(2		)	(5		)	(9		)
Deductible dividends—401(k) Retirement Savings Plan	(2		)	(9		)	(10		)	—			—			—
Amortization of federal investment tax credits	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Section 45 tax credits	(9		)	(8		)	(8		)	(9		)	(8		)	(8		)
Domestic production activities deduction	—			(18		)	(23		)	—			(18		)	(23		)
Remeasurement of deferred taxes in connection with enactment of Tax Act	(188		)	30			—			(176		)	(1		)	—
Nuclear Project impairment	23			—			—			23			—			—
Nondeductible merger-related costs	5			—			—			—			—			—
Other differences, net	2			(4		)	(1		)	2			(4		)	(2		)
Total income tax expense (benefit)	$	(412	)	$	(112	)	$	271		$	(416	)	$	(171	)	$	248

The Company and Consolidated SCE&G have completed their accounting for the effects of the Tax Act. In connection with the remeasurement of federal deferred income tax assets and liabilities, the Company recorded additional deferred income tax expense of approximately $30 million, and Consolidated SCE&G recorded a deferred income tax benefit of approximately $1 million in their respective statements of operations for the year ended December 31, 2017. As a result of the eventual filing of the Company's 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 $188 million at the Company and approximately $176 million at Consolidated SCE&G were recorded. Also in connection with the additional impairment charges, the Company and Consolidated SCE&G recorded additional adjustments to deferred income taxes in the aggregate amount of approximately $23 million. Additional changes could occur as further Tax Act guidance is issued and finalized. In addition, certain states in which the Company and Consolidated SCE&G operate may or may not conform to some or all of the provisions of the Tax 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.

The State of North Carolina lowered its corporate income tax rate to 4.0% in 2016, 3.0% in 2017 and 2.5% effective January 1, 2019. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

The tax effects of significant temporary differences comprising net deferred tax liabilities are as follows:

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Deferred tax assets:
Net operating loss and tax credit carryforward	$	539	$	600	$	493	$	541
Toshiba settlement	274		273		274		273
Nondeductible accruals	84		88		40		42
Asset retirement obligation, including nuclear decommissioning	143		141		135		132
Regulatory liability, non-property accumulated deferred income tax	—		54		—		54
Financial instruments	10		15		—		—
Unamortized investment tax credits	7		8		7		8
Other	4		6		5		5
Total deferred tax assets	1,061		1,185		954		1,055
Deferred tax liabilities:
Property, plant and equipment	1,227		1,220		1,033		1,035
Regulatory asset, unrecovered nuclear plant costs	668		962		668		962
Deferred employee benefit plan costs	60		60		53		53
Regulatory asset, asset retirement obligation	94		91		88		85
Regulatory asset, other unrecovered plant	24		27		24		27
Demand side management costs	16		16		16		16
Prepayments	21		21		20		19
Other	63		49		41		31
Total deferred tax liabilities	2,173		2,446		1,943		2,228
Net deferred tax liabilities	$	1,112	$	1,261	$	989	$	1,173

The federal and state tax credits and NOL carryforwards are presented below:

	December 31, 2018
Millions of dollars	The Company		Consolidated SCE&G		Expiration Year
Federal NOL Carryforwards	$	1,807	$	1,642	2037
Federal Tax Credits	83		83		2035	-	2038
State NOL Carryforwards	2,447		2,198		2037
State Tax Credits	30		30		2026	-	2033
Total Tax Credits and NOL Carryforwards	$	4,367	$	3,953

A valuation allowance is needed when it is more likely than not that all or a portion of a deferred tax asset will not be realized. In determining whether a valuation allowance is required, the Company and Consolidated SCE&G consider such factors as prior earnings history, expected future earnings, carryback and carryforward periods, and tax strategies that could potentially enhance the likelihood of the realization of a deferred tax asset. Based on this evaluation, management has concluded that a valuation allowance is not needed.    

The Company files consolidated federal income tax returns and certain state returns, including the return for South Carolina, which returns include Consolidated SCE&G. The Company and its subsidiaries file various other applicable state and local income tax returns. Consolidated SCE&G's NOL shown above represents their portion on a stand-alone company basis. There is no material amount due to or from the Company.

The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2009 are closed for additional assessment. The IRS is currently examining the Company's open federal returns through 2017 as a result of claims discussed below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010.

Changes in Unrecognized Tax Benefits

	The Company							Consolidated SCE&G
Millions of dollars	2018		2017			2016		2018		2017			2016
Unrecognized tax benefits, January 1	$	98	$	350		$	49	$	98	$	350		$	49
Gross increases—uncertain tax positions in prior period	8		—			94		8		—			94
Gross decreases—uncertain tax positions in prior period	—		(273		)	—		—		(273		)	—
Gross increases—current period uncertain tax positions	—		21			207		—		21			207
Unrecognized tax benefits, December 31	$	106	$	98		$	350	$	106	$	98		$	350

During 2013 and 2014, the Company amended certain of its income tax returns to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). The Company also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016 and 2017, the Company claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the Nuclear Project, in its 2015 and 2016 income tax returns. The Company claimed similar deductions and credits in its 2017 tax return when it was filed in 2018. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models.

The IRS examined the claims in the amended returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2017 income tax returns.

These IRC Section 174 income tax deductions and IRC Section 41 credits were considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities were recorded as unrecognized tax benefits in the financial statements. Following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G claimed an abandonment loss deduction under IRC Section 165 on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, are instead expected to be deductible in 2017 under IRC Section 165. The Company received a favorable PLR from the IRS stating the Company has a valid tax deduction for abandonment under IRC Section 165. Although the IRS does not verify the amount of the deduction, there is no reserve against these costs. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, Section 41 credits, and certain unrecognized state tax benefits.

As of December 31, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $106 million ($38 million net of the impact of state deductions on federal returns, net of NOL and credit carryforwards, and net of receivables related to the uncertain tax positions). If recognized, $106 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. Due to the merger with Dominion Energy, it is reasonably possible that these unrecognized tax benefits could increase within the next 12 months, although such increase cannot be reasonably estimated. It is reasonably possible that these unrecognized tax benefits may decrease by $11 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through December 31, 2018.

The Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses. Amounts recorded for such interest income, interest expense or tax penalties have not been material for any period presented.

SCE&G

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

Components of income tax expense (benefit) are as follows:

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
Current taxes (benefit):
Federal	$	(8	)	$	(414	)	$	36		$	(16	)	$	(410	)	$	50
State	5			18			13			—			(18		)	13
Total current taxes (benefit)	(3		)	(396		)	49			(16		)	(428		)	63
Deferred tax (benefit) expense, net:
Federal	(352		)	323			203			(346		)	261			167
State	(55		)	(37		)	21			(52		)	(2		)	20
Total deferred taxes (benefit)	(407		)	286			224			(398		)	259			187
Investment tax credits:
Amortization of amounts deferred-federal	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Total income tax expense (benefit)	$	(412	)	$	(112	)	$	271		$	(416	)	$	(171	)	$	248

In December 2017, the Tax Act was enacted, resulting in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory tax rate. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in excess deferred income tax balances within regulatory liabilities (see Note 2).

Included in the Company’s 2018 federal deferred income tax expense was $53 million for the utilization of operating loss carryforwards. Included in Consolidated SCE&G’s 2018 federal deferred income tax expense was $46 million for the utilization of operating loss carryforwards.

The difference between actual income tax expense and the amount calculated from the application of the statutory federal income tax rate to pre-tax income is reconciled as follows:

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
U.S. statutory rate	21		%	35		%	35		%	21		%	35		%	35		%
Net income (loss)	$	(528	)	$	(119	)	$	595		$	(614	)	$	(185	)	$	513
Income tax expense (benefit)	(412		)	(112		)	271			(416		)	(171		)	248
Noncontrolling interest	—			—			—			25			13			13
Total pre-tax income (loss)	$	(940	)	$	(231	)	$	866		$	(1,005	)	$	(343	)	$	774
Income taxes (benefit) on above at statutory federal income tax rate	$	(197	)	$	(81	)	$	303		$	(211	)	$	(120	)	$	271
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)	(37		)	(7		)	27			(38		)	(8		)	26
State investment tax credits (less federal income tax effect)	(3		)	(5		)	(5		)	(3		)	(5		)	(5		)
Allowance for equity funds used during construction	(4		)	(8		)	(10		)	(2		)	(5		)	(9		)
Deductible dividends—401(k) Retirement Savings Plan	(2		)	(9		)	(10		)	—			—			—
Amortization of federal investment tax credits	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Section 45 tax credits	(9		)	(8		)	(8		)	(9		)	(8		)	(8		)
Domestic production activities deduction	—			(18		)	(23		)	—			(18		)	(23		)
Remeasurement of deferred taxes in connection with enactment of Tax Act	(188		)	30			—			(176		)	(1		)	—
Nuclear Project impairment	23			—			—			23			—			—
Nondeductible merger-related costs	5			—			—			—			—			—
Other differences, net	2			(4		)	(1		)	2			(4		)	(2		)
Total income tax expense (benefit)	$	(412	)	$	(112	)	$	271		$	(416	)	$	(171	)	$	248

The Company and Consolidated SCE&G have completed their accounting for the effects of the Tax Act. In connection with the remeasurement of federal deferred income tax assets and liabilities, the Company recorded additional deferred income tax expense of approximately $30 million, and Consolidated SCE&G recorded a deferred income tax benefit of approximately $1 million in their respective statements of operations for the year ended December 31, 2017. As a result of the eventual filing of the Company's 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 $188 million at the Company and approximately $176 million at Consolidated SCE&G were recorded. Also in connection with the additional impairment charges, the Company and Consolidated SCE&G recorded additional adjustments to deferred income taxes in the aggregate amount of approximately $23 million. Additional changes could occur as further Tax Act guidance is issued and finalized. In addition, certain states in which the Company and Consolidated SCE&G operate may or may not conform to some or all of the provisions of the Tax 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.

The State of North Carolina lowered its corporate income tax rate to 4.0% in 2016, 3.0% in 2017 and 2.5% effective January 1, 2019. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

The tax effects of significant temporary differences comprising net deferred tax liabilities are as follows:

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Deferred tax assets:
Net operating loss and tax credit carryforward	$	539	$	600	$	493	$	541
Toshiba settlement	274		273		274		273
Nondeductible accruals	84		88		40		42
Asset retirement obligation, including nuclear decommissioning	143		141		135		132
Regulatory liability, non-property accumulated deferred income tax	—		54		—		54
Financial instruments	10		15		—		—
Unamortized investment tax credits	7		8		7		8
Other	4		6		5		5
Total deferred tax assets	1,061		1,185		954		1,055
Deferred tax liabilities:
Property, plant and equipment	1,227		1,220		1,033		1,035
Regulatory asset, unrecovered nuclear plant costs	668		962		668		962
Deferred employee benefit plan costs	60		60		53		53
Regulatory asset, asset retirement obligation	94		91		88		85
Regulatory asset, other unrecovered plant	24		27		24		27
Demand side management costs	16		16		16		16
Prepayments	21		21		20		19
Other	63		49		41		31
Total deferred tax liabilities	2,173		2,446		1,943		2,228
Net deferred tax liabilities	$	1,112	$	1,261	$	989	$	1,173

The federal and state tax credits and NOL carryforwards are presented below:

	December 31, 2018
Millions of dollars	The Company		Consolidated SCE&G		Expiration Year
Federal NOL Carryforwards	$	1,807	$	1,642	2037
Federal Tax Credits	83		83		2035	-	2038
State NOL Carryforwards	2,447		2,198		2037
State Tax Credits	30		30		2026	-	2033
Total Tax Credits and NOL Carryforwards	$	4,367	$	3,953

A valuation allowance is needed when it is more likely than not that all or a portion of a deferred tax asset will not be realized. In determining whether a valuation allowance is required, the Company and Consolidated SCE&G consider such factors as prior earnings history, expected future earnings, carryback and carryforward periods, and tax strategies that could potentially enhance the likelihood of the realization of a deferred tax asset. Based on this evaluation, management has concluded that a valuation allowance is not needed.    

The Company files consolidated federal income tax returns and certain state returns, including the return for South Carolina, which returns include Consolidated SCE&G. The Company and its subsidiaries file various other applicable state and local income tax returns. Consolidated SCE&G's NOL shown above represents their portion on a stand-alone company basis. There is no material amount due to or from the Company.

The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2009 are closed for additional assessment. The IRS is currently examining the Company's open federal returns through 2017 as a result of claims discussed below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010.

Changes in Unrecognized Tax Benefits

	The Company							Consolidated SCE&G
Millions of dollars	2018		2017			2016		2018		2017			2016
Unrecognized tax benefits, January 1	$	98	$	350		$	49	$	98	$	350		$	49
Gross increases—uncertain tax positions in prior period	8		—			94		8		—			94
Gross decreases—uncertain tax positions in prior period	—		(273		)	—		—		(273		)	—
Gross increases—current period uncertain tax positions	—		21			207		—		21			207
Unrecognized tax benefits, December 31	$	106	$	98		$	350	$	106	$	98		$	350

During 2013 and 2014, the Company amended certain of its income tax returns to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). The Company also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016 and 2017, the Company claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the Nuclear Project, in its 2015 and 2016 income tax returns. The Company claimed similar deductions and credits in its 2017 tax return when it was filed in 2018. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models.

The IRS examined the claims in the amended returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2017 income tax returns.

These IRC Section 174 income tax deductions and IRC Section 41 credits were considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities were recorded as unrecognized tax benefits in the financial statements. Following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G claimed an abandonment loss deduction under IRC Section 165 on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, are instead expected to be deductible in 2017 under IRC Section 165. The Company received a favorable PLR from the IRS stating the Company has a valid tax deduction for abandonment under IRC Section 165. Although the IRS does not verify the amount of the deduction, there is no reserve against these costs. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, Section 41 credits, and certain unrecognized state tax benefits.

As of December 31, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $106 million ($38 million net of the impact of state deductions on federal returns, net of NOL and credit carryforwards, and net of receivables related to the uncertain tax positions). If recognized, $106 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. Due to the merger with Dominion Energy, it is reasonably possible that these unrecognized tax benefits could increase within the next 12 months, although such increase cannot be reasonably estimated. It is reasonably possible that these unrecognized tax benefits may decrease by $11 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through December 31, 2018.

The Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses. Amounts recorded for such interest income, interest expense or tax penalties have not been material for any period presented.

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DERIVATIVE FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2018

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

.DERIVATIVE FINANCIAL INSTRUMENTS

Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

Policies and procedures, and in some cases risk limits, are established to control the level of market, credit, liquidity and operational and administrative risks.  Historically, SCANA’s Board of Directors delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries.  The Risk Management Committee, which was comprised of certain officers, apprised the Board of Directors with regard to the management of risk and brought to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the consolidated statements of cash flows.

PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options.  PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging.  PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes.

Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit.

As an accommodation to certain customers, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives.  These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  In cases in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

Forward starting swap agreements designated as cash flow hedges have been used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and its nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G 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 expense or have been applied as otherwise directed by the SCPSC. See Note 2 and Note 15 regarding the settlement gains realized in the first quarter of 2018.

Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.

Quantitative Disclosures Related to Derivatives

The Company was party to natural gas derivative contracts outstanding in the following quantities:

	Commodity and Energy Management Contracts (in bcf)
Hedge designation	Gas Distribution	Gas Marketing	Total
As of December 31, 2018
Commodity	6.4	12.9	19.3
Energy Management (a)	—	46.8	46.8
Total (a)	6.4	59.7	66.1
As of December 31, 2017
Commodity	6.4	13.4	19.8
Energy Management (a)	—	41.9	41.9
Total (a)	6.4	55.3	61.7

(a) Includes amounts related to basis swap contracts totaling 5.1 bcf in 2018 and 2.6 bcf in 2017.

The aggregate notional amounts of the interest rate swaps were as follows:

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	December 31, 2018		December 31, 2017		December 31, 2018		December 31, 2017
Designated as hedging instruments	$	106.8	$	111.2	$	36.4	$	36.4
Not designated as hedging instruments	35.0		735.0		35.0		735.0

The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown.

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of December 31, 2018
Designated as hedging instruments
Interest rate contracts
	Other current liabilities	—		$	2	—		$	1
	Other deferred credits and other liabilities	—		19		—		7
Commodity contracts
	Prepayments	—		1		—		—
Total		—		$	22	—		$	8
Not designated as hedging instruments
Interest rate contracts
	Other deferred credits and other liabilities	—		$	3	—		$	3
Commodity contracts
	Prepayments	$	1	—		—		—
Energy management contracts
	Prepayments	11		12		—		—
	Other current assets	1		—		—		—
	Other current liabilities	—		1		—		—
	Other deferred debits and other assets	1		—		—		—
Total		$	14	$	16	—		$	3
As of December 31, 2017
Designated as hedging instruments
Interest rate contracts
	Other current liabilities	—		$	3	—		$	1
	Other deferred credits and other liabilities	—		24		—		9
Commodity contracts
	Prepayments	—		2		—		—
	Other current liabilities	—		1		—		—
Total		—		$	30	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets and current liabilities	$	54	$	1	$	54	$	1
	Other deferred credits and other liabilities	—		4		—		4
Commodity contracts
	Other current assets	1		—		—		—
Energy management contracts
	Prepayments	—		1		—		—
	Other current assets	3		—		—		—
	Other deferred debits and other assets	1		—		—		—
	Other current liabilities	—		2		—		—
Total		$	59	$	8	$	54	$	5

Derivatives Designated as Fair Value Hedges

The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented.

Derivatives in Cash Flow Hedging Relationships

The effect of derivative instruments on the consolidated statements of operations is as follows: 

The Company and Consolidated SCE&G:	Gain (Loss) Deferred in Regulatory Accounts			Loss Reclassified from Deferred Accounts into Income (Effective Portion)
Millions of dollars	(Effective Portion)			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	1		Interest expense	$	(1	)
Year Ended December 31, 2017
Interest rate contracts	$	(2	)	Interest expense	$	(2	)
Year Ended December 31, 2016
Interest rate contracts	—			Interest expense	$	(2	)

The Company:	Gain (Loss) Recognized in OCI, net of tax			Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion)
Millions of dollars	(Effective Portion)			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	1		Interest expense	$	(9	)
Commodity contracts	(3		)	Gas purchased for resale	(7		)
Total	$	(2	)		$	(16	)
Year Ended December 31, 2017
Interest rate contracts	—			Interest expense	$	(7	)
Commodity contracts	$	(7	)	Gas purchased for resale	1
Total	$	(7	)		$	(6	)
Year Ended December 31, 2016
Interest rate contracts	$	(1	)	Interest expense	$	(7	)
Commodity contracts	5			Gas purchased for resale	(6		)
Total	$	4			$	(13	)

As of December 31, 2018, the Company expects that during the next 12 months reclassifications from AOCI (loss) to earnings arising from cash flow hedges will include approximately $0.6 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $8.7 million as an increase to interest expense. Reclassifications related to commodity and energy management contracts are not expected to be significant. All of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2021.

As of December 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $0.9 million as an increase as an increase to interest expense.

Hedge Ineffectiveness

For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant for all periods presented.

Derivatives Not Designated as Hedging Instruments

The Company and Consolidated SCE&G:	Gain (Loss) Deferred in			Gain (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	Regulatory Accounts			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	64		Interest Expense	$	(2	)
Interest rate contracts				Other Income	115
Year Ended December 31, 2017
Interest rate contracts	$	(32	)	Interest Expense	$	(3	)
Interest rate contracts				Impairment Loss	(173		)
Year Ended December 31, 2016
Interest rate contracts	$	(34	)	Other income	$	(2	)

Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. Loss reclassified to impairment loss is included in the 2017 impairment described in Note 11.

As of December 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $2.8 million as an increase to interest expense.

Credit Risk Considerations

Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral.

Derivative Contracts with Credit Contingent Features

	The Company				Consolidated SCE&G
Millions of dollars	December 31, 2018		December 31, 2017		December 31, 2018		December 31, 2017
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	24.8	$	33.7	$	11.2	$	14.7
Fair value of collateral already posted	24.3		28.9		11.0		10.1
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	0.5	$	4.8	$	0.2	$	4.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position	—		$	53.5	—		$	53.5
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	—		$	53.5	—		$	53.5

In addition, at December 31, 2018, the Company could not call on any letters of credit related to the $1.7 million in commodity derivatives that are in a net asset position. At December 31, 2017, the Company could have called on letters of credit in the amount of $1.2 million related to derivatives of $4.0 million if all the contingent features underlying these instruments had been fully triggered.

Information related to the offsetting derivative assets follows:

Derivative Assets	The Company										Consolidated SCE&G
Millions of dollars	Interest Rate Contracts		Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2018
Gross Amounts of Recognized Assets	—		$	1	$	13		$	14		—
Gross Amounts Offset in Statement of Financial Position	—		—		(11		)	(11		)	—
Net Amounts Presented in Statement of Financial Position	—		1		2			3			—
Gross Amounts Not Offset - Financial Instruments	—		—		—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—			—			—
Net Amount	—		$	1	$	2		$	3		—
Balance sheet location
Prepayments								$	12		—
Other current assets								1			—
Other deferred debits and other assets								1			—
Total								$	14		—
As of December 31, 2017
Gross Amounts of Recognized Assets	$	54	$	1	$	4		$	59		$	54
Gross Amounts Offset in Statement of Financial Position	—		—		—			—			—
Net Amounts Presented in Statement of Financial Position	54		1		4			59			54
Gross Amounts Not Offset - Financial Instruments	—		—		—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—			—			—
Net Amount	$	54	$	1	$	4		$	59		$	54
Balance sheet location
Other current assets								$	58		$	54
Other deferred debits and other assets								1			—
Total								$	59		$	54

Information related to the offsetting of derivative liabilities follows:

Derivative Liabilities	The Company											Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2018
Gross Amounts of Recognized Liabilities	$	24		$	1	$	13		$	38		$	11
Gross Amounts Offset in Statement of Financial Position	—			—		(11		)	(11		)	—
Net Amounts Presented in Statement of Financial Position	24			1		2			27			11
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(24		)	—		—			(24		)	(11		)
Net Amount	—			$	1	$	2		$	3		—
Balance sheet location
Prepayments									$	13		—
Other current liabilities									3			$	1
Other deferred credits and other liabilities									22			10
Total									$	38		$	11

Derivative Liabilities	The Company											Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2017
Gross Amounts of Recognized Liabilities	$	32		$	3	$	3		$	38		$	15
Gross Amounts Offset in Statement of Financial Position	—			—		(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	32			3		2			37			15
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(28		)	—		(1		)	(29		)	—
Net Amount	$	4		3		$	1		$	8		$	15
Balance sheet location
Other current assets									$	2		—
Other current liabilities									7			$	2
Other deferred credits and other liabilities									28			13
Total									$	37		$	15

SCE&G

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

.DERIVATIVE FINANCIAL INSTRUMENTS

Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

Policies and procedures, and in some cases risk limits, are established to control the level of market, credit, liquidity and operational and administrative risks.  Historically, SCANA’s Board of Directors delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries.  The Risk Management Committee, which was comprised of certain officers, apprised the Board of Directors with regard to the management of risk and brought to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the consolidated statements of cash flows.

PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options.  PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging.  PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes.

Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit.

As an accommodation to certain customers, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives.  These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  In cases in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

Forward starting swap agreements designated as cash flow hedges have been used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and its nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G 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 expense or have been applied as otherwise directed by the SCPSC. See Note 2 and Note 15 regarding the settlement gains realized in the first quarter of 2018.

Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.

Quantitative Disclosures Related to Derivatives

The Company was party to natural gas derivative contracts outstanding in the following quantities:

	Commodity and Energy Management Contracts (in bcf)
Hedge designation	Gas Distribution	Gas Marketing	Total
As of December 31, 2018
Commodity	6.4	12.9	19.3
Energy Management (a)	—	46.8	46.8
Total (a)	6.4	59.7	66.1
As of December 31, 2017
Commodity	6.4	13.4	19.8
Energy Management (a)	—	41.9	41.9
Total (a)	6.4	55.3	61.7

(a) Includes amounts related to basis swap contracts totaling 5.1 bcf in 2018 and 2.6 bcf in 2017.

The aggregate notional amounts of the interest rate swaps were as follows:

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	December 31, 2018		December 31, 2017		December 31, 2018		December 31, 2017
Designated as hedging instruments	$	106.8	$	111.2	$	36.4	$	36.4
Not designated as hedging instruments	35.0		735.0		35.0		735.0

The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown.

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of December 31, 2018
Designated as hedging instruments
Interest rate contracts
	Other current liabilities	—		$	2	—		$	1
	Other deferred credits and other liabilities	—		19		—		7
Commodity contracts
	Prepayments	—		1		—		—
Total		—		$	22	—		$	8
Not designated as hedging instruments
Interest rate contracts
	Other deferred credits and other liabilities	—		$	3	—		$	3
Commodity contracts
	Prepayments	$	1	—		—		—
Energy management contracts
	Prepayments	11		12		—		—
	Other current assets	1		—		—		—
	Other current liabilities	—		1		—		—
	Other deferred debits and other assets	1		—		—		—
Total		$	14	$	16	—		$	3
As of December 31, 2017
Designated as hedging instruments
Interest rate contracts
	Other current liabilities	—		$	3	—		$	1
	Other deferred credits and other liabilities	—		24		—		9
Commodity contracts
	Prepayments	—		2		—		—
	Other current liabilities	—		1		—		—
Total		—		$	30	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets and current liabilities	$	54	$	1	$	54	$	1
	Other deferred credits and other liabilities	—		4		—		4
Commodity contracts
	Other current assets	1		—		—		—
Energy management contracts
	Prepayments	—		1		—		—
	Other current assets	3		—		—		—
	Other deferred debits and other assets	1		—		—		—
	Other current liabilities	—		2		—		—
Total		$	59	$	8	$	54	$	5

Derivatives Designated as Fair Value Hedges

The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented.

Derivatives in Cash Flow Hedging Relationships

The effect of derivative instruments on the consolidated statements of operations is as follows: 

The Company and Consolidated SCE&G:	Gain (Loss) Deferred in Regulatory Accounts			Loss Reclassified from Deferred Accounts into Income (Effective Portion)
Millions of dollars	(Effective Portion)			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	1		Interest expense	$	(1	)
Year Ended December 31, 2017
Interest rate contracts	$	(2	)	Interest expense	$	(2	)
Year Ended December 31, 2016
Interest rate contracts	—			Interest expense	$	(2	)

The Company:	Gain (Loss) Recognized in OCI, net of tax			Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion)
Millions of dollars	(Effective Portion)			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	1		Interest expense	$	(9	)
Commodity contracts	(3		)	Gas purchased for resale	(7		)
Total	$	(2	)		$	(16	)
Year Ended December 31, 2017
Interest rate contracts	—			Interest expense	$	(7	)
Commodity contracts	$	(7	)	Gas purchased for resale	1
Total	$	(7	)		$	(6	)
Year Ended December 31, 2016
Interest rate contracts	$	(1	)	Interest expense	$	(7	)
Commodity contracts	5			Gas purchased for resale	(6		)
Total	$	4			$	(13	)

As of December 31, 2018, the Company expects that during the next 12 months reclassifications from AOCI (loss) to earnings arising from cash flow hedges will include approximately $0.6 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $8.7 million as an increase to interest expense. Reclassifications related to commodity and energy management contracts are not expected to be significant. All of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2021.

As of December 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $0.9 million as an increase as an increase to interest expense.

Hedge Ineffectiveness

For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant for all periods presented.

Derivatives Not Designated as Hedging Instruments

The Company and Consolidated SCE&G:	Gain (Loss) Deferred in			Gain (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	Regulatory Accounts			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	64		Interest Expense	$	(2	)
Interest rate contracts				Other Income	115
Year Ended December 31, 2017
Interest rate contracts	$	(32	)	Interest Expense	$	(3	)
Interest rate contracts				Impairment Loss	(173		)
Year Ended December 31, 2016
Interest rate contracts	$	(34	)	Other income	$	(2	)

Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. Loss reclassified to impairment loss is included in the 2017 impairment described in Note 11.

As of December 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $2.8 million as an increase to interest expense.

Credit Risk Considerations

Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral.

Derivative Contracts with Credit Contingent Features

	The Company				Consolidated SCE&G
Millions of dollars	December 31, 2018		December 31, 2017		December 31, 2018		December 31, 2017
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	24.8	$	33.7	$	11.2	$	14.7
Fair value of collateral already posted	24.3		28.9		11.0		10.1
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	0.5	$	4.8	$	0.2	$	4.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position	—		$	53.5	—		$	53.5
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	—		$	53.5	—		$	53.5

In addition, at December 31, 2018, the Company could not call on any letters of credit related to the $1.7 million in commodity derivatives that are in a net asset position. At December 31, 2017, the Company could have called on letters of credit in the amount of $1.2 million related to derivatives of $4.0 million if all the contingent features underlying these instruments had been fully triggered.

Information related to the offsetting derivative assets follows:

Derivative Assets	The Company										Consolidated SCE&G
Millions of dollars	Interest Rate Contracts		Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2018
Gross Amounts of Recognized Assets	—		$	1	$	13		$	14		—
Gross Amounts Offset in Statement of Financial Position	—		—		(11		)	(11		)	—
Net Amounts Presented in Statement of Financial Position	—		1		2			3			—
Gross Amounts Not Offset - Financial Instruments	—		—		—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—			—			—
Net Amount	—		$	1	$	2		$	3		—
Balance sheet location
Prepayments								$	12		—
Other current assets								1			—
Other deferred debits and other assets								1			—
Total								$	14		—
As of December 31, 2017
Gross Amounts of Recognized Assets	$	54	$	1	$	4		$	59		$	54
Gross Amounts Offset in Statement of Financial Position	—		—		—			—			—
Net Amounts Presented in Statement of Financial Position	54		1		4			59			54
Gross Amounts Not Offset - Financial Instruments	—		—		—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—			—			—
Net Amount	$	54	$	1	$	4		$	59		$	54
Balance sheet location
Other current assets								$	58		$	54
Other deferred debits and other assets								1			—
Total								$	59		$	54

Information related to the offsetting of derivative liabilities follows:

Derivative Liabilities	The Company											Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2018
Gross Amounts of Recognized Liabilities	$	24		$	1	$	13		$	38		$	11
Gross Amounts Offset in Statement of Financial Position	—			—		(11		)	(11		)	—
Net Amounts Presented in Statement of Financial Position	24			1		2			27			11
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(24		)	—		—			(24		)	(11		)
Net Amount	—			$	1	$	2		$	3		—
Balance sheet location
Prepayments									$	13		—
Other current liabilities									3			$	1
Other deferred credits and other liabilities									22			10
Total									$	38		$	11

Derivative Liabilities	The Company											Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2017
Gross Amounts of Recognized Liabilities	$	32		$	3	$	3		$	38		$	15
Gross Amounts Offset in Statement of Financial Position	—			—		(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	32			3		2			37			15
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(28		)	—		(1		)	(29		)	—
Net Amount	$	4		3		$	1		$	8		$	15
Balance sheet location
Other current assets									$	2		—
Other current liabilities									7			$	2
Other deferred credits and other liabilities									28			13
Total									$	37		$	15

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

12 Months Ended

Dec. 31, 2018

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Disclosures [Text Block]

.             FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

The Company and Consolidated SCE&G value available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, on which the securities are actively traded or are open-ended mutual funds registered with the SEC and maintain a stable NAV and are invested in government money market agreements or fully collateralized repurchase agreements. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

	As of December 31, 2018							As of December 31, 2017
	The Company				Consolidated SCE&G			The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 1	Level 2		Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	—		—		—	—		$	119	—		$	100	—
Held to maturity securities	—		$	6	—	—		—		$	6	—		—
Interest rate contracts	—		—		—	—		—		54		—		$	54
Commodity contracts	$	1	—		—	—		1		—		—		—
Energy management contracts	11		2		—	—		—		4		—		—
Liabilities:
Interest rate contracts	—		24		—	$	11	—		32		—		15
Commodity contracts	1		—		—	—		2		1		—		—
Energy management contracts	12		3		—	—		1		4		—		—

The Company and Consolidated SCE&G had no Level 3 fair value measurements during either period presented.

Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2018 and December 31, 2017 were as follows:

	As of December 31, 2018				As of December 31, 2017
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,753.9	$	7,180.8	$	6,632.9	$	7,399.7
Consolidated SCE&G	5,145.6		5,469.7		5,163.3		5,790.3

 Fair values of long-term debt instruments are 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. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent.

Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.

In connection with the impairment loss described in Note 11, the Company and Consolidated SCE&G determined that the fair value of certain of their nuclear fuel was lower than its carrying amount. At December 31, 2018, this nuclear fuel had an estimated fair value of $40.2 million. This estimate is based on quoted prices received from vendors of nuclear fuel, which are considered to be Level 3 fair value measurements. The Company and Consolidated SCE&G assess the fair value of nuclear fuel in connection with the analysis of impairment described in Note 11 on a quarterly basis.

SCE&G

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Disclosures [Text Block]

.             FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

The Company and Consolidated SCE&G value available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, on which the securities are actively traded or are open-ended mutual funds registered with the SEC and maintain a stable NAV and are invested in government money market agreements or fully collateralized repurchase agreements. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

	As of December 31, 2018							As of December 31, 2017
	The Company				Consolidated SCE&G			The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 1	Level 2		Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	—		—		—	—		$	119	—		$	100	—
Held to maturity securities	—		$	6	—	—		—		$	6	—		—
Interest rate contracts	—		—		—	—		—		54		—		$	54
Commodity contracts	$	1	—		—	—		1		—		—		—
Energy management contracts	11		2		—	—		—		4		—		—
Liabilities:
Interest rate contracts	—		24		—	$	11	—		32		—		15
Commodity contracts	1		—		—	—		2		1		—		—
Energy management contracts	12		3		—	—		1		4		—		—

The Company and Consolidated SCE&G had no Level 3 fair value measurements during either period presented.

Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2018 and December 31, 2017 were as follows:

	As of December 31, 2018				As of December 31, 2017
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,753.9	$	7,180.8	$	6,632.9	$	7,399.7
Consolidated SCE&G	5,145.6		5,469.7		5,163.3		5,790.3

 Fair values of long-term debt instruments are 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. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent.

Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.

In connection with the impairment loss described in Note 11, the Company and Consolidated SCE&G determined that the fair value of certain of their nuclear fuel was lower than its carrying amount. At December 31, 2018, this nuclear fuel had an estimated fair value of $40.2 million. This estimate is based on quoted prices received from vendors of nuclear fuel, which are considered to be Level 3 fair value measurements. The Company and Consolidated SCE&G assess the fair value of nuclear fuel in connection with the analysis of impairment described in Note 11 on a quarterly basis.

XML

EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2018

Pension and Other Postretirement Benefit Plans

Pension and Other Postretirement Benefits Disclosure [Text Block]

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. SCE&G 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. SCE&G 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.

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.

	The Company												Consolidated SCE&G
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017			2018			2017			2018			2017
Benefit obligation, January 1	$	933.2		$	904.3		$	289.2		$	274.7		$	793.0		$	768.4		$	216.6		$	207.2
Service cost	21.0			21.7			4.6			4.5			17.1			18.1			3.6			3.7
Interest cost	34.1			37.4			10.1			11.5			29.0			31.9			8.0			9.5
Plan participants’ contributions	—			—			1.4			1.3			—			—			1.1			1.1
Actuarial (gain) loss	(53.1		)	42.2			(38.4		)	9.7			(45.5		)	36.6			(30.7		)	6.8
Benefits paid	(71.7		)	(72.4		)	(13.2		)	(12.5		)	(61.3		)	(62.0		)	(10.4		)	(10.3		)
Amounts funded to parent	n/a			n/a			n/a			n/a			—			—			(0.8		)	(1.4		)
Benefit obligation, December 31	$	863.5		$	933.2		$	253.7		$	289.2		$	732.3		$	793.0		$	187.4		$	216.6

The accumulated benefit obligation for pension benefits for the Company was $842.4 million at the end of 2018 and $905.8 million at the end of 2017. The accumulated benefit obligation for pension benefits for Consolidated SCE&G was $714.3 million at the end of 2018 and $769.7 million at the end of 2017. 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
	2018		2017		2018		2017
Annual discount rate used to determine benefit obligation	4.35	%	3.71	%	4.38	%	3.74	%
Assumed annual rate of future salary increases for projected benefit obligation	3.00	%	3.00	%	3.00	%	3.00	%

A 6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018. 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 the Company would increase the postretirement benefit obligation by $0.7 million at December 31, 2018 and by $1.6 million at December 31, 2017. A one percent decrease in the assumed health care cost trend rate for the Company would decrease the postretirement benefit obligation by $0.6 million at December 31, 2018 and by $1.4 million at December 31, 2017. A one percent increase in the assumed health care cost trend rate for Consolidated SCE&G would increase the postretirement benefit obligation by $0.6 million at December 31, 2018 and by $1.3 million at December 31, 2017. A one percent decrease in the assumed health care cost trend rate for Consolidated SCE&G would decrease the postretirement benefit obligation by $0.5 million at December 31, 2018 and by $1.1 million at December 31, 2017.

Funded Status

	The Company												Consolidated SCE&G
Millions of Dollars	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
December 31,	2018			2017			2018			2017			2018			2017			2018			2017
Fair value of plan assets	$	727.3		$	849.6		—			—			$	676.7		$	781.3		—			—
Benefit obligation	863.5			933.2			$	253.7		$	289.2		732.3			793.0			$	187.4		$	216.6
Funded status	$	(136.2	)	$	(83.6	)	$	(253.7	)	$	(289.2	)	$	(55.6	)	$	(11.7	)	$	(187.4	)	$	(216.6	)

Amounts recognized on the consolidated balance sheets were as follows:

	The Company												Consolidated SCE&G
Millions of Dollars	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
December 31,	2018			2017			2018			2017			2018			2017			2018			2017
Current liability	—			—			$	(13.3	)	$	(13.5	)	—			—			$	(10.5	)	$	(10.8	)
Noncurrent liability	$	(136.2	)	$	(83.6	)	(240.4		)	(275.7		)	$	(55.6	)	$	(11.7	)	(176.9		)	(205.8		)

Amounts recognized in accumulated other comprehensive loss were as follows:

	The Company								Consolidated SCE&G
Millions of Dollars	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
December 31,	2018		2017		2018		2017		2018		2017		2018		2017
Net actuarial loss	$	12.8	$	8.8	$	1.1	$	3.5	$	3.4	$	2.1	$	0.5	$	1.5
Prior service cost	0.1		0.1		—		—		—		—		—		—
Total	$	12.9	$	8.9	$	1.1	$	3.5	$	3.4	$	2.1	$	0.5	$	1.5

Amounts recognized in regulatory assets were as follows:

	The Company								Consolidated SCE&G
Millions of Dollars	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
December 31,	2018		2017		2018		2017		2018		2017		2018		2017
Net actuarial loss	$	230.4	$	194.8	$	10.9	$	43.3	$	202.4	$	171.4	$	9.0	$	35.9
Prior service cost	0.7		1.2		—		—		0.6		1.0		—		—
Total	$	231.1	$	196.0	$	10.9	$	43.3	$	203.0	$	172.4	$	9.0	$	35.9

In connection with the joint ownership of Summer Station, costs related to the pension benefit obligation attributable to Santee Cooper as of December 31, 2018 and 2017 totaled $24.9 million and $21.4 million, respectively, and were recorded within deferred debits. The unfunded postretirement benefit obligation attributable to Santee Cooper as of December 31, 2018 and 2017 totaled $12.4 million and $14.7 million, respectively, and was recorded within deferred debits.

Changes in Fair Value of Plan Assets

Pension Benefits	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Fair value of plan assets, January 1	$	849.6		$	793.6		$	781.3		$	732.9
Actual return (loss) on plan assets	(50.6		)	128.4			(43.3		)	110.4
Benefits paid	(71.7		)	(72.4		)	(61.3		)	(62.0		)
Fair value of plan assets, December 31	$	727.3		$	849.6		$	676.7		$	781.3

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. SCANA 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, 2018 and 2017 and the target allocation for 2019 are as follows: 

	Percentage of Plan Assets
	Target Allocation		December 31,
Asset Category	2019		2018		2017
Equity Securities	58	%	55	%	58	%
Fixed Income	33	%	34	%	31	%
Hedge Funds	9	%	11	%	11	%

For 2019, 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, 2018 and 2017, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Investments with fair value measure at Level 2:
Mutual funds	$	107	$	120	$	99	$	110
Short-term investment vehicles	20		17		19		16
US Treasury securities	7		15		7		14
Corporate debt instruments	92		91		86		84
Government and other debt instruments	18		17		16		15
Total assets in the fair value hierarchy	244		260		227		239
Investments at net asset value:
Common collective trust	400		498		373		458
Joint venture interests	83		92		77		84
Total investments at fair value	$	727	$	850	$	677	$	781

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 2018 or 2017.

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

	The Company				Consolidated SCE&G
Millions of dollars	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
2019	$	71.5	$	13.6	$	71.5	$	10.8
2020	62.4		14.3		62.4		11.4
2021	65.6		14.9		65.6		11.8
2022	69.6		15.4		69.6		12.2
2023	66.6		15.8		66.6		12.6
2024-2028	284.9		82.3		284.9		65.4

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

The Company	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018		2017		2016
Service cost	$	21.0		$	21.7		$	20.7		$	4.6	$	4.5	$	4.4
Interest cost	34.1			37.4			39.4			10.1		11.5		12.1
Expected return on assets	(56.7		)	(54.7		)	(55.9		)	n/a		n/a		n/a
Prior service cost amortization	0.5			1.6			3.9			—		—		0.3
Amortization of actuarial losses	12.8			16.3			14.8			0.7		1.0		0.5
Net periodic benefit cost	$	11.7		$	22.3		$	22.9		$	15.4	$	17.0	$	17.3

Consolidated SCE&G	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018		2017		2016
Service cost	$	17.1		$	18.1		$	16.9		$	3.6	$	3.7	$	3.6
Interest cost	29.0			31.9			33.4			8.0		9.5		9.9
Expected return on assets	(48.1		)	(46.7		)	(47.4		)	n/a		n/a		n/a
Prior service cost amortization	0.4			1.4			3.4			—		—		0.3
Amortization of actuarial losses	10.9			13.9			12.5			0.6		0.8		0.4
Net periodic benefit cost	$	9.3		$	18.6		$	18.8		$	12.2	$	14.0	$	14.2

In connection with regulatory orders, SCE&G 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. PSNC Energy recovers pension costs through cost of service rates. 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, SCE&G amortizes certain previously deferred pension costs. See Note 2.

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

The Company	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017			2016
Current year actuarial (gain) loss	$	4.5		$	(1.0	)	$	0.6		$	(2.4	)	$	1.1		$	0.8
Amortization of actuarial losses	(0.5		)	(0.6		)	(0.6		)	—			(0.1		)	—
Amortization of prior service cost	—			—			(0.1		)	—			—			—
Total recognized in OCI	$	4.0		$	(1.6	)	$	(0.1	)	$	(2.4	)	$	1.0		$	0.8

Consolidated SCE&G	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017		2016
Current year actuarial loss	$	1.4		$	0.3		—			$	(1.0	)	$	0.5	$	0.3
Amortization of actuarial losses	(0.1		)	(0.1		)	$	(0.1	)	—			—		—
Total recognized in OCI	$	1.3		$	0.2		$	(0.1	)	$	(1.0	)	$	0.5	$	0.3

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

The Company	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017			2016
Current year actuarial (gain) loss	$	46.7		$	(27.1	)	$	29.4		$	(31.8	)	$	9.4		$	11.1
Amortization of actuarial losses	(11.1		)	(14.1		)	(12.7		)	(0.6		)	(0.8		)	(0.4		)
Amortization of prior service cost	(0.5		)	(1.4		)	(3.4		)	—			—			(0.3		)
Total recognized in regulatory assets	$	35.1		$	(42.6	)	$	13.3		$	(32.4	)	$	8.6		$	10.4

Consolidated SCE&G	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017			2016
Current year actuarial (gain) loss	$	40.7		$	(24.8	)	$	26.3		$	(26.4	)	$	7.3		$	9.2
Amortization of actuarial losses	(9.7		)	(12.5		)	(11.2		)	(0.5		)	(0.7		)	(0.3		)
Amortization of prior service cost	(0.4		)	(1.3		)	(3.0		)	—			—			(0.2		)
Total recognized in regulatory assets	$	30.6		$	(38.6	)	$	12.1		$	(26.9	)	$	6.6		$	8.7

Significant Assumptions Used in Determining Net Periodic Benefit Cost

	Pension Benefits						Other Postretirement Benefits
	2018		2017		2016		2018		2017		2016
Discount rate	3.71	%	4.22	%	4.68	%	3.74	%	4.30	%	4.78	%
Expected return on plan assets	7.00	%	7.25	%	7.50	%	n/a		n/a		n/a
Rate of compensation increase	3.00	%	3.00	%	3.00	%	3.00	%	3.00	%	3.00	%
Health care cost trend rate	n/a		n/a		n/a		7.00	%	6.60	%	7.00	%
Ultimate health care cost trend rate	n/a		n/a		n/a		5.00	%	5.00	%	5.00	%
Year achieved	n/a		n/a		n/a		2023		2021		2021

The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2019 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant:

Millions of Dollars	Pension Benefits		Other Postretirement Benefits
Actuarial loss	$	0.8	—

The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2019 are as follows:

	The Company			Consolidated SCE&G
Millions of Dollars	Pension Benefits		Other Postretirement Benefits	Pension Benefits		Other Postretirement Benefits
Actuarial loss	$	14.7	—	$	12.9	—
Prior service cost	0.3		—	0.3		—
Total	$	15.0	—	$	13.2	—

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. SCE&G participates in this plan. Contributions are matched 100% up to 6% of an employee’s eligible earnings. Such matching contributions made by the Company totaled $24.1 million in 2018, $27.9 million in 2017 and $27.5 million in 2016. These matching contributions included those made by Consolidated SCE&G, which totaled $19.6 million in 2018, $23.4 million in 2017 and $22.9 million in 2016. Employee deferrals, matching contributions, and earnings on all contributions are fully vested and non-forfeitable at all times.

SCE&G

Pension and Other Postretirement Benefit Plans

Pension and Other Postretirement Benefits Disclosure [Text Block]

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. SCE&G 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. SCE&G 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.

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.

	The Company												Consolidated SCE&G
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017			2018			2017			2018			2017
Benefit obligation, January 1	$	933.2		$	904.3		$	289.2		$	274.7		$	793.0		$	768.4		$	216.6		$	207.2
Service cost	21.0			21.7			4.6			4.5			17.1			18.1			3.6			3.7
Interest cost	34.1			37.4			10.1			11.5			29.0			31.9			8.0			9.5
Plan participants’ contributions	—			—			1.4			1.3			—			—			1.1			1.1
Actuarial (gain) loss	(53.1		)	42.2			(38.4		)	9.7			(45.5		)	36.6			(30.7		)	6.8
Benefits paid	(71.7		)	(72.4		)	(13.2		)	(12.5		)	(61.3		)	(62.0		)	(10.4		)	(10.3		)
Amounts funded to parent	n/a			n/a			n/a			n/a			—			—			(0.8		)	(1.4		)
Benefit obligation, December 31	$	863.5		$	933.2		$	253.7		$	289.2		$	732.3		$	793.0		$	187.4		$	216.6

The accumulated benefit obligation for pension benefits for the Company was $842.4 million at the end of 2018 and $905.8 million at the end of 2017. The accumulated benefit obligation for pension benefits for Consolidated SCE&G was $714.3 million at the end of 2018 and $769.7 million at the end of 2017. 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
	2018		2017		2018		2017
Annual discount rate used to determine benefit obligation	4.35	%	3.71	%	4.38	%	3.74	%
Assumed annual rate of future salary increases for projected benefit obligation	3.00	%	3.00	%	3.00	%	3.00	%

A 6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018. 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 the Company would increase the postretirement benefit obligation by $0.7 million at December 31, 2018 and by $1.6 million at December 31, 2017. A one percent decrease in the assumed health care cost trend rate for the Company would decrease the postretirement benefit obligation by $0.6 million at December 31, 2018 and by $1.4 million at December 31, 2017. A one percent increase in the assumed health care cost trend rate for Consolidated SCE&G would increase the postretirement benefit obligation by $0.6 million at December 31, 2018 and by $1.3 million at December 31, 2017. A one percent decrease in the assumed health care cost trend rate for Consolidated SCE&G would decrease the postretirement benefit obligation by $0.5 million at December 31, 2018 and by $1.1 million at December 31, 2017.

Funded Status

	The Company												Consolidated SCE&G
Millions of Dollars	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
December 31,	2018			2017			2018			2017			2018			2017			2018			2017
Fair value of plan assets	$	727.3		$	849.6		—			—			$	676.7		$	781.3		—			—
Benefit obligation	863.5			933.2			$	253.7		$	289.2		732.3			793.0			$	187.4		$	216.6
Funded status	$	(136.2	)	$	(83.6	)	$	(253.7	)	$	(289.2	)	$	(55.6	)	$	(11.7	)	$	(187.4	)	$	(216.6	)

Amounts recognized on the consolidated balance sheets were as follows:

	The Company												Consolidated SCE&G
Millions of Dollars	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
December 31,	2018			2017			2018			2017			2018			2017			2018			2017
Current liability	—			—			$	(13.3	)	$	(13.5	)	—			—			$	(10.5	)	$	(10.8	)
Noncurrent liability	$	(136.2	)	$	(83.6	)	(240.4		)	(275.7		)	$	(55.6	)	$	(11.7	)	(176.9		)	(205.8		)

Amounts recognized in accumulated other comprehensive loss were as follows:

	The Company								Consolidated SCE&G
Millions of Dollars	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
December 31,	2018		2017		2018		2017		2018		2017		2018		2017
Net actuarial loss	$	12.8	$	8.8	$	1.1	$	3.5	$	3.4	$	2.1	$	0.5	$	1.5
Prior service cost	0.1		0.1		—		—		—		—		—		—
Total	$	12.9	$	8.9	$	1.1	$	3.5	$	3.4	$	2.1	$	0.5	$	1.5

Amounts recognized in regulatory assets were as follows:

	The Company								Consolidated SCE&G
Millions of Dollars	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
December 31,	2018		2017		2018		2017		2018		2017		2018		2017
Net actuarial loss	$	230.4	$	194.8	$	10.9	$	43.3	$	202.4	$	171.4	$	9.0	$	35.9
Prior service cost	0.7		1.2		—		—		0.6		1.0		—		—
Total	$	231.1	$	196.0	$	10.9	$	43.3	$	203.0	$	172.4	$	9.0	$	35.9

In connection with the joint ownership of Summer Station, costs related to the pension benefit obligation attributable to Santee Cooper as of December 31, 2018 and 2017 totaled $24.9 million and $21.4 million, respectively, and were recorded within deferred debits. The unfunded postretirement benefit obligation attributable to Santee Cooper as of December 31, 2018 and 2017 totaled $12.4 million and $14.7 million, respectively, and was recorded within deferred debits.

Changes in Fair Value of Plan Assets

Pension Benefits	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Fair value of plan assets, January 1	$	849.6		$	793.6		$	781.3		$	732.9
Actual return (loss) on plan assets	(50.6		)	128.4			(43.3		)	110.4
Benefits paid	(71.7		)	(72.4		)	(61.3		)	(62.0		)
Fair value of plan assets, December 31	$	727.3		$	849.6		$	676.7		$	781.3

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. SCANA 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, 2018 and 2017 and the target allocation for 2019 are as follows: 

	Percentage of Plan Assets
	Target Allocation		December 31,
Asset Category	2019		2018		2017
Equity Securities	58	%	55	%	58	%
Fixed Income	33	%	34	%	31	%
Hedge Funds	9	%	11	%	11	%

For 2019, 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, 2018 and 2017, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Investments with fair value measure at Level 2:
Mutual funds	$	107	$	120	$	99	$	110
Short-term investment vehicles	20		17		19		16
US Treasury securities	7		15		7		14
Corporate debt instruments	92		91		86		84
Government and other debt instruments	18		17		16		15
Total assets in the fair value hierarchy	244		260		227		239
Investments at net asset value:
Common collective trust	400		498		373		458
Joint venture interests	83		92		77		84
Total investments at fair value	$	727	$	850	$	677	$	781

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 2018 or 2017.

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

	The Company				Consolidated SCE&G
Millions of dollars	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
2019	$	71.5	$	13.6	$	71.5	$	10.8
2020	62.4		14.3		62.4		11.4
2021	65.6		14.9		65.6		11.8
2022	69.6		15.4		69.6		12.2
2023	66.6		15.8		66.6		12.6
2024-2028	284.9		82.3		284.9		65.4

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

The Company	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018		2017		2016
Service cost	$	21.0		$	21.7		$	20.7		$	4.6	$	4.5	$	4.4
Interest cost	34.1			37.4			39.4			10.1		11.5		12.1
Expected return on assets	(56.7		)	(54.7		)	(55.9		)	n/a		n/a		n/a
Prior service cost amortization	0.5			1.6			3.9			—		—		0.3
Amortization of actuarial losses	12.8			16.3			14.8			0.7		1.0		0.5
Net periodic benefit cost	$	11.7		$	22.3		$	22.9		$	15.4	$	17.0	$	17.3

Consolidated SCE&G	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018		2017		2016
Service cost	$	17.1		$	18.1		$	16.9		$	3.6	$	3.7	$	3.6
Interest cost	29.0			31.9			33.4			8.0		9.5		9.9
Expected return on assets	(48.1		)	(46.7		)	(47.4		)	n/a		n/a		n/a
Prior service cost amortization	0.4			1.4			3.4			—		—		0.3
Amortization of actuarial losses	10.9			13.9			12.5			0.6		0.8		0.4
Net periodic benefit cost	$	9.3		$	18.6		$	18.8		$	12.2	$	14.0	$	14.2

In connection with regulatory orders, SCE&G 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. PSNC Energy recovers pension costs through cost of service rates. 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, SCE&G amortizes certain previously deferred pension costs. See Note 2.

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

The Company	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017			2016
Current year actuarial (gain) loss	$	4.5		$	(1.0	)	$	0.6		$	(2.4	)	$	1.1		$	0.8
Amortization of actuarial losses	(0.5		)	(0.6		)	(0.6		)	—			(0.1		)	—
Amortization of prior service cost	—			—			(0.1		)	—			—			—
Total recognized in OCI	$	4.0		$	(1.6	)	$	(0.1	)	$	(2.4	)	$	1.0		$	0.8

Consolidated SCE&G	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017		2016
Current year actuarial loss	$	1.4		$	0.3		—			$	(1.0	)	$	0.5	$	0.3
Amortization of actuarial losses	(0.1		)	(0.1		)	$	(0.1	)	—			—		—
Total recognized in OCI	$	1.3		$	0.2		$	(0.1	)	$	(1.0	)	$	0.5	$	0.3

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

The Company	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017			2016
Current year actuarial (gain) loss	$	46.7		$	(27.1	)	$	29.4		$	(31.8	)	$	9.4		$	11.1
Amortization of actuarial losses	(11.1		)	(14.1		)	(12.7		)	(0.6		)	(0.8		)	(0.4		)
Amortization of prior service cost	(0.5		)	(1.4		)	(3.4		)	—			—			(0.3		)
Total recognized in regulatory assets	$	35.1		$	(42.6	)	$	13.3		$	(32.4	)	$	8.6		$	10.4

Consolidated SCE&G	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017			2016
Current year actuarial (gain) loss	$	40.7		$	(24.8	)	$	26.3		$	(26.4	)	$	7.3		$	9.2
Amortization of actuarial losses	(9.7		)	(12.5		)	(11.2		)	(0.5		)	(0.7		)	(0.3		)
Amortization of prior service cost	(0.4		)	(1.3		)	(3.0		)	—			—			(0.2		)
Total recognized in regulatory assets	$	30.6		$	(38.6	)	$	12.1		$	(26.9	)	$	6.6		$	8.7

Significant Assumptions Used in Determining Net Periodic Benefit Cost

	Pension Benefits						Other Postretirement Benefits
	2018		2017		2016		2018		2017		2016
Discount rate	3.71	%	4.22	%	4.68	%	3.74	%	4.30	%	4.78	%
Expected return on plan assets	7.00	%	7.25	%	7.50	%	n/a		n/a		n/a
Rate of compensation increase	3.00	%	3.00	%	3.00	%	3.00	%	3.00	%	3.00	%
Health care cost trend rate	n/a		n/a		n/a		7.00	%	6.60	%	7.00	%
Ultimate health care cost trend rate	n/a		n/a		n/a		5.00	%	5.00	%	5.00	%
Year achieved	n/a		n/a		n/a		2023		2021		2021

The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2019 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant:

Millions of Dollars	Pension Benefits		Other Postretirement Benefits
Actuarial loss	$	0.8	—

The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2019 are as follows:

	The Company			Consolidated SCE&G
Millions of Dollars	Pension Benefits		Other Postretirement Benefits	Pension Benefits		Other Postretirement Benefits
Actuarial loss	$	14.7	—	$	12.9	—
Prior service cost	0.3		—	0.3		—
Total	$	15.0	—	$	13.2	—

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. SCE&G participates in this plan. Contributions are matched 100% up to 6% of an employee’s eligible earnings. Such matching contributions made by the Company totaled $24.1 million in 2018, $27.9 million in 2017 and $27.5 million in 2016. These matching contributions included those made by Consolidated SCE&G, which totaled $19.6 million in 2018, $23.4 million in 2017 and $22.9 million in 2016. Employee deferrals, matching contributions, and earnings on all contributions are fully vested and non-forfeitable at all times.

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SHARE-BASED COMPENSATION

12 Months Ended

Dec. 31, 2018

Share-Based Compensation

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

SHARE-BASED COMPENSATION

The LTECP provided for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The LTECP authorized the issuance of up to five million shares of SCANA’s common stock, no more than one million of which could be granted in the form of restricted stock.

Compensation cost was measured based on the grant-date fair value of the instruments issued and was recognized over the period that an employee provided service in exchange for the award. Share-based payment awards did not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves did not vest, dividends or dividend equivalents which would have been paid on those awards did not vest.

For all periods presented, performance cycles provided for performance measurement and award determination based on performance over a single three-year cycle, with payment of awards being deferred until after the end of the three-year performance cycle. In each of these performance cycles, 30% of the performance awards were granted in the form of restricted share units, which were liability awards payable in cash, and 70% of the awards were granted in performance shares, each of which had a value equal to, and changed with, the value of a share of SCANA common stock. Dividend equivalents were accrued on the performance shares and the restricted share units. Performance awards and related dividend equivalents were subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to certain exceptions. Payouts of performance share awards were determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50%) and growth in GAAP-adjusted net earnings per share (weighted 50%). 

Compensation cost of liability awards was recognized over their respective three-year performance periods based on the estimated fair value of the award, which was periodically updated based on expected ultimate cash payout, and was reduced by estimated forfeitures. Cash-settled liabilities related to performance cycles totaled approximately $5.5 million in 2018, $28.0 million in 2017 and $18.4 million in 2016 for the Company and approximately $3.5 million in 2018, $20.2 million in 2017 and $13.2 million in 2016 for Consolidated SCE&G.

Fair value adjustments for all performance cycles resulted in compensation expense (benefit) recognized in the statements of operations totaling approximately $(1.7) million in 2018, $(9.0) million in 2017 and $25.6 million in 2016 for the Company and approximately $(0.9) million in 2018, $(6.3) million in 2017 and $17.3 million in 2016 for Consolidated SCE&G (including amounts allocated from SCANA Services). Such fair value adjustments also resulted in no capitalized compensation costs in 2018, $(1.3) million in 2017 and $3.3 million in 2016 for the Company and no capitalized compensation costs in 2018, $(0.9) million in 2017 and $3.1 million in 2016 for Consolidated SCE&G.

In connection with the SCANA Combination, effective January 1, 2019, all grants discussed above were deemed to be vested at their target levels and were converted into the right to receive lump sum amounts based on the value of Dominion Energy stock at that time. As such, additional compensation cost of $28.6 million will be recorded in the first quarter of 2019 as a result of the merger. Related cash-settlement payments totaling $19.6 million were made in January 2019, and further lump sum amounts of $6.7 million and $9.1 million are expected to be paid in 2020 and 2021, respectively, to the extent that those later payments are not accelerated in connection with employee retirements or other separations prior to those dates.

SCE&G

Share-Based Compensation

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

.             SHARE-BASED COMPENSATION

The LTECP provided for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The LTECP authorized the issuance of up to five million shares of SCANA’s common stock, no more than one million of which could be granted in the form of restricted stock.

Compensation cost was measured based on the grant-date fair value of the instruments issued and was recognized over the period that an employee provided service in exchange for the award. Share-based payment awards did not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves did not vest, dividends or dividend equivalents which would have been paid on those awards did not vest.

For all periods presented, performance cycles provided for performance measurement and award determination based on performance over a single three-year cycle, with payment of awards being deferred until after the end of the three-year performance cycle. In each of these performance cycles, 30% of the performance awards were granted in the form of restricted share units, which were liability awards payable in cash, and 70% of the awards were granted in performance shares, each of which had a value equal to, and changed with, the value of a share of SCANA common stock. Dividend equivalents were accrued on the performance shares and the restricted share units. Performance awards and related dividend equivalents were subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to certain exceptions. Payouts of performance share awards were determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50%) and growth in GAAP-adjusted net earnings per share (weighted 50%). 

Compensation cost of liability awards was recognized over their respective three-year performance periods based on the estimated fair value of the award, which was periodically updated based on expected ultimate cash payout, and was reduced by estimated forfeitures. Cash-settled liabilities related to performance cycles totaled approximately $5.5 million in 2018, $28.0 million in 2017 and $18.4 million in 2016 for the Company and approximately $3.5 million in 2018, $20.2 million in 2017 and $13.2 million in 2016 for Consolidated SCE&G.

Fair value adjustments for all performance cycles resulted in compensation expense (benefit) recognized in the statements of operations totaling approximately $(1.7) million in 2018, $(9.0) million in 2017 and $25.6 million in 2016 for the Company and approximately $(0.9) million in 2018, $(6.3) million in 2017 and $17.3 million in 2016 for Consolidated SCE&G (including amounts allocated from SCANA Services). Such fair value adjustments also resulted in no capitalized compensation costs in 2018, $(1.3) million in 2017 and $3.3 million in 2016 for the Company and no capitalized compensation costs in 2018, $(0.9) million in 2017 and $3.1 million in 2016 for Consolidated SCE&G.

In connection with the SCANA Combination, effective January 1, 2019, all grants discussed above were deemed to be vested at their target levels and were converted into the right to receive lump sum amounts based on the value of Dominion Energy stock at that time. As such, additional compensation cost of $28.6 million will be recorded in the first quarter of 2019 as a result of the merger. Related cash-settlement payments totaling $19.6 million were made in January 2019, and further lump sum amounts of $6.7 million and $9.1 million are expected to be paid in 2020 and 2021, respectively, to the extent that those later payments are not accelerated in connection with employee retirements or other separations prior to those dates.

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2018

Commitment [Line Items]

Legal Matters and Contingencies [Text Block]

COMMITMENTS AND CONTINGENCIES

Abandoned Nuclear Project

SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. SCE&G's ownership share in these units 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 and Related Uncertainties below), and were the subject of comprehensive analyses performed by the Company and Santee Cooper.

Based on the results of the Company's analysis, and in light of Santee Cooper's decision to suspend construction on Unit 2 and Unit 3, on July 31, 2017, the Company 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 the Company became the focus of numerous legislative, regulatory and legal proceedings, and led to SCE&G recording pre-tax impairment charges in 2017 totaling approximately $1.118 billion (approximately $690 million net of tax). An additional pre-tax impairment loss was recorded in the first quarter of 2018 of approximately $3.6 million (approximately $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. See further discussion below under Impairment Considerations. These proceedings continued in 2018, and some of them remain unresolved and are described below and/or in Claims and Litigation.

On January 2, 2018, SCANA and Dominion Energy entered into the 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.

Merger Approval Order

On December 21, 2018, the SCPSC issued the Merger Approval Order. The order adopted Dominion Energy's Plan-B Levelized Customer Benefits Plan whereby the average bill for an SCE&G residential electric customer would approximate that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the SCPSC in August 2018. Among other things, the order also sets forth the following findings and merger conditions:

• No capital costs related to the Nuclear Project incurred after March 12, 2015 will be recoverable by SCE&G, which results in rate base associated with the Nuclear Project of $2.768 billion after recording an impairment charge of $1.372 billion (pre-tax, and incremental to impairment losses recorded in 2017).

• SCE&G will provide refunds and restitution to customers from prior years' revenues totaling an aggregate $2.039 billion, comprised of $1.032 billion to be credited to customers over 20 years and $1.007 billion credited to customers over approximately 11 years. These refunds include amounts to be refunded to customers related to the monetization of guaranty settlement described in Note 2.

• Except for rate adjustments for fuel and environmental costs, demand side management costs, and other rates routinely adjusted on an annual or biannual basis, SCE&G will freeze retail electric base rates at current levels until January 1, 2021.

• SCE&G's natural gas customers will receive refunds totaling $2.45 million in 2019, 2020 and 2021 combined.

• Corporate giving will increase by $1 million per year for at least five years above historical levels.

• SCE&G will not seek to pass on to ratepayers its initial capital investment in CEC, a 540-MW combined-cycle natural gas-fired generating facility, and will not seek to pass on to ratepayers any acquisition premium costs, transition costs, or transaction cost associated with the merger. SCE&G's decision to not seek recovery of the initial capital investment in CEC was included in the determination of impairment charges recorded in 2017.

In addition, the SCPSC order approved the removal of SCE&G's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of December 31, 2018, such investment in these assets included approximately $367 million within utility plant, net and approximately $15 million within regulatory assets, which amount represents certain deferred operating costs. The SCPSC also approved deferral of certain operating costs related to the investment. Recovery of the transmission capital costs and associated deferred operating costs will be addressed in a future rate proceeding.

Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. On February 12, 2019, the SCPSC issued a ruling (1) finding that SCE&G was imprudent in its actions by not disclosing material information to the ORS and the SCPSC, and (2) denying the petitions for rehearing or reconsideration as to other issues raised in the various petitions. The Merger Approval Order and the ruling are subject to appeal by various parties. The Company and Consolidated SCE&G cannot predict the outcome of these matters.

Contractor Bankruptcy Proceedings and Related Uncertainties

On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the Nuclear Project and similar units being built for an unaffiliated company as a material factor that caused WEC and WECTEC to seek protection under the bankruptcy laws. As part of such filing, WEC and WECTEC publicly announced their inability to complete Unit 2 and Unit 3 under the terms of the EPC Contract.

On September 1, 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of WEC and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by the Consortium of the EPC Contract, and asserted against WEC and WECTEC any and all claims that were based thereon or that may have been related thereto. These claims were sold to Citibank on September 27, 2017 as part of a monetization transaction discussed below. Notwithstanding the sale of the claims, SCE&G and Santee Cooper remain responsible for any claims that may be made by WEC and WECTEC against them relating to the EPC Contract.

WEC’s Reorganization Plan was confirmed by the Bankruptcy Court on March 28, 2018, and became effective August 1, 2018. In connection with the effectiveness of the Reorganization Plan, the EPC Contract was deemed rejected. Initially, WEC had projected that its Reorganization Plan would pay in full or nearly in full its pre-petition trade creditors, including several of the WEC Subcontractors which have alleged non-payment by the Consortium for amounts owed for work performed on the Nuclear Project and have filed liens on property in Fairfield County, South Carolina, where Unit 2 and Unit 3 were to be located (Unit 2/3 Property). SCE&G is contesting approximately $285 million of filed liens in Fairfield County. Most of these asserted liens are “pre-petition” claims that relate to work performed by WEC Subcontractors before the WEC bankruptcy, although some of them are “post-petition” claims arising from work performed after the WEC bankruptcy.

WEC has indicated that some unsecured creditors have sought or may seek amounts beyond what WEC allocated when it submitted the Reorganization Plan. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the Reorganization Plan allocated by WEC, 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. See also discussion below regarding limitations with respect to SCE&G’s pre-petition lien obligations arising from its monetization of the Toshiba Settlement.

SCE&G and Santee Cooper are responsible for amounts owed to WEC for valid work performed by WEC Subcontractors on the Nuclear Project after the WEC bankruptcy filing (i.e., post-petition) until termination of the IAA (the IAA Period). While SCE&G and Santee Cooper funded amounts to WEC for such IAA Period obligations on a weekly basis, SCE&G and Santee Cooper undertook a reconciliation to ensure that amounts advanced to WEC for such purposes while the IAA was in effect were paid to WEC Subcontractors. That reconciliation remains ongoing. In the WEC bankruptcy proceeding, deadlines were established for creditors of WEC (including the WEC Subcontractors on the Nuclear Project) to assert the amounts owed to such creditors prior to the WEC bankruptcy filing and during the IAA Period. Many of the WEC Subcontractors have filed such claims. SCE&G does not believe that the claims asserted related to the IAA Period will exceed the amounts previously funded for the currently asserted IAA-related claims, whether relating to claims already paid or those remaining to be paid. SCE&G intends to oppose any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the IAA. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.

Further, some WEC Subcontractors who have made claims against WEC in the bankruptcy proceeding also filed against SCE&G and Santee Cooper in South Carolina state court for damages. The WEC 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 Nuclear Project site. SCE&G also intends to oppose these claims and liens. With respect to claims of WEC Subcontractors during the IAA Period, SCE&G believes there were sufficient amounts previously funded during the IAA Period to pay such validly asserted claims. With respect to the WEC Subcontractor claims which relate to other periods, SCE&G understands that such claims will be paid pursuant to WEC’s confirmed Reorganization Plan. SCE&G further understands that the amounts paid under the plan may satisfy such claims in full.  Therefore, SCE&G believes that the WEC Subcontractors may be paid substantially (and potentially in full) from WEC. While SCE&G cannot be assured that it will not have any exposure on account of unpaid WEC Subcontractor claims, which claims SCE&G is presently disputing, SCE&G believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.

Toshiba Settlement and Subsequent Monetization

Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC. In 2015 Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. In satisfaction of such guaranty obligations, on July 27, 2017, the Toshiba Settlement was executed under which Toshiba was to make periodic settlement payments beginning in October 2017 in the total amount of approximately $2.2 billion ($1.2 billion for SCE&G’s 55% share), subject to certain offsets for payments by WEC in bankruptcy that would have the effect of satisfying the liens discussed above and below.

In September and October 2017, proceeds totaling approximately $1.997 billion were received in full satisfaction of the Toshiba Settlement ($1.098 billion for SCE&G's 55% share). The proceeds were obtained through the receipt of a payment from Toshiba and a payment from Citibank arising from its purchase of all other scheduled payments, including amounts related to the contractor liens discussed above. The purchase agreement with Citibank provides that SCE&G and Santee Cooper (each according to its pro rata share) would indemnify Citibank for its losses arising from misrepresentations or covenant defaults under the purchase agreement. SCE&G and Santee Cooper also assigned their claims under the WEC bankruptcy process to Citibank, and agreed to use commercially reasonable efforts to cooperate with Citibank and provide reasonable support necessary for its enforcement of those claims. Proceeds received from the Toshiba Settlement are recorded as a regulatory liability on the accompanying consolidated balance sheets, as the net value of the proceeds will be credited to customer bills over 20 years (see Merger Approval Order above).

Several WEC Subcontractors have filed liens against the Unit 2/3 Property, which SCE&G is contesting. Payments under the Toshiba Settlement are subject to reduction if WEC pays WEC Subcontractors holding pre-petition liens directly. Under these circumstances, SCE&G and Santee Cooper, each in its pro rata share, would be required to make Citibank whole for reductions related to valid subcontractor and vendor pre-petition liens up to $60 million ($33 million for SCE&G's 55% share).

Regulatory, Political and Legal Developments

In connection with the abandonment of the Nuclear Project, various state and local governmental authorities have attempted and may further attempt to challenge, reverse or revoke previously-approved tax or economic development incentives, benefits or exemptions and have attempted and may further attempt to apply such actions retroactively. No assurance can be given as to the timing or outcome of these matters. See Claims and Litigation for a description of specific challenges.

In July 2018, the SCPSC issued orders implementing a June 2018 legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from its electric utility customers under the BLRA and altering certain provisions previously applicable under the BLRA, including redefining the standard of care required by the associated regulations and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the Nuclear Project. These orders reduced the portion of SCE&G’s retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer’s bill, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. These lower rates remained in effect until February 2019, when the new rates pursuant to the Merger Approval Order became effective.

In June 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of the rate reductions under the BLRA. In the lawsuit, which was subsequently amended, SCE&G sought a declaration that the new laws were unconstitutional. On January 8, 2019, SCE&G voluntarily dismissed this lawsuit without prejudice.

Impairment Considerations

In 2017, the Company and Consolidated SC&G recognized pre-tax impairment losses of approximately $1.118 billion (approximately $690 million net of tax) related to the Nuclear Project. In the first quarter of 2018, the Company and Consolidated SCE&G recognized a pre-tax impairment loss of approximately $3.6 million (approximately $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. On December 21, 2018, the SCPSC issued the Merger Approval Order which, among other things, limited recovery of capital costs related to the Nuclear Project to $2.768 billion. As a result, the Company and Consolidated SCE&G concluded that Nuclear Project capital costs exceeding the amount established in the Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed, and recorded an impairment charge of approximately $1.372 billion (approximately $870.1 million net of tax) in the fourth quarter of 2018.

In addition, the Company and Consolidated SCE&G expect to record additional impairment charges and establish additional liabilities in the first quarter of 2019. These additional amounts arise from or are related to provisions in the Merger Approval Order and an order by the NCUC approving the SCANA Combination that required the successful consummation of the merger before they would become effective. Accordingly, the following impairment charges and liabilities are expected to be recorded by the Company and Consolidated SCE&G (unless otherwise indicated) in the first quarter of 2019:

• A pre-tax impairment charge of approximately $105 million (approximately $79 million net of tax) related to certain assets that had been constructed in connection with the Nuclear Project that were not abandoned but were instead transferred to Unit 1.

• A regulatory liability for refunds and restitution to electric customers of approximately $1.007 billion pre-tax (approximately $755 million net of tax).

• A regulatory liability for refunds to natural gas customers totaling $2.45 million pre-tax (approximately $1.8 million net of tax).

• A liability related to charitable contributions in South Carolina of approximately $22 million pre-tax (approximately $16 million net of tax). It is expected that an additional liability related to charitable contributions in North Carolina of approximately $0.7 million pre-tax (approximately $0.5 million net of tax) would be recorded by the Company.

• A write-off of excess deferred taxes of approximately $145 million related to the regulatory liability for the monetization of guaranty settlement.

In addition, the SCPSC order approved the removal of SCE&G's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of December 31, 2018, such investment in these assets included approximately $367 million within utility plant, net and approximately $15 million within regulatory assets, which amount represents certain deferred operating costs. The SCPSC also approved deferral of certain operating costs related to the investment. Recovery of the transmission capital costs and associated deferred operating costs will be addressed in a future rate proceeding. The Company and Consolidated SCE&G believe these transmission capital and deferred operating costs are probable of recovery; however, if the SCPSC were to disallow recovery of or a reasonable return on all or a portion of them, an impairment charge equal to the disallowed costs may be required.

Claims and Litigation

Ratepayer Class Actions

In May 2018, a consolidated complaint was filed in the State Court of Common Pleas in Hampton County, South Carolina (the Hampton County Court) against SCE&G, SCANA, and the State of South Carolina (the SCE&G Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that SCE&G was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the Nuclear Project, and that SCE&G committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that SCE&G may not charge its customers for any past or continuing costs of the Nuclear Project, sought to have SCANA and SCE&G’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 Nuclear Project.

In December 2018, the judge entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the SCE&G Ratepayer Case. The settlement agreement provides that SCANA and SCE&G would establish an escrow account (the Common Benefit Fund), and proceeds from the Common Benefit Fund would be distributed to the class members, after payment of certain taxes, attorneys' fees and other expenses and administrative costs. The Common Benefit Fund would include (1) the sum of $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 Common Benefit Fund in favor of class members over a period of time established by the SCPSC in its order related to the Concurrent Dockets, (2) a cash payment of $115 million, and (3) the transfer of certain SCE&G-owned real estate or sales proceeds from the sale of such properties, which counsel for the SCE&G Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and SCE&G have funded this escrow account. The court has scheduled a fairness hearing on the settlement in May 2019. Any distribution from the Common Benefit Fund is subject to court approval. As a result, the Company and Consolidated SCE&G expect to reflect an approximately $157 million ($118 million after-tax) charge in the first quarter of 2019. In addition to court approval, this settlement was contingent on the consummation of the SCANA Combination, which became effective January 1, 2019. Therefore, as of December 31, 2018, no accrual for this potential loss has been included in the consolidated financial statements, but is expected to be recorded by the Company and Consolidated SCE&G in the first quarter of 2019.

In September 2017, a purported class action was filed against Santee Cooper, SCE&G, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the Hampton County Court (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the SCE&G 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 Nuclear 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. In December 2018, Santee Cooper filed its answer to the plaintiffs' fourth amended complaint and filed cross claims against SCE&G. These cross claims include breach of contract accompanied by a fraudulent act, gross negligence, breach of fiduciary duty, breach of contract accompanied by bad faith, waste and equitable indemnification. In January 2019, SCE&G filed a motion to dismiss Santee Cooper's cross claims or in the alternative to compel arbitration and a stay. A hearing has not been scheduled on this motion. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

In January 2018, a purported class action was filed, and subsequently amended, against SCANA, SCE&G and certain former executive officers in the District Court. The plaintiffs allege, among other things, that SCANA, SCE&G 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 SCE&G Ratepayer Case settlement described previously contemplates dismissal of claims by SCE&G ratepayers in this case against SCE&G, SCANA and their former officers. In January 2019, the plaintiffs filed an amended complaint which continues to make allegations on behalf of Santee Cooper ratepayers against SCANA, SCE&G and the individual former executive officers. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

State Court Shareholder Actions

In September 2017, a purported shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina (the Richland County Court). In September 2018, this action was consolidated with another action in the Business Court Pilot Program in Richland County. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the Nuclear Project, and that certain of the defendants were unjustly enriched by bonuses they were paid in connection with the project. The defendants have filed a motion to dismiss the consolidated action in favor of the pending federal derivative action. On January 7, 2019, the defendants filed a motion for judgment on the pleadings, asserting the shareholders in this action lost standing to assert derivative claims as a result of the SCANA Combination. These motions are pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren 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 District Court and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County, South Carolina. Dominion Energy appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with a similar appeal and remains pending. Motions to stay and to consolidate this case are being held in abeyance. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

In February 2018, a purported class action was filed against certain former executive officers and directors of SCANA and SCE&G and Dominion Energy in the Richland County Court. The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the City of Warren Lawsuit. In February 2018, Dominion Energy removed the case to the District Court and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the Richland County Court. Dominion Energy appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with the City of Warren Lawsuit. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

Federal Court Shareholder Actions

In November 2017, a purported shareholder derivative action was filed against SCANA and certain former executive officers and directors in the District Court. Another purported shareholder derivative action was filed against nearly all of these defendants. In January 2018, the District Court consolidated these suits, and the plaintiffs filed a consolidated amended complaint. The plaintiffs allege, among other things, that the defendants violated their fiduciary duties to shareholders by disseminating false and misleading information about the Nuclear Project, failing to maintain proper internal controls, failing to properly oversee and manage SCANA and that the individual defendants were unjustly enriched in their compensation. In June 2018, the court denied the defendants' motions to dismiss and in October 2018, the court denied SCANA's motion to stay all proceedings pending investigation by a Special Litigation Committee of its Board of Directors, with leave to refile after the SCPSC's decision on the merger between Dominion Energy and SCANA. On January 7, 2019, the defendants filed a motion for judgment on the pleadings, asserting the shareholders in this action lost standing to assert derivative claims as a result of the SCANA Combination. This motion is pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

In September 2017, a purported class action was filed against SCANA and certain former executive officers in the District Court. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants. In January 2018, the District Court consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and that the individually named defendants are liable under §20(a) of the Exchange Act. The defendants' motions to dismiss are pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

Employment Class Action and Indemnification

In July 2018, a case filed in the District Court was certified as a class action on behalf of persons who formerly worked at the Nuclear Project. The plaintiffs allege, among other things, that SCANA, Fluor Corporation and Fluor Enterprises, Inc. violated the WARN Act in connection with the decision to stop construction at the Nuclear Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment. While SCANA and SCE&G intend to contest this case, it is reasonably possible that a loss estimated to be as much as $75 million could be incurred, of which SCE&G's proportionate share as a co-owner of the Nuclear Project would be 55%. This potential loss could arise due to the Fluor Defendants seeking indemnification from SCE&G.

In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina (the Fairfield County Court) by the Fluor Defendants against SCE&G and Santee Cooper. The Fluor Defendants 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. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of these cases, but there could be a material impact to their results of operations, financial condition and/or cash flows.

FILOT Litigation

In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against SCE&G in the Fairfield County Court. The complaint makes allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty and unfair trade practices related to SCE&G’s termination of the FILOT agreement between SCE&G and Fairfield County related to the Nuclear Project. The plaintiff withdrew the motion for temporary injunction in December 2017. This case is pending. The Company and Consolidated SCE&G are currently unable to make an estimate of the potential impacts to their respective consolidated financial statements related to this matter.

Other Proceedings and Investigations

In June 2018, SCE&G received a notice of proposed assessment of approximately $410 million, excluding interest, from the DOR following its audit of SCE&G's sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the Nuclear Project, is based on the DOR’s position that SCE&G’s sales and use tax exemption for the Nuclear Project does not apply because the facility will not become operational. SCE&G has protested the proposed assessment, which remains pending, and recorded an $11 million liability in its Consolidated Balance Sheet as of December 31, 2018 for its share of any taxes ultimately due.

On December 29, 2018, arbitration proceedings commenced between SCE&G and Cameco Corporation (Cameco) related to a supply agreement dated May 12, 2008.  This agreement provides the terms and conditions under which SCE&G agreed to purchase uranium hexafluoride from Cameco over a period from 2010 to 2020.  Cameco alleges that SCE&G violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for 2017 and 2018 delivery years.  SCE&G denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement.  The Company and Consolidated SCE&G cannot determine the outcome or timing of this matter.

In 2017 the Company was served with subpoenas issued by the United States Attorney’s Office for the District of South Carolina and the staff of the SEC's Division of Enforcement seeking documents relating to the Nuclear Project. Also, SLED is conducting a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. These investigations are ongoing, and the Company and Consolidated SCE&G intend to fully cooperate with them.

While the Company and Consolidated SCE&G intend to vigorously contest the lawsuits, claims, and audit positions which have been filed or initiated against them, except as noted above, they cannot predict the timing or outcome of these matters or others that may arise, and adverse outcomes from some of these matters would not be covered by insurance. Except as noted above, the various claims for damages do not specify an amount for those damages, and the number of plaintiffs that are ultimately certified in any class action lawsuit is unknown. In addition, most of the cases referred to above are in their early stages. For these reasons, the Company and Consolidated SCE&G (i) have not determined that a loss is probable and (ii) except as noted above, cannot provide any estimate or range of potential loss for these matters at this time. Therefore, no accrual for these potential losses has been included in the consolidated financial statements. However, outcomes could have a material adverse impact on the Company's and Consolidated SCE&G's results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G are subject to various other claims and litigation incidental to their business operations which management anticipates will be resolved without a material impact on the Company's and Consolidated SCE&G's results of operations, cash flows or financial condition.

Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Unit 1.  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 ANI 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 $137.7 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $20.5 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be $91.8 million per incident, but not more than $13.7 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 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, SCE&G’s portion of the retrospective premium assessment would not exceed $23.4 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 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, SCE&G's portion of the retrospective premium assessment would not exceed $2.0 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G 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 the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position.

Environmental

The Company's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on the Company's and Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, the Company and Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company and Consolidated SCE&G expect to recover such expenditures and costs through existing ratemaking provisions.

From a regulatory perspective, SCANA, SCE&G 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. SCE&G 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.

In August 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO₂ from newly constructed fossil fuel-fired units. The final rule required all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds CO₂ per MWh and new natural gas units to meet 1,000 pounds CO₂ per MWh. In December 2018, the EPA proposed to revise the standard for newly constructed large coal-fired units to 1,900 pounds of CO₂ per MWh and for small units to 2,000 pounds CO₂ per MWh. The Company and Consolidated SCE&G are monitoring the proposed rule, but do not plan to construct new coal-fired units in the foreseeable future.

On August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The CPP rule included state-specific goals for reducing national CO₂ emissions by 32% from 2005 levels by 2030 and established a phased-in compliance approach beginning in 2022. The rule gave each state from one to three years to issue its SIP, which would ultimately define the specific compliance methodology that would be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. As a result of an Executive Order on March 28, 2017, the EPA placed the rule under review and the Court of Appeals agreed to hold the case in abeyance. On October 10, 2017, the Administrator of the EPA signed a notice proposing to repeal the rule on the grounds that it exceeds the EPA's statutory authority. The Company and Consolidated SCE&G expect any costs incurred to comply with such rule to be recoverable through rates.

On August 21, 2018, the EPA proposed the ACE rule which would replace the CPP. If implemented, the proposed ACE rule would define the “best system of emission reduction” for GHG emissions from existing power plants as on-site, heat-rate efficiency improvements; provide states with a list of “candidate technologies” that can be used to establish standards of performance and incorporated into their state plans; update the EPA’s NSR permitting program to incentivize efficiency improvements at existing power plants; and align CAA section 111(d) general implementing regulations to give states adequate time and flexibility to develop their state plans. The Company and Consolidated SCE&G are currently evaluating the ACE rule for potential impact at their coal fired units and expect any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of SO₂ and NO_X from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO₂ emissions and annual and ozone season NO_X emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO₂ and NO_X and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G and GENCO are in compliance with the MATS rule and expect to remain in compliance.

The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits such that, as a facility’s NPDES permit is renewed, any new effluent limitations would be incorporated. The ELG Rule became effective on January 4, 2016, after which state regulators could modify facility NPDES permits to match more restrictive standards, which would require facilities to retrofit with new wastewater treatment technologies. Compliance dates varied by type of wastewater, and some were based on a facility's five-year permit cycle and thus could range from 2018 to 2023. However, the ELG Rule is under reconsideration by the EPA and has been stayed administratively. The EPA has decided to conduct a new rulemaking that could result in revisions to certain flue gas desulfurization wastewater and bottom ash transport water requirements in the ELG Rule. Accordingly, in September 2017 the EPA finalized a rule that resets compliance dates under the ELG Rule to a range from November 1, 2020 to December 31, 2023. The EPA indicates that the new rulemaking process may take up to three years to complete, such that any revisions to the ELG Rule likely would not be final until the summer of 2020. While the Company and Consolidated SCE&G expect that wastewater treatment technology retrofits will be required at Williams and Wateree Stations, any costs incurred to comply with the ELG Rule are expected to be recoverable through rates.

The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications to ensure compliance with this rule. Any costs incurred to comply with this rule are expected to be recoverable through rates.

The EPA's final rule for CCR became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at certain of SCE&G's and GENCO's coal-fired generating facilities. An August 2018 decision by the United States Court of Appeals for the District of Columbia also imposed the rule requirements on CCR ponds at a former generation site owned by SCE&G. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. The Company and Consolidated SCE&G do not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future rates.

In December 2016, the U.S. Congress passed and the President signed legislation that creates a framework for EPA- approved state CCR permit programs. Under this legislation, an approved state CCR permit program functions in lieu of the self-implementing Federal CCR rule. The legislation allows states more flexibility in developing permit programs to implement the environmental criteria in the CCR rule. 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. To date, South Carolina has not begun drafting a CCR rule.

The Nuclear Waste Act 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. SCE&G 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, 2018, the federal government has not accepted any spent fuel from Unit 1, and it remains unclear when the repository may become available. SCE&G has constructed an independent spent fuel storage installation to accommodate the spent nuclear fuel output for the life of Unit 1. SCE&G may evaluate other technology as it becomes available.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by or under review by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2020 and will cost an additional $9.5 million. In September 2018, SCE&G submitted an updated remediation work plan for one site (Congaree River) to DHEC which, if approved and subsequently permitted by the USACE, would increase remediation cost for that site by approximately $8 million. DHEC is considering a revised remedy under a MRA but has not issued its direction or approval. SCE&G cannot predict if or when DHEC and the USACE may approve or issue permits for this work to proceed. Major remediation activities are accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheets. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At December 31, 2018, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $23.3 million and are included in regulatory assets.

Operating Lease Commitments

The Company and Consolidated SCE&G are obligated under various operating leases for land, office space, furniture, equipment, rail cars, and for the Company, airplanes. Leases expire at various dates through 2057.

	Rent Expense						Future Minimum Rental Payments
Millions of dollars	2016		2017		2018		2019		2020		2021		2022		2023		Thereafter
The Company	$	10.2	$	10	$	9.7	$	10	$	8	$	7	$	6	$	4	$	30
Consolidated SCE&G	12.2		11.4		10.2		3		2		1		1		—		16

Guarantees, Surety Bonds and Letters of Credit

SCANA has issued guarantees on behalf of its consolidated subsidiaries to facilitate commercial transactions with third parties. These guarantees are in the form of performance guarantees, primarily for the purchase and transportation of natural gas, and credit support for certain tax-exempt bond issues. SCANA is not required to recognize a liability for such guarantees unless it becomes probable that performance under the guarantees will be required. SCANA believes the likelihood that it would be required to perform or otherwise incur any losses associated with these guarantees is not probable; therefore, no liability for these guarantees has been recognized. To the extent that a liability subject to a guarantee has been incurred, the liability is included in the consolidated financial statements. At December 31, 2018, the maximum future payments (undiscounted) that SCANA could be required to make under guarantees totaled approximately $444.6 million.

At December 31, 2018, SCE&G had purchased a $100.4 million surety bond to facilitate commercial transactions with Dominion Energy Carolina Gas Transmission LLC, which became an affiliate in connection with the SCANA Combination. Under the terms of the surety bond, SCE&G is obligated to indemnify the surety bond company for any amounts paid. Further, the Company had authorized the issuance of letters of credit by financial institutions of approximately $80.4 million, including approximately $39.3 million by Consolidated SCE&G, primarily to facilitate commercial transactions and to provide credit support for certain tax-exempt bond issues. Certain of these letters of credit are supported by lines of credit and are discussed in Note 5.

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 the Company’s regulated utility operations.  As of December 31, 2018, the Company and Consolidated SCE&G have recorded AROs of approximately $218 million for nuclear plant decommissioning (see Note 1). In addition, the Company has recorded AROs of approximately $359 million, including $323 million for Consolidated SCE&G, 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: 

	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Beginning balance	$	568		$	558		$	529		$	522
Liabilities incurred	—			—			—			—
Liabilities settled	(15		)	(10		)	(15		)	(9		)
Accretion expense	25			25			23			23
Revisions in estimated cash flows	(1		)	(5		)	4			(7		)
Ending balance	$	577		$	568		$	541		$	529

Revisions in estimated cash flows in 2018 and 2017 primarily related to ash pond retirement obligations settled and updates in the anticipated timing of cash flows as work is completed.

SCE&G

Commitment [Line Items]

Legal Matters and Contingencies [Text Block]

COMMITMENTS AND CONTINGENCIES

Abandoned Nuclear Project

SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. SCE&G's ownership share in these units 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 and Related Uncertainties below), and were the subject of comprehensive analyses performed by the Company and Santee Cooper.

Based on the results of the Company's analysis, and in light of Santee Cooper's decision to suspend construction on Unit 2 and Unit 3, on July 31, 2017, the Company 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 the Company became the focus of numerous legislative, regulatory and legal proceedings, and led to SCE&G recording pre-tax impairment charges in 2017 totaling approximately $1.118 billion (approximately $690 million net of tax). An additional pre-tax impairment loss was recorded in the first quarter of 2018 of approximately $3.6 million (approximately $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. See further discussion below under Impairment Considerations. These proceedings continued in 2018, and some of them remain unresolved and are described below and/or in Claims and Litigation.

On January 2, 2018, SCANA and Dominion Energy entered into the 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.

Merger Approval Order

On December 21, 2018, the SCPSC issued the Merger Approval Order. The order adopted Dominion Energy's Plan-B Levelized Customer Benefits Plan whereby the average bill for an SCE&G residential electric customer would approximate that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the SCPSC in August 2018. Among other things, the order also sets forth the following findings and merger conditions:

• No capital costs related to the Nuclear Project incurred after March 12, 2015 will be recoverable by SCE&G, which results in rate base associated with the Nuclear Project of $2.768 billion after recording an impairment charge of $1.372 billion (pre-tax, and incremental to impairment losses recorded in 2017).

• SCE&G will provide refunds and restitution to customers from prior years' revenues totaling an aggregate $2.039 billion, comprised of $1.032 billion to be credited to customers over 20 years and $1.007 billion credited to customers over approximately 11 years. These refunds include amounts to be refunded to customers related to the monetization of guaranty settlement described in Note 2.

• Except for rate adjustments for fuel and environmental costs, demand side management costs, and other rates routinely adjusted on an annual or biannual basis, SCE&G will freeze retail electric base rates at current levels until January 1, 2021.

• SCE&G's natural gas customers will receive refunds totaling $2.45 million in 2019, 2020 and 2021 combined.

• Corporate giving will increase by $1 million per year for at least five years above historical levels.

• SCE&G will not seek to pass on to ratepayers its initial capital investment in CEC, a 540-MW combined-cycle natural gas-fired generating facility, and will not seek to pass on to ratepayers any acquisition premium costs, transition costs, or transaction cost associated with the merger. SCE&G's decision to not seek recovery of the initial capital investment in CEC was included in the determination of impairment charges recorded in 2017.

In addition, the SCPSC order approved the removal of SCE&G's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of December 31, 2018, such investment in these assets included approximately $367 million within utility plant, net and approximately $15 million within regulatory assets, which amount represents certain deferred operating costs. The SCPSC also approved deferral of certain operating costs related to the investment. Recovery of the transmission capital costs and associated deferred operating costs will be addressed in a future rate proceeding.

Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. On February 12, 2019, the SCPSC issued a ruling (1) finding that SCE&G was imprudent in its actions by not disclosing material information to the ORS and the SCPSC, and (2) denying the petitions for rehearing or reconsideration as to other issues raised in the various petitions. The Merger Approval Order and the ruling are subject to appeal by various parties. The Company and Consolidated SCE&G cannot predict the outcome of these matters.

Contractor Bankruptcy Proceedings and Related Uncertainties

On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the Nuclear Project and similar units being built for an unaffiliated company as a material factor that caused WEC and WECTEC to seek protection under the bankruptcy laws. As part of such filing, WEC and WECTEC publicly announced their inability to complete Unit 2 and Unit 3 under the terms of the EPC Contract.

On September 1, 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of WEC and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by the Consortium of the EPC Contract, and asserted against WEC and WECTEC any and all claims that were based thereon or that may have been related thereto. These claims were sold to Citibank on September 27, 2017 as part of a monetization transaction discussed below. Notwithstanding the sale of the claims, SCE&G and Santee Cooper remain responsible for any claims that may be made by WEC and WECTEC against them relating to the EPC Contract.

WEC’s Reorganization Plan was confirmed by the Bankruptcy Court on March 28, 2018, and became effective August 1, 2018. In connection with the effectiveness of the Reorganization Plan, the EPC Contract was deemed rejected. Initially, WEC had projected that its Reorganization Plan would pay in full or nearly in full its pre-petition trade creditors, including several of the WEC Subcontractors which have alleged non-payment by the Consortium for amounts owed for work performed on the Nuclear Project and have filed liens on property in Fairfield County, South Carolina, where Unit 2 and Unit 3 were to be located (Unit 2/3 Property). SCE&G is contesting approximately $285 million of filed liens in Fairfield County. Most of these asserted liens are “pre-petition” claims that relate to work performed by WEC Subcontractors before the WEC bankruptcy, although some of them are “post-petition” claims arising from work performed after the WEC bankruptcy.

WEC has indicated that some unsecured creditors have sought or may seek amounts beyond what WEC allocated when it submitted the Reorganization Plan. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the Reorganization Plan allocated by WEC, 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. See also discussion below regarding limitations with respect to SCE&G’s pre-petition lien obligations arising from its monetization of the Toshiba Settlement.

SCE&G and Santee Cooper are responsible for amounts owed to WEC for valid work performed by WEC Subcontractors on the Nuclear Project after the WEC bankruptcy filing (i.e., post-petition) until termination of the IAA (the IAA Period). While SCE&G and Santee Cooper funded amounts to WEC for such IAA Period obligations on a weekly basis, SCE&G and Santee Cooper undertook a reconciliation to ensure that amounts advanced to WEC for such purposes while the IAA was in effect were paid to WEC Subcontractors. That reconciliation remains ongoing. In the WEC bankruptcy proceeding, deadlines were established for creditors of WEC (including the WEC Subcontractors on the Nuclear Project) to assert the amounts owed to such creditors prior to the WEC bankruptcy filing and during the IAA Period. Many of the WEC Subcontractors have filed such claims. SCE&G does not believe that the claims asserted related to the IAA Period will exceed the amounts previously funded for the currently asserted IAA-related claims, whether relating to claims already paid or those remaining to be paid. SCE&G intends to oppose any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the IAA. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.

Further, some WEC Subcontractors who have made claims against WEC in the bankruptcy proceeding also filed against SCE&G and Santee Cooper in South Carolina state court for damages. The WEC 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 Nuclear Project site. SCE&G also intends to oppose these claims and liens. With respect to claims of WEC Subcontractors during the IAA Period, SCE&G believes there were sufficient amounts previously funded during the IAA Period to pay such validly asserted claims. With respect to the WEC Subcontractor claims which relate to other periods, SCE&G understands that such claims will be paid pursuant to WEC’s confirmed Reorganization Plan. SCE&G further understands that the amounts paid under the plan may satisfy such claims in full.  Therefore, SCE&G believes that the WEC Subcontractors may be paid substantially (and potentially in full) from WEC. While SCE&G cannot be assured that it will not have any exposure on account of unpaid WEC Subcontractor claims, which claims SCE&G is presently disputing, SCE&G believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.

Toshiba Settlement and Subsequent Monetization

Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC. In 2015 Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. In satisfaction of such guaranty obligations, on July 27, 2017, the Toshiba Settlement was executed under which Toshiba was to make periodic settlement payments beginning in October 2017 in the total amount of approximately $2.2 billion ($1.2 billion for SCE&G’s 55% share), subject to certain offsets for payments by WEC in bankruptcy that would have the effect of satisfying the liens discussed above and below.

In September and October 2017, proceeds totaling approximately $1.997 billion were received in full satisfaction of the Toshiba Settlement ($1.098 billion for SCE&G's 55% share). The proceeds were obtained through the receipt of a payment from Toshiba and a payment from Citibank arising from its purchase of all other scheduled payments, including amounts related to the contractor liens discussed above. The purchase agreement with Citibank provides that SCE&G and Santee Cooper (each according to its pro rata share) would indemnify Citibank for its losses arising from misrepresentations or covenant defaults under the purchase agreement. SCE&G and Santee Cooper also assigned their claims under the WEC bankruptcy process to Citibank, and agreed to use commercially reasonable efforts to cooperate with Citibank and provide reasonable support necessary for its enforcement of those claims. Proceeds received from the Toshiba Settlement are recorded as a regulatory liability on the accompanying consolidated balance sheets, as the net value of the proceeds will be credited to customer bills over 20 years (see Merger Approval Order above).

Several WEC Subcontractors have filed liens against the Unit 2/3 Property, which SCE&G is contesting. Payments under the Toshiba Settlement are subject to reduction if WEC pays WEC Subcontractors holding pre-petition liens directly. Under these circumstances, SCE&G and Santee Cooper, each in its pro rata share, would be required to make Citibank whole for reductions related to valid subcontractor and vendor pre-petition liens up to $60 million ($33 million for SCE&G's 55% share).

Regulatory, Political and Legal Developments

In connection with the abandonment of the Nuclear Project, various state and local governmental authorities have attempted and may further attempt to challenge, reverse or revoke previously-approved tax or economic development incentives, benefits or exemptions and have attempted and may further attempt to apply such actions retroactively. No assurance can be given as to the timing or outcome of these matters. See Claims and Litigation for a description of specific challenges.

In July 2018, the SCPSC issued orders implementing a June 2018 legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from its electric utility customers under the BLRA and altering certain provisions previously applicable under the BLRA, including redefining the standard of care required by the associated regulations and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the Nuclear Project. These orders reduced the portion of SCE&G’s retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer’s bill, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. These lower rates remained in effect until February 2019, when the new rates pursuant to the Merger Approval Order became effective.

In June 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of the rate reductions under the BLRA. In the lawsuit, which was subsequently amended, SCE&G sought a declaration that the new laws were unconstitutional. On January 8, 2019, SCE&G voluntarily dismissed this lawsuit without prejudice.

Impairment Considerations

In 2017, the Company and Consolidated SC&G recognized pre-tax impairment losses of approximately $1.118 billion (approximately $690 million net of tax) related to the Nuclear Project. In the first quarter of 2018, the Company and Consolidated SCE&G recognized a pre-tax impairment loss of approximately $3.6 million (approximately $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. On December 21, 2018, the SCPSC issued the Merger Approval Order which, among other things, limited recovery of capital costs related to the Nuclear Project to $2.768 billion. As a result, the Company and Consolidated SCE&G concluded that Nuclear Project capital costs exceeding the amount established in the Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed, and recorded an impairment charge of approximately $1.372 billion (approximately $870.1 million net of tax) in the fourth quarter of 2018.

In addition, the Company and Consolidated SCE&G expect to record additional impairment charges and establish additional liabilities in the first quarter of 2019. These additional amounts arise from or are related to provisions in the Merger Approval Order and an order by the NCUC approving the SCANA Combination that required the successful consummation of the merger before they would become effective. Accordingly, the following impairment charges and liabilities are expected to be recorded by the Company and Consolidated SCE&G (unless otherwise indicated) in the first quarter of 2019:

• A pre-tax impairment charge of approximately $105 million (approximately $79 million net of tax) related to certain assets that had been constructed in connection with the Nuclear Project that were not abandoned but were instead transferred to Unit 1.

• A regulatory liability for refunds and restitution to electric customers of approximately $1.007 billion pre-tax (approximately $755 million net of tax).

• A regulatory liability for refunds to natural gas customers totaling $2.45 million pre-tax (approximately $1.8 million net of tax).

• A liability related to charitable contributions in South Carolina of approximately $22 million pre-tax (approximately $16 million net of tax). It is expected that an additional liability related to charitable contributions in North Carolina of approximately $0.7 million pre-tax (approximately $0.5 million net of tax) would be recorded by the Company.

• A write-off of excess deferred taxes of approximately $145 million related to the regulatory liability for the monetization of guaranty settlement.

In addition, the SCPSC order approved the removal of SCE&G's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of December 31, 2018, such investment in these assets included approximately $367 million within utility plant, net and approximately $15 million within regulatory assets, which amount represents certain deferred operating costs. The SCPSC also approved deferral of certain operating costs related to the investment. Recovery of the transmission capital costs and associated deferred operating costs will be addressed in a future rate proceeding. The Company and Consolidated SCE&G believe these transmission capital and deferred operating costs are probable of recovery; however, if the SCPSC were to disallow recovery of or a reasonable return on all or a portion of them, an impairment charge equal to the disallowed costs may be required.

Claims and Litigation

Ratepayer Class Actions

In May 2018, a consolidated complaint was filed in the State Court of Common Pleas in Hampton County, South Carolina (the Hampton County Court) against SCE&G, SCANA, and the State of South Carolina (the SCE&G Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that SCE&G was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the Nuclear Project, and that SCE&G committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that SCE&G may not charge its customers for any past or continuing costs of the Nuclear Project, sought to have SCANA and SCE&G’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 Nuclear Project.

In December 2018, the judge entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the SCE&G Ratepayer Case. The settlement agreement provides that SCANA and SCE&G would establish an escrow account (the Common Benefit Fund), and proceeds from the Common Benefit Fund would be distributed to the class members, after payment of certain taxes, attorneys' fees and other expenses and administrative costs. The Common Benefit Fund would include (1) the sum of $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 Common Benefit Fund in favor of class members over a period of time established by the SCPSC in its order related to the Concurrent Dockets, (2) a cash payment of $115 million, and (3) the transfer of certain SCE&G-owned real estate or sales proceeds from the sale of such properties, which counsel for the SCE&G Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and SCE&G have funded this escrow account. The court has scheduled a fairness hearing on the settlement in May 2019. Any distribution from the Common Benefit Fund is subject to court approval. As a result, the Company and Consolidated SCE&G expect to reflect an approximately $157 million ($118 million after-tax) charge in the first quarter of 2019. In addition to court approval, this settlement was contingent on the consummation of the SCANA Combination, which became effective January 1, 2019. Therefore, as of December 31, 2018, no accrual for this potential loss has been included in the consolidated financial statements, but is expected to be recorded by the Company and Consolidated SCE&G in the first quarter of 2019.

In September 2017, a purported class action was filed against Santee Cooper, SCE&G, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the Hampton County Court (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the SCE&G 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 Nuclear 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. In December 2018, Santee Cooper filed its answer to the plaintiffs' fourth amended complaint and filed cross claims against SCE&G. These cross claims include breach of contract accompanied by a fraudulent act, gross negligence, breach of fiduciary duty, breach of contract accompanied by bad faith, waste and equitable indemnification. In January 2019, SCE&G filed a motion to dismiss Santee Cooper's cross claims or in the alternative to compel arbitration and a stay. A hearing has not been scheduled on this motion. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

In January 2018, a purported class action was filed, and subsequently amended, against SCANA, SCE&G and certain former executive officers in the District Court. The plaintiffs allege, among other things, that SCANA, SCE&G 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 SCE&G Ratepayer Case settlement described previously contemplates dismissal of claims by SCE&G ratepayers in this case against SCE&G, SCANA and their former officers. In January 2019, the plaintiffs filed an amended complaint which continues to make allegations on behalf of Santee Cooper ratepayers against SCANA, SCE&G and the individual former executive officers. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

State Court Shareholder Actions

In September 2017, a purported shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina (the Richland County Court). In September 2018, this action was consolidated with another action in the Business Court Pilot Program in Richland County. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the Nuclear Project, and that certain of the defendants were unjustly enriched by bonuses they were paid in connection with the project. The defendants have filed a motion to dismiss the consolidated action in favor of the pending federal derivative action. On January 7, 2019, the defendants filed a motion for judgment on the pleadings, asserting the shareholders in this action lost standing to assert derivative claims as a result of the SCANA Combination. These motions are pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren 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 District Court and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County, South Carolina. Dominion Energy appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with a similar appeal and remains pending. Motions to stay and to consolidate this case are being held in abeyance. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

In February 2018, a purported class action was filed against certain former executive officers and directors of SCANA and SCE&G and Dominion Energy in the Richland County Court. The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the City of Warren Lawsuit. In February 2018, Dominion Energy removed the case to the District Court and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the Richland County Court. Dominion Energy appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with the City of Warren Lawsuit. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

Federal Court Shareholder Actions

In November 2017, a purported shareholder derivative action was filed against SCANA and certain former executive officers and directors in the District Court. Another purported shareholder derivative action was filed against nearly all of these defendants. In January 2018, the District Court consolidated these suits, and the plaintiffs filed a consolidated amended complaint. The plaintiffs allege, among other things, that the defendants violated their fiduciary duties to shareholders by disseminating false and misleading information about the Nuclear Project, failing to maintain proper internal controls, failing to properly oversee and manage SCANA and that the individual defendants were unjustly enriched in their compensation. In June 2018, the court denied the defendants' motions to dismiss and in October 2018, the court denied SCANA's motion to stay all proceedings pending investigation by a Special Litigation Committee of its Board of Directors, with leave to refile after the SCPSC's decision on the merger between Dominion Energy and SCANA. On January 7, 2019, the defendants filed a motion for judgment on the pleadings, asserting the shareholders in this action lost standing to assert derivative claims as a result of the SCANA Combination. This motion is pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

In September 2017, a purported class action was filed against SCANA and certain former executive officers in the District Court. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants. In January 2018, the District Court consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and that the individually named defendants are liable under §20(a) of the Exchange Act. The defendants' motions to dismiss are pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.

Employment Class Action and Indemnification

In July 2018, a case filed in the District Court was certified as a class action on behalf of persons who formerly worked at the Nuclear Project. The plaintiffs allege, among other things, that SCANA, Fluor Corporation and Fluor Enterprises, Inc. violated the WARN Act in connection with the decision to stop construction at the Nuclear Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment. While SCANA and SCE&G intend to contest this case, it is reasonably possible that a loss estimated to be as much as $75 million could be incurred, of which SCE&G's proportionate share as a co-owner of the Nuclear Project would be 55%. This potential loss could arise due to the Fluor Defendants seeking indemnification from SCE&G.

In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina (the Fairfield County Court) by the Fluor Defendants against SCE&G and Santee Cooper. The Fluor Defendants 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. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of these cases, but there could be a material impact to their results of operations, financial condition and/or cash flows.

FILOT Litigation

In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against SCE&G in the Fairfield County Court. The complaint makes allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty and unfair trade practices related to SCE&G’s termination of the FILOT agreement between SCE&G and Fairfield County related to the Nuclear Project. The plaintiff withdrew the motion for temporary injunction in December 2017. This case is pending. The Company and Consolidated SCE&G are currently unable to make an estimate of the potential impacts to their respective consolidated financial statements related to this matter.

Other Proceedings and Investigations

In June 2018, SCE&G received a notice of proposed assessment of approximately $410 million, excluding interest, from the DOR following its audit of SCE&G's sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the Nuclear Project, is based on the DOR’s position that SCE&G’s sales and use tax exemption for the Nuclear Project does not apply because the facility will not become operational. SCE&G has protested the proposed assessment, which remains pending, and recorded an $11 million liability in its Consolidated Balance Sheet as of December 31, 2018 for its share of any taxes ultimately due.

On December 29, 2018, arbitration proceedings commenced between SCE&G and Cameco Corporation (Cameco) related to a supply agreement dated May 12, 2008.  This agreement provides the terms and conditions under which SCE&G agreed to purchase uranium hexafluoride from Cameco over a period from 2010 to 2020.  Cameco alleges that SCE&G violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for 2017 and 2018 delivery years.  SCE&G denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement.  The Company and Consolidated SCE&G cannot determine the outcome or timing of this matter.

In 2017 the Company was served with subpoenas issued by the United States Attorney’s Office for the District of South Carolina and the staff of the SEC's Division of Enforcement seeking documents relating to the Nuclear Project. Also, SLED is conducting a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. These investigations are ongoing, and the Company and Consolidated SCE&G intend to fully cooperate with them.

While the Company and Consolidated SCE&G intend to vigorously contest the lawsuits, claims, and audit positions which have been filed or initiated against them, except as noted above, they cannot predict the timing or outcome of these matters or others that may arise, and adverse outcomes from some of these matters would not be covered by insurance. Except as noted above, the various claims for damages do not specify an amount for those damages, and the number of plaintiffs that are ultimately certified in any class action lawsuit is unknown. In addition, most of the cases referred to above are in their early stages. For these reasons, the Company and Consolidated SCE&G (i) have not determined that a loss is probable and (ii) except as noted above, cannot provide any estimate or range of potential loss for these matters at this time. Therefore, no accrual for these potential losses has been included in the consolidated financial statements. However, outcomes could have a material adverse impact on the Company's and Consolidated SCE&G's results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G are subject to various other claims and litigation incidental to their business operations which management anticipates will be resolved without a material impact on the Company's and Consolidated SCE&G's results of operations, cash flows or financial condition.

Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Unit 1.  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 ANI 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 $137.7 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $20.5 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be $91.8 million per incident, but not more than $13.7 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 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, SCE&G’s portion of the retrospective premium assessment would not exceed $23.4 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 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, SCE&G's portion of the retrospective premium assessment would not exceed $2.0 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G 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 the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position.

Environmental

The Company's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on the Company's and Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, the Company and Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company and Consolidated SCE&G expect to recover such expenditures and costs through existing ratemaking provisions.

From a regulatory perspective, SCANA, SCE&G 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. SCE&G 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.

In August 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO₂ from newly constructed fossil fuel-fired units. The final rule required all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds CO₂ per MWh and new natural gas units to meet 1,000 pounds CO₂ per MWh. In December 2018, the EPA proposed to revise the standard for newly constructed large coal-fired units to 1,900 pounds of CO₂ per MWh and for small units to 2,000 pounds CO₂ per MWh. The Company and Consolidated SCE&G are monitoring the proposed rule, but do not plan to construct new coal-fired units in the foreseeable future.

On August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The CPP rule included state-specific goals for reducing national CO₂ emissions by 32% from 2005 levels by 2030 and established a phased-in compliance approach beginning in 2022. The rule gave each state from one to three years to issue its SIP, which would ultimately define the specific compliance methodology that would be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. As a result of an Executive Order on March 28, 2017, the EPA placed the rule under review and the Court of Appeals agreed to hold the case in abeyance. On October 10, 2017, the Administrator of the EPA signed a notice proposing to repeal the rule on the grounds that it exceeds the EPA's statutory authority. The Company and Consolidated SCE&G expect any costs incurred to comply with such rule to be recoverable through rates.

On August 21, 2018, the EPA proposed the ACE rule which would replace the CPP. If implemented, the proposed ACE rule would define the “best system of emission reduction” for GHG emissions from existing power plants as on-site, heat-rate efficiency improvements; provide states with a list of “candidate technologies” that can be used to establish standards of performance and incorporated into their state plans; update the EPA’s NSR permitting program to incentivize efficiency improvements at existing power plants; and align CAA section 111(d) general implementing regulations to give states adequate time and flexibility to develop their state plans. The Company and Consolidated SCE&G are currently evaluating the ACE rule for potential impact at their coal fired units and expect any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of SO₂ and NO_X from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO₂ emissions and annual and ozone season NO_X emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO₂ and NO_X and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G and GENCO are in compliance with the MATS rule and expect to remain in compliance.

The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits such that, as a facility’s NPDES permit is renewed, any new effluent limitations would be incorporated. The ELG Rule became effective on January 4, 2016, after which state regulators could modify facility NPDES permits to match more restrictive standards, which would require facilities to retrofit with new wastewater treatment technologies. Compliance dates varied by type of wastewater, and some were based on a facility's five-year permit cycle and thus could range from 2018 to 2023. However, the ELG Rule is under reconsideration by the EPA and has been stayed administratively. The EPA has decided to conduct a new rulemaking that could result in revisions to certain flue gas desulfurization wastewater and bottom ash transport water requirements in the ELG Rule. Accordingly, in September 2017 the EPA finalized a rule that resets compliance dates under the ELG Rule to a range from November 1, 2020 to December 31, 2023. The EPA indicates that the new rulemaking process may take up to three years to complete, such that any revisions to the ELG Rule likely would not be final until the summer of 2020. While the Company and Consolidated SCE&G expect that wastewater treatment technology retrofits will be required at Williams and Wateree Stations, any costs incurred to comply with the ELG Rule are expected to be recoverable through rates.

The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications to ensure compliance with this rule. Any costs incurred to comply with this rule are expected to be recoverable through rates.

The EPA's final rule for CCR became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at certain of SCE&G's and GENCO's coal-fired generating facilities. An August 2018 decision by the United States Court of Appeals for the District of Columbia also imposed the rule requirements on CCR ponds at a former generation site owned by SCE&G. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. The Company and Consolidated SCE&G do not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future rates.

In December 2016, the U.S. Congress passed and the President signed legislation that creates a framework for EPA- approved state CCR permit programs. Under this legislation, an approved state CCR permit program functions in lieu of the self-implementing Federal CCR rule. The legislation allows states more flexibility in developing permit programs to implement the environmental criteria in the CCR rule. 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. To date, South Carolina has not begun drafting a CCR rule.

The Nuclear Waste Act 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. SCE&G 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, 2018, the federal government has not accepted any spent fuel from Unit 1, and it remains unclear when the repository may become available. SCE&G has constructed an independent spent fuel storage installation to accommodate the spent nuclear fuel output for the life of Unit 1. SCE&G may evaluate other technology as it becomes available.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by or under review by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2020 and will cost an additional $9.5 million. In September 2018, SCE&G submitted an updated remediation work plan for one site (Congaree River) to DHEC which, if approved and subsequently permitted by the USACE, would increase remediation cost for that site by approximately $8 million. DHEC is considering a revised remedy under a MRA but has not issued its direction or approval. SCE&G cannot predict if or when DHEC and the USACE may approve or issue permits for this work to proceed. Major remediation activities are accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheets. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At December 31, 2018, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $23.3 million and are included in regulatory assets.

Operating Lease Commitments

The Company and Consolidated SCE&G are obligated under various operating leases for land, office space, furniture, equipment, rail cars, and for the Company, airplanes. Leases expire at various dates through 2057.

	Rent Expense						Future Minimum Rental Payments
Millions of dollars	2016		2017		2018		2019		2020		2021		2022		2023		Thereafter
The Company	$	10.2	$	10	$	9.7	$	10	$	8	$	7	$	6	$	4	$	30
Consolidated SCE&G	12.2		11.4		10.2		3		2		1		1		—		16

Guarantees, Surety Bonds and Letters of Credit

SCANA has issued guarantees on behalf of its consolidated subsidiaries to facilitate commercial transactions with third parties. These guarantees are in the form of performance guarantees, primarily for the purchase and transportation of natural gas, and credit support for certain tax-exempt bond issues. SCANA is not required to recognize a liability for such guarantees unless it becomes probable that performance under the guarantees will be required. SCANA believes the likelihood that it would be required to perform or otherwise incur any losses associated with these guarantees is not probable; therefore, no liability for these guarantees has been recognized. To the extent that a liability subject to a guarantee has been incurred, the liability is included in the consolidated financial statements. At December 31, 2018, the maximum future payments (undiscounted) that SCANA could be required to make under guarantees totaled approximately $444.6 million.

At December 31, 2018, SCE&G had purchased a $100.4 million surety bond to facilitate commercial transactions with Dominion Energy Carolina Gas Transmission LLC, which became an affiliate in connection with the SCANA Combination. Under the terms of the surety bond, SCE&G is obligated to indemnify the surety bond company for any amounts paid. Further, the Company had authorized the issuance of letters of credit by financial institutions of approximately $80.4 million, including approximately $39.3 million by Consolidated SCE&G, primarily to facilitate commercial transactions and to provide credit support for certain tax-exempt bond issues. Certain of these letters of credit are supported by lines of credit and are discussed in Note 5.

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 the Company’s regulated utility operations.  As of December 31, 2018, the Company and Consolidated SCE&G have recorded AROs of approximately $218 million for nuclear plant decommissioning (see Note 1). In addition, the Company has recorded AROs of approximately $359 million, including $323 million for Consolidated SCE&G, 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: 

	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Beginning balance	$	568		$	558		$	529		$	522
Liabilities incurred	—			—			—			—
Liabilities settled	(15		)	(10		)	(15		)	(9		)
Accretion expense	25			25			23			23
Revisions in estimated cash flows	(1		)	(5		)	4			(7		)
Ending balance	$	577		$	568		$	541		$	529

Revisions in estimated cash flows in 2018 and 2017 primarily related to ash pond retirement obligations settled and updates in the anticipated timing of cash flows as work is completed.

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SEGMENT OF BUSINESS INFORMATION

12 Months Ended

Dec. 31, 2018

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

  SEGMENT OF BUSINESS INFORMATION

Reportable segments, which are described below, follow the same accounting policies as those described in Note 1. Intersegment sales and transfers of electricity and gas are recorded based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.

Electric Operations primarily generates, transmits and distributes electricity, and is regulated by the SCPSC and FERC. Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, purchases and sells natural gas, primarily at retail. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively. Gas Marketing is comprised of the marketing operations of SCANA Energy, which markets natural gas to retail customers in Georgia and to industrial and large commercial customers and municipalities in the Southeast.

All Other includes the parent company and a services company.

Regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations’ product differs from the other segments, as does its generation process and method of distribution. Gas Marketing operates in a deregulated environment.

Management uses operating income (loss) to measure segment profitability for its regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, no allocation is made to segments for interest charges, income tax expense (benefit) or assets other than utility plant. For nonregulated operations, management uses net income (loss) as the measure of segment profitability and evaluates total assets for financial position. Intersegment revenue for SCE&G was not significant. Interest income is not reported by segment and is not material. Deferred tax assets are netted with deferred tax liabilities for consolidated reporting purposes.

The consolidated financial statements report operating revenues which are comprised of the energy-related and regulated segments. Revenues from non-reportable and nonregulated segments are included in Other Income. Therefore, the adjustments to total operating revenues remove revenues from non-reportable segments. Adjustments to net income (loss) consist of the unallocated net income (loss) of regulated reportable segments.

 Segment Assets include utility plant, net for SCE&G’s Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G.

Adjustments to Interest Expense, Income Tax Expense (Benefit), Expenditures for Assets and Deferred Tax Assets include primarily the amounts that are not allocated to the segments. Interest Expense is also adjusted to eliminate charges between affiliates. Adjustments to Depreciation and Amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Expenditures for Assets are adjusted for AFC and revisions to estimated cash flows related to AROs, and totals not allocated to other segments. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis.

Disclosure of Reportable Segments 

The Company:

Millions of dollars	Electric Operations			Gas Distribution		Gas Marketing		All Other			Adjustments/ Eliminations			Consolidated Total
2018
External Revenue	$	2,322		$	934	$	796	—			—			$	4,052
Intersegment Revenue	5			1		139		$	470		$	(615	)	—
Operating Income (Loss)	(894		)	173		n/a		—			(8		)	(729		)
Interest Expense	18			37		1		—			328			384
Depreciation and Amortization	307			94		2		15			(15		)	403
Income Tax Expense (Benefit)	9			26		15		(25		)	(437		)	(412		)
Net Income (Loss)	n/a			n/a		43		(90		)	(481		)	(528		)
Segment Assets	7,988			3,517		305		1,212			4,632			17,654
Expenditures for Assets	973			345		2		8			(438		)	890
Deferred Tax Assets	4			17		2		—			(23		)	—
2017
External Revenue	$	2,659		$	874	$	874	—			—			$	4,407
Intersegment Revenue	5			2		127		$	389		$	(523	)	—
Operating Income (Loss)	(154		)	187		n/a		—			52			85
Interest Expense	19			28		1		—			315			363
Depreciation and Amortization	295			85		2		16			(16		)	382
Income Tax Expense (Benefit)	8			41		25		(7		)	(179		)	(112		)
Net Income (Loss)	n/a			n/a		27		(46		)	(100		)	(119		)
Segment Assets	11,979			3,259		230		1,042			2,229			18,739
Expenditures for Assets	216			417		2		7			583			1,225
Deferred Tax Assets	6			25		9		—			(40		)	—
2016
External Revenue	$	2,614		$	788	$	825	—			—			$	4,227
Intersegment Revenue	5			2		111		$	414		$	(532	)	—
Operating Income	969			149		n/a		—			49			1,167
Interest Expense	17			25		1		—			299			342
Depreciation and Amortization	287			82		2		16			(16		)	371
Income Tax Expense	8			32		19		—			212			271
Net Income (Loss)	n/a			n/a		30		(18		)	583			595
Segment Assets	11,929			2,892		230		1,124			2,532			18,707
Expenditures for Assets	1,275			276		2		11			15			1,579

Deferred Tax Assets 9 32 11 — (52 ) —

Consolidated SCE&G:

Millions of dollars	Electric Operations			Gas Distribution		Adjustments/ Eliminations			Consolidated Total
2018
External Revenue	$	2,327		$	435	—			$	2,762
Operating Income (Loss)	(894		)	63		—			(831		)
Interest Expense	18			—		$	285		303
Depreciation and Amortization	307			32		(12		)	327
Segment Assets	7,988			934		6,041			14,963
Expenditures for Assets	973			90		(430		)	633
Deferred Tax Assets	4			n/a		(4		)	—
2017
External Revenue	$	2,664		$	406	—			$	3,070
Operating Income (Loss)	(154		)	71		—			(83		)
Interest Expense	19			—		$	269		288
Depreciation and Amortization	295			30		(13		)	312
Segment Assets	11,979			869		3,098			15,946
Expenditures for Assets	216			65		647			928
Deferred Tax Assets	6			n/a		(6		)	—
2016
External Revenue	$	2,619		$	367	—			$	2,986
Operating Income	969			56		—			1,025
Interest Expense	17			—		$	253		270
Depreciation and Amortization	287			28		(13		)	302
Segment Assets	11,929			825		3,337			16,091
Expenditures for Assets	1,275			78		46			1,399
Deferred Tax Assets	9			n/a		(9		)	—

SCE&G

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

SEGMENT OF BUSINESS INFORMATION

Reportable segments, which are described below, follow the same accounting policies as those described in Note 1. Intersegment sales and transfers of electricity and gas are recorded based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.

Electric Operations primarily generates, transmits and distributes electricity, and is regulated by the SCPSC and FERC. Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, purchases and sells natural gas, primarily at retail. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively. Gas Marketing is comprised of the marketing operations of SCANA Energy, which markets natural gas to retail customers in Georgia and to industrial and large commercial customers and municipalities in the Southeast.

All Other includes the parent company and a services company.

Regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations’ product differs from the other segments, as does its generation process and method of distribution. Gas Marketing operates in a deregulated environment.

Management uses operating income (loss) to measure segment profitability for its regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, no allocation is made to segments for interest charges, income tax expense (benefit) or assets other than utility plant. For nonregulated operations, management uses net income (loss) as the measure of segment profitability and evaluates total assets for financial position. Intersegment revenue for SCE&G was not significant. Interest income is not reported by segment and is not material. Deferred tax assets are netted with deferred tax liabilities for consolidated reporting purposes.

The consolidated financial statements report operating revenues which are comprised of the energy-related and regulated segments. Revenues from non-reportable and nonregulated segments are included in Other Income. Therefore, the adjustments to total operating revenues remove revenues from non-reportable segments. Adjustments to net income (loss) consist of the unallocated net income (loss) of regulated reportable segments.

 Segment Assets include utility plant, net for SCE&G’s Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G.

Adjustments to Interest Expense, Income Tax Expense (Benefit), Expenditures for Assets and Deferred Tax Assets include primarily the amounts that are not allocated to the segments. Interest Expense is also adjusted to eliminate charges between affiliates. Adjustments to Depreciation and Amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Expenditures for Assets are adjusted for AFC and revisions to estimated cash flows related to AROs, and totals not allocated to other segments. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis.

Disclosure of Reportable Segments 

The Company:

Millions of dollars	Electric Operations			Gas Distribution		Gas Marketing		All Other			Adjustments/ Eliminations			Consolidated Total
2018
External Revenue	$	2,322		$	934	$	796	—			—			$	4,052
Intersegment Revenue	5			1		139		$	470		$	(615	)	—
Operating Income (Loss)	(894		)	173		n/a		—			(8		)	(729		)
Interest Expense	18			37		1		—			328			384
Depreciation and Amortization	307			94		2		15			(15		)	403
Income Tax Expense (Benefit)	9			26		15		(25		)	(437		)	(412		)
Net Income (Loss)	n/a			n/a		43		(90		)	(481		)	(528		)
Segment Assets	7,988			3,517		305		1,212			4,632			17,654
Expenditures for Assets	973			345		2		8			(438		)	890
Deferred Tax Assets	4			17		2		—			(23		)	—
2017
External Revenue	$	2,659		$	874	$	874	—			—			$	4,407
Intersegment Revenue	5			2		127		$	389		$	(523	)	—
Operating Income (Loss)	(154		)	187		n/a		—			52			85
Interest Expense	19			28		1		—			315			363
Depreciation and Amortization	295			85		2		16			(16		)	382
Income Tax Expense (Benefit)	8			41		25		(7		)	(179		)	(112		)
Net Income (Loss)	n/a			n/a		27		(46		)	(100		)	(119		)
Segment Assets	11,979			3,259		230		1,042			2,229			18,739
Expenditures for Assets	216			417		2		7			583			1,225
Deferred Tax Assets	6			25		9		—			(40		)	—
2016
External Revenue	$	2,614		$	788	$	825	—			—			$	4,227
Intersegment Revenue	5			2		111		$	414		$	(532	)	—
Operating Income	969			149		n/a		—			49			1,167
Interest Expense	17			25		1		—			299			342
Depreciation and Amortization	287			82		2		16			(16		)	371
Income Tax Expense	8			32		19		—			212			271
Net Income (Loss)	n/a			n/a		30		(18		)	583			595
Segment Assets	11,929			2,892		230		1,124			2,532			18,707
Expenditures for Assets	1,275			276		2		11			15			1,579

Deferred Tax Assets 9 32 11 — (52 ) —

Consolidated SCE&G:

Millions of dollars	Electric Operations			Gas Distribution		Adjustments/ Eliminations			Consolidated Total
2018
External Revenue	$	2,327		$	435	—			$	2,762
Operating Income (Loss)	(894		)	63		—			(831		)
Interest Expense	18			—		$	285		303
Depreciation and Amortization	307			32		(12		)	327
Segment Assets	7,988			934		6,041			14,963
Expenditures for Assets	973			90		(430		)	633
Deferred Tax Assets	4			n/a		(4		)	—
2017
External Revenue	$	2,664		$	406	—			$	3,070
Operating Income (Loss)	(154		)	71		—			(83		)
Interest Expense	19			—		$	269		288
Depreciation and Amortization	295			30		(13		)	312
Segment Assets	11,979			869		3,098			15,946
Expenditures for Assets	216			65		647			928
Deferred Tax Assets	6			n/a		(6		)	—
2016
External Revenue	$	2,619		$	367	—			$	2,986
Operating Income	969			56		—			1,025
Interest Expense	17			—		$	253		270
Depreciation and Amortization	287			28		(13		)	302
Segment Assets	11,929			825		3,337			16,091
Expenditures for Assets	1,275			78		46			1,399
Deferred Tax Assets	9			n/a		(9		)	—

XML

UTILITY PLANT AND NONUTILITY PROPERTY (Notes)

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment Disclosure [Text Block]

   UTILITY PLANT AND NONUTILITY PROPERTY

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

Millions of dollars	The Company		Consolidated SCE&G
Gross Utility Plant:
Generation	$	5,751	$	5,751
Transmission	2,417		1,758
Distribution	6,032		4,456
Storage	99		74
General and other	631		535
Intangible	241		229
Construction work in progress	527		350
Nuclear Fuel	611		611
Total Gross Utility Plant	$	16,309	$	13,764
Gross Nonutility Property	$	410	$	73

Jointly Owned Utility Plant

SCE&G jointly owns and is the operator of Unit 1. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. Unit 2 and Unit 3 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 2.

As of December 31,	2018			2017
	Unit 1			Unit 1
Percent owned	66.7%			66.7%
Plant in service	$	1.5	billion	$	1.5	billion
Accumulated depreciation	$	643.9	million	$	637.6	million
Construction work in progress	$	127.5	million	$	110.1	million

Included within other receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses. These amounts totaled $46.3 million at December 31, 2018 and $53.8 million at December 31, 2017.

SCE&G

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment Disclosure [Text Block]

UTILITY PLANT AND NONUTILITY PROPERTY

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

Millions of dollars	The Company		Consolidated SCE&G
Gross Utility Plant:
Generation	$	5,751	$	5,751
Transmission	2,417		1,758
Distribution	6,032		4,456
Storage	99		74
General and other	631		535
Intangible	241		229
Construction work in progress	527		350
Nuclear Fuel	611		611
Total Gross Utility Plant	$	16,309	$	13,764
Gross Nonutility Property	$	410	$	73

Jointly Owned Utility Plant

SCE&G jointly owns and is the operator of Unit 1. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. Unit 2 and Unit 3 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 2.

As of December 31,	2018			2017
	Unit 1			Unit 1
Percent owned	66.7%			66.7%
Plant in service	$	1.5	billion	$	1.5	billion
Accumulated depreciation	$	643.9	million	$	637.6	million
Construction work in progress	$	127.5	million	$	110.1	million

Included within other receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses. These amounts totaled $46.3 million at December 31, 2018 and $53.8 million at December 31, 2017.

XML

AFFILIATED TRANSACTIONS (Notes)

12 Months Ended

Dec. 31, 2018

Related Party Transaction [Line Items]

Related Party Transactions Disclosure [Text Block]

14.          AFFILIATED TRANSACTIONS

The Company:

The Company received cash distributions from equity-method investees of $2.3 million in 2018, $2.8 million in 2017 and $3.7 million in 2016. The Company made investments in equity-method investees of $4.2 million in 2018, $4.6 million in 2017 and $5.5 million in 2016.

The Company and Consolidated SCE&G:

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of operations (for the Company) and of comprehensive income (for Consolidated SCE&G).

Millions of Dollars	2018		2017		2016
Purchases from Canadys Refined Coal, LLC	$	149.9	$	162.1	$	161.8
Sales to Canadys Refined Coal, LLC	149.0		161.1		160.8

Millions of Dollars	2018		2017
Receivable from Canadys Refined Coal, LLC	$	6.8	$	4.9
Payable to Canadys Refined Coal, LLC	6.8		4.9

Consolidated SCE&G:

SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. 

SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, 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, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in Other operation and maintenance - nonconsolidated affiliate and Other Income (Expense), net on the consolidated statements of comprehensive income.

Millions of Dollars	2018		2017		2016
Purchases from SCANA Energy	$	139.0	$	127.4	$	111.5
Direct and Allocated Costs from SCANA Services	283.3		302.8		337.7

Millions of Dollars	2018		2017
Payable to SCANA Energy	$	14.1	$	10.0
Payable to SCANA Services	37.7		42.0

Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 5. Certain disclosures regarding SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 9.

SCE&G

Related Party Transaction [Line Items]

Related Party Transactions Disclosure [Text Block]

14.          AFFILIATED TRANSACTIONS

The Company:

The Company received cash distributions from equity-method investees of $2.3 million in 2018, $2.8 million in 2017 and $3.7 million in 2016. The Company made investments in equity-method investees of $4.2 million in 2018, $4.6 million in 2017 and $5.5 million in 2016.

The Company and Consolidated SCE&G:

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of operations (for the Company) and of comprehensive income (for Consolidated SCE&G).

Millions of Dollars	2018		2017		2016
Purchases from Canadys Refined Coal, LLC	$	149.9	$	162.1	$	161.8
Sales to Canadys Refined Coal, LLC	149.0		161.1		160.8

Millions of Dollars	2018		2017
Receivable from Canadys Refined Coal, LLC	$	6.8	$	4.9
Payable to Canadys Refined Coal, LLC	6.8		4.9

Consolidated SCE&G:

SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. 

SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, 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, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in Other operation and maintenance - nonconsolidated affiliate and Other Income (Expense), net on the consolidated statements of comprehensive income.

Millions of Dollars	2018		2017		2016
Purchases from SCANA Energy	$	139.0	$	127.4	$	111.5
Direct and Allocated Costs from SCANA Services	283.3		302.8		337.7

Millions of Dollars	2018		2017
Payable to SCANA Energy	$	14.1	$	10.0
Payable to SCANA Services	37.7		42.0

Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 5. Certain disclosures regarding SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 9.

XML

OTHER INCOME (EXPENSE), NET (Notes)

12 Months Ended

Dec. 31, 2018

Other Income and Other Expense Disclosure [Text Block]

OTHER INCOME (EXPENSE), NET

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

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
Revenues from contracts with customers	$	20		—			—			$	5		—			—
Other income	180			$	79		$	64		141			$	45		$	29
Other expense	(46		)	(55		)	(52		)	(28		)	(32		)	(36		)
Allowance for equity funds used during construction	19			23			29			11			15			26
Other income (expense), net	$	173		$	47		$	41		$	129		$	28		$	19

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 3, and as permitted, prior periods have not been restated. For the Company and Consolidated SCE&G, other income in 2018 includes gains from the settlement of interest rate derivatives of approximately $114 million (see Note 7). For the Company and Consolidated SCE&G, non-service cost components of pension and other postretirement benefits are included in other expense.

SCE&G

Other Income and Other Expense Disclosure [Text Block]

OTHER INCOME (EXPENSE), NET

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

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
Revenues from contracts with customers	$	20		—			—			$	5		—			—
Other income	180			$	79		$	64		141			$	45		$	29
Other expense	(46		)	(55		)	(52		)	(28		)	(32		)	(36		)
Allowance for equity funds used during construction	19			23			29			11			15			26
Other income (expense), net	$	173		$	47		$	41		$	129		$	28		$	19

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 3, and as permitted, prior periods have not been restated. For the Company and Consolidated SCE&G, other income in 2018 includes gains from the settlement of interest rate derivatives of approximately $114 million (see Note 7). For the Company and Consolidated SCE&G, non-service cost components of pension and other postretirement benefits are included in other expense.

XML

QUARTERLY FINANCIAL INFORMATION (Notes)

12 Months Ended

Dec. 31, 2018

Entity Information [Line Items]

Quarterly Financial Information [Text Block]

QUARTERLY FINANCIAL DATA (UNAUDITED)

The Company Millions of dollars, except per share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Annual
2018
Total Operating Revenues	$	1,180	$	843	$	926	$	1,103		$	4,052
Operating Income (Loss)	189		103		183		(1,204		)	(729		)
Net Income (Loss)	169		8		67		(772		)	(528		)
Earnings (Loss) Per Share of Common Stock	1.18		0.06		0.47		(5.41		)	(3.70		)
2017
Total Operating Revenues	$	1,173	$	1,001	$	1,076	$	1,157		$	4,407
Operating Income (Loss)	320		251		122		(608		)	85
Net Income (Loss)	171		121		34		(445		)	(119		)
Earnings (Loss) Per Share of Common Stock	1.19		0.85		0.24		(3.11		)	(0.83		)

Consolidated SCE&G Millions of dollars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Annual
2018
Total Operating Revenues	$	702	$	632	$	739	$	689		$	2,762
Operating Income (Loss)	121		107		212		(1,271		)	(831		)
Total Comprehensive Income (Loss)	128		31		104		(852		)	(589		)
Comprehensive Income Available (Loss Attributable) to Common Shareholder	124		26		98		(861		)	(613		)
2017
Total Operating Revenues	$	719	$	756	$	856	$	739		$	3,070
Operating Income (Loss)	226		247		124		(680		)	(83		)
Total Comprehensive Income (Loss)	112		126		42		(452		)	(172		)
Comprehensive Income Available (Loss Attributable) to Common Shareholder	109		123		39		(456		)	(185		)

See Note 11 for a discussion of impairment losses booked in the third and fourth quarter of 2017 and the first and fourth quarter of 2018.

SCE&G

Entity Information [Line Items]

Quarterly Financial Information [Text Block]

16.          QUARTERLY FINANCIAL DATA (UNAUDITED)

The Company Millions of dollars, except per share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Annual
2018
Total Operating Revenues	$	1,180	$	843	$	926	$	1,103		$	4,052
Operating Income (Loss)	189		103		183		(1,204		)	(729		)
Net Income (Loss)	169		8		67		(772		)	(528		)
Earnings (Loss) Per Share of Common Stock	1.18		0.06		0.47		(5.41		)	(3.70		)
2017
Total Operating Revenues	$	1,173	$	1,001	$	1,076	$	1,157		$	4,407
Operating Income (Loss)	320		251		122		(608		)	85
Net Income (Loss)	171		121		34		(445		)	(119		)
Earnings (Loss) Per Share of Common Stock	1.19		0.85		0.24		(3.11		)	(0.83		)

Consolidated SCE&G Millions of dollars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Annual
2018
Total Operating Revenues	$	702	$	632	$	739	$	689		$	2,762
Operating Income (Loss)	121		107		212		(1,271		)	(831		)
Total Comprehensive Income (Loss)	128		31		104		(852		)	(589		)
Comprehensive Income Available (Loss Attributable) to Common Shareholder	124		26		98		(861		)	(613		)
2017
Total Operating Revenues	$	719	$	756	$	856	$	739		$	3,070
Operating Income (Loss)	226		247		124		(680		)	(83		)
Total Comprehensive Income (Loss)	112		126		42		(452		)	(172		)
Comprehensive Income Available (Loss Attributable) to Common Shareholder	109		123		39		(456		)	(185		)

See Note 11 for a discussion of impairment losses booked in the third and fourth quarter of 2017 and the first and fourth quarter of 2018.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2018

Significant Accounting Policies

Consolidation, Policy [Policy Text Block]

Organization and Principles of Consolidation

Effective January 1, 2019, SCANA became a wholly-owned subsidiary of Dominion Energy under the terms of the Merger Agreement. See additional discussion in Note 2 and Note 11.

The Company

SCANA, a South Carolina corporation, is a holding company created in 1984. The Company primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina, and the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia.

The accompanying consolidated financial statements reflect the accounts of SCANA and the following wholly-owned subsidiaries.

Regulated businesses	Nonregulated businesses
South Carolina Electric & Gas Company	SCANA Energy Marketing, Inc.
South Carolina Fuel Company, Inc.	SCANA Services, Inc.
South Carolina Generating Company, Inc.	SCANA Corporate Security Services, Inc.
Public Service Company of North Carolina, Incorporated	SCANA Communications Holdings, Inc.

SCANA reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. Discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

Consolidated SCE&G

SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA. Consolidated SCE&G primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s 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, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $500 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5.

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Property, Plant and Equipment, Planned Major Maintenance Activities, Policy [Policy Text Block]

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 SCPSC 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.

SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2018, and 2017, SCE&G incurred $16.3 million and $26.1 million, respectively, for turbine maintenance.

Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 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 SCE&G was responsible totaled

Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]

Goodwill

The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company has tested goodwill for impairment annually as of January 1, unless indicators, events or circumstances required interim testing to be performed. The Company performed its test on January 1, 2019 and intends to test goodwill annually on April 1, effective April 1, 2019. Under current accounting guidance, the Company may perform a qualitative assessment of impairment. Based on this assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to make a quantitative estimate of the fair value of the reporting unit and to compare that amount to its carrying value. If the Company is required to make a quantitative assessment or if it chooses to do so without first performing a qualitative one, and if the quantitative assessment indicates a carrying value in excess of fair value, an impairment charge would be required. Any such charge would be treated as an operating expense.

For each period presented, assets with a carrying value of $210 million for PSNC Energy (Gas Distribution segment), net of a writedown of $230 million taken in 2002, were classified as goodwill. The Company performed a quantitative assessment of goodwill in its evaluation as of January 1, 2019 and performed a qualitative assessment of goodwill in its evaluation as of January 1, 2018. No impairment of goodwill was required based on these evaluations.

Nuclear Decommissiong [Policy Text Block]

Nuclear Decommissioning

Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $625.8 million, stated in 2018 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. 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 SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ($3.2 million pre-tax 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 Unit 1 on an after-tax basis.

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds.

Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block]

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 3. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $217.5 million at December 31, 2018 and $220.9 million at December 31, 2017 for the Company. Unbilled revenues totaled $129.3 million at December 31, 2018 and $140.3 million at December 31, 2017 for Consolidated SCE&G.

Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station.

Inventory, Policy [Policy Text Block]

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 SCPSC or NCUC, as applicable.

Asset Management and Supply Service Agreements [Policy Text Block]

PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 46% and 39% of PSNC Energy’s natural gas inventory at December 31, 2018 and December 31, 2017, respectively, with a carrying value of $13.9 million and $11.5 million, respectively. Under the terms of this agreement, PSNC Energy receives storage asset management feesof which 75% are credited to customers. This agreement has been extended and expires October 31, 2020.

Income Tax, Policy [Policy Text Block]

Income Taxes

SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 6 for a discussion of the impact of adjustments recorded in connection with enactment of the Tax Act.

Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA for all periods presented. Also, under provisions of an income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions.

regulatory assets and regulatory liabilities [Policy Text Block]

Regulatory Assets and Regulatory Liabilities

The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods that differ from those in which the costs would be charged to expense, or record revenues in periods that differ from those in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified on the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively.

Debt Premium, Discount, and Expense [Policy Text Block]

Debt Issuance Premiums, Discounts and Other Costs

Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred credits or debits and are amortized over the term of the replacement debt, also as interest charges.

Environmental Costs, Policy [Policy Text Block]

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.

Income Statement policy [Policy Text Block]

Statement of Operations Presentation

Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense).

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed.

Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings.

SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews.

Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of operations.

Earnings Per Share, Policy [Policy Text Block]

Earnings (Loss) Per Share

The Company computes basic earnings (loss) per share by dividing net income (loss) by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings (loss) per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.

New Accounting Matters [Policy Text Block]

New Accounting Matters

Recently Adopted

In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact or no significant impact on their respective financial statements except as indicated.

• Goodwill impairment guidance, issued in January 2017, removed Step 2 of the goodwill impairment test.

• Guidance for revenue arising from contracts with customers uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods were not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3.

• The required presentation of net periodic pension and postretirement benefit costs has been changed to distinguish between service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees. Non-service cost components are now excluded from operating income. This guidance has been applied retrospectively for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017 and 2016.

Increase (Decrease) Millions of dollars	The Company						Consolidated SCE&G
Year Ended December 31	2017			2016			2017			2016
Other operation and maintenance	$	(9	)	$	(14	)	$	(7	)	$	(12	)
Total Operating Expenses	(9		)	(14		)	(7		)	(12		)
Operating Income	9			14			7			12
Other Income (Expense), Net	(9		)	(14		)	(7		)	(12		)

In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost component, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs. Effective January 1, 2018, amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets.

• Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things.

• Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented.

• Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented.

Pending Adoption

The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below.

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 currently 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 is effective for the Company's and Consolidated SCE&G's interim and annual reporting periods beginning January 1, 2019. This revised accounting guidance will be adopted using a modified-retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Company and Consolidated SCE&G are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Company and Consolidated SCE&G will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. The Company and Consolidated SCE&G anticipate that the adoption of this guidance will result in approximately $30 million to $35 million and $15 million to $20 million, respectively, of offsetting right-of-use assets and liabilities added to their consolidated balance sheets for operating leases in effect at the adoption date. No material changes are expected to the Company's and Consolidated SCE&G's results of operations.

In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 and do not expect it to have a significant impact on their respective financial statements.

In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 on a prospective basis. Upon adoption, the Company and Consolidated SCE&G expect to record cumulative effect adjustments to retained earnings and AOCI in their statements of changes in common equity (in the amount of $8 million and $1 million at the Company and Consolidated SCE&G, respectively) and do not expect any other significant impact on their financial statements. The amounts to be reclassified reflect the impact of the reduction in the federal income tax rate arising from the Tax Act, and the related federal benefit of state income taxes, on the components of the Company’s and Consolidated SCE&G’s AOCI.

In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. A modified-retrospective approach is required upon adoption, whereby a cumulative-effect adjustment to retained earnings is made as of the beginning of the first reporting period in which the guidance is effective. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements.

In August 2018, the FASB issued accounting guidance to modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance must be applied retrospectively to all periods presented. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position.

SCE&G

Significant Accounting Policies

Consolidation, Policy [Policy Text Block]

Consolidated SCE&G

SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA. Consolidated SCE&G primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s 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, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $500 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5.

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Property, Plant and Equipment, Planned Major Maintenance Activities, Policy [Policy Text Block]

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 SCPSC 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.

SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2018, and 2017, SCE&G incurred $16.3 million and $26.1 million, respectively, for turbine maintenance.

Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 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 SCE&G was responsible totaled

Nuclear Decommissiong [Policy Text Block]

Nuclear Decommissioning

Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $625.8 million, stated in 2018 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. 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 SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ($3.2 million pre-tax 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 Unit 1 on an after-tax basis.

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds.

Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block]

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 3. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $217.5 million at December 31, 2018 and $220.9 million at December 31, 2017 for the Company. Unbilled revenues totaled $129.3 million at December 31, 2018 and $140.3 million at December 31, 2017 for Consolidated SCE&G.

Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station.

Inventory, Policy [Policy Text Block]

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 SCPSC or NCUC, as applicable.

Income Tax, Policy [Policy Text Block]

Income Taxes

SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 6 for a discussion of the impact of adjustments recorded in connection with enactment of the Tax Act.

Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA for all periods presented. Also, under provisions of an income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions.

regulatory assets and regulatory liabilities [Policy Text Block]

Regulatory Assets and Regulatory Liabilities

The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods that differ from those in which the costs would be charged to expense, or record revenues in periods that differ from those in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified on the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively.

Debt Premium, Discount, and Expense [Policy Text Block]

Debt Issuance Premiums, Discounts and Other Costs

Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred credits or debits and are amortized over the term of the replacement debt, also as interest charges.

Environmental Costs, Policy [Policy Text Block]

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.

Income Statement policy [Policy Text Block]

Statement of Operations Presentation

Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense).

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed.

Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings.

SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews.

Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of operations. 

New Accounting Matters [Policy Text Block]

New Accounting Matters

Recently Adopted

In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact or no significant impact on their respective financial statements except as indicated.

• Goodwill impairment guidance, issued in January 2017, removed Step 2 of the goodwill impairment test.

• Guidance for revenue arising from contracts with customers uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods were not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3.

• The required presentation of net periodic pension and postretirement benefit costs has been changed to distinguish between service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees. Non-service cost components are now excluded from operating income. This guidance has been applied retrospectively for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017 and 2016.

Increase (Decrease) Millions of dollars	The Company						Consolidated SCE&G
Year Ended December 31	2017			2016			2017			2016
Other operation and maintenance	$	(9	)	$	(14	)	$	(7	)	$	(12	)
Total Operating Expenses	(9		)	(14		)	(7		)	(12		)
Operating Income	9			14			7			12
Other Income (Expense), Net	(9		)	(14		)	(7		)	(12		)

In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost component, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs. Effective January 1, 2018, amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets.

• Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things.

• Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented.

• Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented.

Pending Adoption

The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below.

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 currently 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 is effective for the Company's and Consolidated SCE&G's interim and annual reporting periods beginning January 1, 2019. This revised accounting guidance will be adopted using a modified-retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Company and Consolidated SCE&G are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Company and Consolidated SCE&G will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. The Company and Consolidated SCE&G anticipate that the adoption of this guidance will result in approximately $30 million to $35 million and $15 million to $20 million, respectively, of offsetting right-of-use assets and liabilities added to their consolidated balance sheets for operating leases in effect at the adoption date. No material changes are expected to the Company's and Consolidated SCE&G's results of operations.

In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 and do not expect it to have a significant impact on their respective financial statements.

In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 on a prospective basis. Upon adoption, the Company and Consolidated SCE&G expect to record cumulative effect adjustments to retained earnings and AOCI in their statements of changes in common equity (in the amount of $8 million and $1 million at the Company and Consolidated SCE&G, respectively) and do not expect any other significant impact on their financial statements. The amounts to be reclassified reflect the impact of the reduction in the federal income tax rate arising from the Tax Act, and the related federal benefit of state income taxes, on the components of the Company’s and Consolidated SCE&G’s AOCI.

In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. A modified-retrospective approach is required upon adoption, whereby a cumulative-effect adjustment to retained earnings is made as of the beginning of the first reporting period in which the guidance is effective. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements.

In August 2018, the FASB issued accounting guidance to modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance must be applied retrospectively to all periods presented. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2018

Significant Accounting Policies

Reclassifications [Text Block]

Increase (Decrease) Millions of dollars	The Company						Consolidated SCE&G
Year Ended December 31	2017			2016			2017			2016
Other operation and maintenance	$	(9	)	$	(14	)	$	(7	)	$	(12	)
Total Operating Expenses	(9		)	(14		)	(7		)	(12		)
Operating Income	9			14			7			12
Other Income (Expense), Net	(9		)	(14		)	(7		)	(12		)

Schedule of weighted avg depreciation rates [Table Text Block]

	The Company		Consolidated SCE&G
Generation	2.61	%	2.61	%
Transmission	2.47	%	2.74	%
Distribution	2.48	%	2.41	%
Storage	2.48	%	2.71	%
General and other	5.64	%	3.18	%

SCE&G

Significant Accounting Policies

Reclassifications [Text Block]

Increase (Decrease) Millions of dollars	The Company						Consolidated SCE&G
Year Ended December 31	2017			2016			2017			2016
Other operation and maintenance	$	(9	)	$	(14	)	$	(7	)	$	(12	)
Total Operating Expenses	(9		)	(14		)	(7		)	(12		)
Operating Income	9			14			7			12
Other Income (Expense), Net	(9		)	(14		)	(7		)	(12		)

Schedule of weighted avg depreciation rates [Table Text Block]

	The Company		Consolidated SCE&G
Generation	2.61	%	2.61	%
Transmission	2.47	%	2.74	%
Distribution	2.48	%	2.41	%
Storage	2.48	%	2.71	%
General and other	5.64	%	3.18	%

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RATE AND OTHER REGULATORY MATTERS (Tables)

12 Months Ended

Dec. 31, 2018

Public Utilities, General Disclosures

Pipeline integrity management revenue requirement [Table Text Block]

Rates Effective	2018	2017
March 1	$14.7 million	$1.9 million
September 1	$1.1 million	$0.7 million

Demand reduction programs [Table Text Block]

Year	Effective	Amount
2018	First billing cycle of May	$33.0 million
2017	First billing cycle of May	$37.0 million
2016	First billing cycle of May	$37.6 million

Schedule of Changes in Gas Rate RSA [Table Text Block]

Year	Action			Amount
2018	4.6	%	Decrease	$19.7 million	*
2017	2.2	%	Increase	$8.6 million
2016	1.2	%	Increase	$4.1 million

Schedule of Regulatory Assets [Table Text Block]

	The Company				Consolidated SCE&G
	December 31,				December 31,
Millions of dollars	2018		2017		2018		2017
Regulatory Assets:
Unrecovered Nuclear Project costs	$	2,768	3,976		$	2,768	3,976
AROs and related funding	406		434		380		410
Deferred employee benefit plan costs	302		305		272		273
Deferred losses on interest rate derivatives	448		456		448		456
Other unrecovered plant	93		105		93		105
DSM Programs	65		59		65		59
Pipeline integrity management costs	73		51		9		8
Environmental remediation costs	27		30		24		25
Deferred storm damage costs	35		24		35		24
Deferred transmission operating costs	15		—		15		—
Other	148		140		147		140
Total Regulatory Assets	$	4,380	$	5,580	$	4,256	$	5,476

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Monetization of guaranty settlement	$	1,098	1,095		$	1,098	1,095
Accumulated deferred income taxes	814		1,076		659		914
Asset removal costs	779		757		541		527
Deferred gains on interest rate derivatives	77		131		77		131
Other	21		—		5		—
Total Regulatory Liabilities	$	2,789	$	3,059	$	2,380	$	2,667

SCE&G

Public Utilities, General Disclosures

Demand reduction programs [Table Text Block]

Year	Effective	Amount
2018	First billing cycle of May	$33.0 million
2017	First billing cycle of May	$37.0 million
2016	First billing cycle of May	$37.6 million

Schedule of Changes in Gas Rate RSA [Table Text Block]

Year	Action			Amount
2018	4.6	%	Decrease	$19.7 million	*
2017	2.2	%	Increase	$8.6 million
2016	1.2	%	Increase	$4.1 million

Schedule of Regulatory Assets [Table Text Block]

	The Company				Consolidated SCE&G
	December 31,				December 31,
Millions of dollars	2018		2017		2018		2017
Regulatory Assets:
Unrecovered Nuclear Project costs	$	2,768	3,976		$	2,768	3,976
AROs and related funding	406		434		380		410
Deferred employee benefit plan costs	302		305		272		273
Deferred losses on interest rate derivatives	448		456		448		456
Other unrecovered plant	93		105		93		105
DSM Programs	65		59		65		59
Pipeline integrity management costs	73		51		9		8
Environmental remediation costs	27		30		24		25
Deferred storm damage costs	35		24		35		24
Deferred transmission operating costs	15		—		15		—
Other	148		140		147		140
Total Regulatory Assets	$	4,380	$	5,580	$	4,256	$	5,476

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Monetization of guaranty settlement	$	1,098	1,095		$	1,098	1,095
Accumulated deferred income taxes	814		1,076		659		914
Asset removal costs	779		757		541		527
Deferred gains on interest rate derivatives	77		131		77		131
Other	21		—		5		—
Total Regulatory Liabilities	$	2,789	$	3,059	$	2,380	$	2,667

PSNC Energy [Member]

Public Utilities, General Disclosures

Pipeline integrity management revenue requirement [Table Text Block]

Rates Effective	2018	2017
March 1	$14.7 million	$1.9 million
September 1	$1.1 million	$0.7 million

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REVENUE RECOGNITION Disaggregation of Revenue and Capitalized Costs (Tables)

12 Months Ended

Dec. 31, 2018

Capitalized Contract Cost [Table Text Block]

The Company and Consolidated SCE&G
Millions of dollars	Regulatory Assets
January 1, 2018	$	16.3
Additional costs	—
Amortization	(1.5		)
Impairment	—
December 31, 2018	$	14.8

Disaggregation Revenue [Table Text Block]

The Company	Consolidated SCE&G				PSNC Energy		Total  Gas-regulated		Gas-nonregulated
Millions of dollars	Electric		Gas-regulated		Gas-regulated
2018
Customer class:
Residential	$	1,054	$	208	$	325	$	533	$	244
Commercial	744		117		125		242		92
Industrial	385		92		15		107		422
Transportation	—		13		32		45		—
Other	132		4		—		4		38
Revenues from contracts with customers	2,315		434		497		931		796
Other operating revenues	12		1		3		4		—
Total Operating Revenues	$	2,327	$	435	$	500	$	935	$	796

SCE&G

Capitalized Contract Cost [Table Text Block]

The Company and Consolidated SCE&G
Millions of dollars	Regulatory Assets
January 1, 2018	$	16.3
Additional costs	—
Amortization	(1.5		)
Impairment	—
December 31, 2018	$	14.8

Disaggregation Revenue [Table Text Block]

The Company	Consolidated SCE&G				PSNC Energy		Total  Gas-regulated		Gas-nonregulated
Millions of dollars	Electric		Gas-regulated		Gas-regulated
2018
Customer class:
Residential	$	1,054	$	208	$	325	$	533	$	244
Commercial	744		117		125		242		92
Industrial	385		92		15		107		422
Transportation	—		13		32		45		—
Other	132		4		—		4		38
Revenues from contracts with customers	2,315		434		497		931		796
Other operating revenues	12		1		3		4		—
Total Operating Revenues	$	2,327	$	435	$	500	$	935	$	796

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LONG-TERM AND SHORT-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2018

Debt Instrument [Line Items]

Schedule of Debt [Table Text Block]

:

The Company
December 31,				2018					2017
Dollars in millions	Maturity			Balance			Rate		Balance			Rate
SCANA Medium Term Notes (unsecured)	2020	-	2022	$	800		5.42	%	$	800		5.42	%
SCANA Senior Notes (unsecured) (a)	2019	-	2034	70			3.44	%	75			2.18	%
SCE&G First Mortgage Bonds (secured)	2021	-	2065	4,990			5.52	%	4,840			5.80	%
GENCO Notes (secured)	2019	-	2024	40			5.49	%	207			5.94	%
Industrial and Pollution Control Bonds (b)	2028	-	2038	122			3.52	%	122			3.52	%
PSNC Energy Senior Debentures and Notes	2020	-	2047	700			5.07	%	600			5.19	%
Other	2019	-	2027	73			3.46	%	28			2.83	%
Total debt				6,795					6,672
Current maturities of long-term debt				(59		)			(727		)
Unamortized discount, net				(2		)			(1		)
Unamortized debt issuance costs				(39		)			(38		)
Total long-term debt, net				$	6,695				$	5,906

Schedule of Line of Credit Facilities [Text Block]

December 31, 2017
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0	$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	500.0		—		500.0			—
Three-year, expiring December 2018	200.0		—		200.0			—
Total committed long-term	2,000.0		400.0		1,400.0			200.0
Outstanding commercial paper (270 or fewer days)	350.3		—		251.6			98.7
Weighted average interest rate					1.92		%	1.93		%
Letters of credit supported by LOC	3.3		3.0		0.3			—
Available	$	1,646.4	$	397.0	$	1,148.1		$	101.3

:

Millions of dollars	Total		SCANA			SCE&G			PSNC  Energy
December 31, 2018
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	500.0		—			500.0			—
Total committed long-term	1,800.0		400.0			1,200.0			200.0
LOC advances	40.0		40.0			—			—
Weighted average interest rate			3.87		%
Outstanding commercial paper (270 or fewer days)	172.9		2.0			73.2			97.7
Weighted average interest rate			3.65		%	3.82		%	3.49		%
Letters of credit supported by LOC	37.6		37.3			0.3			—
Available	$	1,549.5	$	320.7		$	1,126.5		$	102.3

SCE&G

Debt Instrument [Line Items]

Schedule of Debt [Table Text Block]

Consolidated SCE&G
December 31,				2018					2017
Dollars in millions	Maturity			Balance			Rate		Balance			Rate
First Mortgage Bonds (secured)	2021	-	2065	$	4,990		5.52	%	$	4,840		5.80	%
GENCO Notes (secured)	2019	-	2024	40			5.49	%	207			5.94	%
Industrial and Pollution Control Bonds (b)	2028	-	2038	122			3.52	%	122			3.52	%
Other	2019	-	2027	30			2.97	%	28			2.83	%
Total debt				5,182					5,197
Current maturities of long-term debt				(14		)			(723		)
Unamortized premium (discount), net				(1		)			1
Unamortized debt issuance costs				(35		)			(34		)
Total long-term debt, net				$	5,132				$	4,441

Schedule of Line of Credit Facilities [Text Block]

Millions of dollars	Total		SCANA			SCE&G			PSNC  Energy
December 31, 2018
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	500.0		—			500.0			—
Total committed long-term	1,800.0		400.0			1,200.0			200.0
LOC advances	40.0		40.0			—			—
Weighted average interest rate			3.87		%
Outstanding commercial paper (270 or fewer days)	172.9		2.0			73.2			97.7
Weighted average interest rate			3.65		%	3.82		%	3.49		%
Letters of credit supported by LOC	37.6		37.3			0.3			—
Available	$	1,549.5	$	320.7		$	1,126.5		$	102.3

December 31, 2017
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0	$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	500.0		—		500.0			—
Three-year, expiring December 2018	200.0		—		200.0			—
Total committed long-term	2,000.0		400.0		1,400.0			200.0
Outstanding commercial paper (270 or fewer days)	350.3		—		251.6			98.7
Weighted average interest rate					1.92		%	1.93		%
Letters of credit supported by LOC	3.3		3.0		0.3			—
Available	$	1,646.4	$	397.0	$	1,148.1		$	101.3

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2018

Investments, Owned, Federal Income Tax Note [Line Items]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

:

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
Current taxes (benefit):
Federal	$	(8	)	$	(414	)	$	36		$	(16	)	$	(410	)	$	50
State	5			18			13			—			(18		)	13
Total current taxes (benefit)	(3		)	(396		)	49			(16		)	(428		)	63
Deferred tax (benefit) expense, net:
Federal	(352		)	323			203			(346		)	261			167
State	(55		)	(37		)	21			(52		)	(2		)	20
Total deferred taxes (benefit)	(407		)	286			224			(398		)	259			187
Investment tax credits:
Amortization of amounts deferred-federal	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Total income tax expense (benefit)	$	(412	)	$	(112	)	$	271		$	(416	)	$	(171	)	$	248

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

:

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
U.S. statutory rate	21		%	35		%	35		%	21		%	35		%	35		%
Net income (loss)	$	(528	)	$	(119	)	$	595		$	(614	)	$	(185	)	$	513
Income tax expense (benefit)	(412		)	(112		)	271			(416		)	(171		)	248
Noncontrolling interest	—			—			—			25			13			13
Total pre-tax income (loss)	$	(940	)	$	(231	)	$	866		$	(1,005	)	$	(343	)	$	774
Income taxes (benefit) on above at statutory federal income tax rate	$	(197	)	$	(81	)	$	303		$	(211	)	$	(120	)	$	271
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)	(37		)	(7		)	27			(38		)	(8		)	26
State investment tax credits (less federal income tax effect)	(3		)	(5		)	(5		)	(3		)	(5		)	(5		)
Allowance for equity funds used during construction	(4		)	(8		)	(10		)	(2		)	(5		)	(9		)
Deductible dividends—401(k) Retirement Savings Plan	(2		)	(9		)	(10		)	—			—			—
Amortization of federal investment tax credits	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Section 45 tax credits	(9		)	(8		)	(8		)	(9		)	(8		)	(8		)
Domestic production activities deduction	—			(18		)	(23		)	—			(18		)	(23		)
Remeasurement of deferred taxes in connection with enactment of Tax Act	(188		)	30			—			(176		)	(1		)	—
Nuclear Project impairment	23			—			—			23			—			—
Nondeductible merger-related costs	5			—			—			—			—			—
Other differences, net	2			(4		)	(1		)	2			(4		)	(2		)
Total income tax expense (benefit)	$	(412	)	$	(112	)	$	271		$	(416	)	$	(171	)	$	248

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

:

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Deferred tax assets:
Net operating loss and tax credit carryforward	$	539	$	600	$	493	$	541
Toshiba settlement	274		273		274		273
Nondeductible accruals	84		88		40		42
Asset retirement obligation, including nuclear decommissioning	143		141		135		132
Regulatory liability, non-property accumulated deferred income tax	—		54		—		54
Financial instruments	10		15		—		—
Unamortized investment tax credits	7		8		7		8
Other	4		6		5		5
Total deferred tax assets	1,061		1,185		954		1,055
Deferred tax liabilities:
Property, plant and equipment	1,227		1,220		1,033		1,035
Regulatory asset, unrecovered nuclear plant costs	668		962		668		962
Deferred employee benefit plan costs	60		60		53		53
Regulatory asset, asset retirement obligation	94		91		88		85
Regulatory asset, other unrecovered plant	24		27		24		27
Demand side management costs	16		16		16		16
Prepayments	21		21		20		19
Other	63		49		41		31
Total deferred tax liabilities	2,173		2,446		1,943		2,228
Net deferred tax liabilities	$	1,112	$	1,261	$	989	$	1,173

Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]

	The Company							Consolidated SCE&G
Millions of dollars	2018		2017			2016		2018		2017			2016
Unrecognized tax benefits, January 1	$	98	$	350		$	49	$	98	$	350		$	49
Gross increases—uncertain tax positions in prior period	8		—			94		8		—			94
Gross decreases—uncertain tax positions in prior period	—		(273		)	—		—		(273		)	—
Gross increases—current period uncertain tax positions	—		21			207		—		21			207
Unrecognized tax benefits, December 31	$	106	$	98		$	350	$	106	$	98		$	350

Summary of Tax Credit Carryforwards [Table Text Block]

The federal and state tax credits and NOL carryforwards are presented below:

	December 31, 2018
Millions of dollars	The Company		Consolidated SCE&G		Expiration Year
Federal NOL Carryforwards	$	1,807	$	1,642	2037
Federal Tax Credits	83		83		2035	-	2038
State NOL Carryforwards	2,447		2,198		2037
State Tax Credits	30		30		2026	-	2033
Total Tax Credits and NOL Carryforwards	$	4,367	$	3,953

SCE&G

Investments, Owned, Federal Income Tax Note [Line Items]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

:

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
Current taxes (benefit):
Federal	$	(8	)	$	(414	)	$	36		$	(16	)	$	(410	)	$	50
State	5			18			13			—			(18		)	13
Total current taxes (benefit)	(3		)	(396		)	49			(16		)	(428		)	63
Deferred tax (benefit) expense, net:
Federal	(352		)	323			203			(346		)	261			167
State	(55		)	(37		)	21			(52		)	(2		)	20
Total deferred taxes (benefit)	(407		)	286			224			(398		)	259			187
Investment tax credits:
Amortization of amounts deferred-federal	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Total income tax expense (benefit)	$	(412	)	$	(112	)	$	271		$	(416	)	$	(171	)	$	248

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
U.S. statutory rate	21		%	35		%	35		%	21		%	35		%	35		%
Net income (loss)	$	(528	)	$	(119	)	$	595		$	(614	)	$	(185	)	$	513
Income tax expense (benefit)	(412		)	(112		)	271			(416		)	(171		)	248
Noncontrolling interest	—			—			—			25			13			13
Total pre-tax income (loss)	$	(940	)	$	(231	)	$	866		$	(1,005	)	$	(343	)	$	774
Income taxes (benefit) on above at statutory federal income tax rate	$	(197	)	$	(81	)	$	303		$	(211	)	$	(120	)	$	271
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)	(37		)	(7		)	27			(38		)	(8		)	26
State investment tax credits (less federal income tax effect)	(3		)	(5		)	(5		)	(3		)	(5		)	(5		)
Allowance for equity funds used during construction	(4		)	(8		)	(10		)	(2		)	(5		)	(9		)
Deductible dividends—401(k) Retirement Savings Plan	(2		)	(9		)	(10		)	—			—			—
Amortization of federal investment tax credits	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Section 45 tax credits	(9		)	(8		)	(8		)	(9		)	(8		)	(8		)
Domestic production activities deduction	—			(18		)	(23		)	—			(18		)	(23		)
Remeasurement of deferred taxes in connection with enactment of Tax Act	(188		)	30			—			(176		)	(1		)	—
Nuclear Project impairment	23			—			—			23			—			—
Nondeductible merger-related costs	5			—			—			—			—			—
Other differences, net	2			(4		)	(1		)	2			(4		)	(2		)
Total income tax expense (benefit)	$	(412	)	$	(112	)	$	271		$	(416	)	$	(171	)	$	248

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Deferred tax assets:
Net operating loss and tax credit carryforward	$	539	$	600	$	493	$	541
Toshiba settlement	274		273		274		273
Nondeductible accruals	84		88		40		42
Asset retirement obligation, including nuclear decommissioning	143		141		135		132
Regulatory liability, non-property accumulated deferred income tax	—		54		—		54
Financial instruments	10		15		—		—
Unamortized investment tax credits	7		8		7		8
Other	4		6		5		5
Total deferred tax assets	1,061		1,185		954		1,055
Deferred tax liabilities:
Property, plant and equipment	1,227		1,220		1,033		1,035
Regulatory asset, unrecovered nuclear plant costs	668		962		668		962
Deferred employee benefit plan costs	60		60		53		53
Regulatory asset, asset retirement obligation	94		91		88		85
Regulatory asset, other unrecovered plant	24		27		24		27
Demand side management costs	16		16		16		16
Prepayments	21		21		20		19
Other	63		49		41		31
Total deferred tax liabilities	2,173		2,446		1,943		2,228
Net deferred tax liabilities	$	1,112	$	1,261	$	989	$	1,173

Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]

	The Company							Consolidated SCE&G
Millions of dollars	2018		2017			2016		2018		2017			2016
Unrecognized tax benefits, January 1	$	98	$	350		$	49	$	98	$	350		$	49
Gross increases—uncertain tax positions in prior period	8		—			94		8		—			94
Gross decreases—uncertain tax positions in prior period	—		(273		)	—		—		(273		)	—
Gross increases—current period uncertain tax positions	—		21			207		—		21			207
Unrecognized tax benefits, December 31	$	106	$	98		$	350	$	106	$	98		$	350

Summary of Tax Credit Carryforwards [Table Text Block]

The federal and state tax credits and NOL carryforwards are presented below:

	December 31, 2018
Millions of dollars	The Company		Consolidated SCE&G		Expiration Year
Federal NOL Carryforwards	$	1,807	$	1,642	2037
Federal Tax Credits	83		83		2035	-	2038
State NOL Carryforwards	2,447		2,198		2037
State Tax Credits	30		30		2026	-	2033
Total Tax Credits and NOL Carryforwards	$	4,367	$	3,953

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2018

Derivative [Line Items]

Schedule of Nonmonetary Notional Amounts of Outstanding Derivative Positions [Table Text Block]

The Company was party to natural gas derivative contracts outstanding in the following quantities:

	Commodity and Energy Management Contracts (in bcf)
Hedge designation	Gas Distribution	Gas Marketing	Total
As of December 31, 2018
Commodity	6.4	12.9	19.3
Energy Management (a)	—	46.8	46.8
Total (a)	6.4	59.7	66.1
As of December 31, 2017
Commodity	6.4	13.4	19.8
Energy Management (a)	—	41.9	41.9
Total (a)	6.4	55.3	61.7

(a) Includes amounts related to basis swap contracts totaling 5.1 bcf in 2018 and 2.6 bcf in 2017.

Schedule of Derivative Instruments [Table Text Block]

The aggregate notional amounts of the interest rate swaps were as follows:

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	December 31, 2018		December 31, 2017		December 31, 2018		December 31, 2017
Designated as hedging instruments	$	106.8	$	111.2	$	36.4	$	36.4
Not designated as hedging instruments	35.0		735.0		35.0		735.0

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of December 31, 2018
Designated as hedging instruments
Interest rate contracts
	Other current liabilities	—		$	2	—		$	1
	Other deferred credits and other liabilities	—		19		—		7
Commodity contracts
	Prepayments	—		1		—		—
Total		—		$	22	—		$	8
Not designated as hedging instruments
Interest rate contracts
	Other deferred credits and other liabilities	—		$	3	—		$	3
Commodity contracts
	Prepayments	$	1	—		—		—
Energy management contracts
	Prepayments	11		12		—		—
	Other current assets	1		—		—		—
	Other current liabilities	—		1		—		—
	Other deferred debits and other assets	1		—		—		—
Total		$	14	$	16	—		$	3
As of December 31, 2017
Designated as hedging instruments
Interest rate contracts
	Other current liabilities	—		$	3	—		$	1
	Other deferred credits and other liabilities	—		24		—		9
Commodity contracts
	Prepayments	—		2		—		—
	Other current liabilities	—		1		—		—
Total		—		$	30	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets and current liabilities	$	54	$	1	$	54	$	1
	Other deferred credits and other liabilities	—		4		—		4
Commodity contracts
	Other current assets	1		—		—		—
Energy management contracts
	Prepayments	—		1		—		—
	Other current assets	3		—		—		—
	Other deferred debits and other assets	1		—		—		—
	Other current liabilities	—		2		—		—
Total		$	59	$	8	$	54	$	5

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

The effect of derivative instruments on the consolidated statements of operations is as follows: 

The Company and Consolidated SCE&G:	Gain (Loss) Deferred in Regulatory Accounts			Loss Reclassified from Deferred Accounts into Income (Effective Portion)
Millions of dollars	(Effective Portion)			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	1		Interest expense	$	(1	)
Year Ended December 31, 2017
Interest rate contracts	$	(2	)	Interest expense	$	(2	)
Year Ended December 31, 2016
Interest rate contracts	—			Interest expense	$	(2	)

The Company:	Gain (Loss) Recognized in OCI, net of tax			Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion)
Millions of dollars	(Effective Portion)			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	1		Interest expense	$	(9	)
Commodity contracts	(3		)	Gas purchased for resale	(7		)
Total	$	(2	)		$	(16	)
Year Ended December 31, 2017
Interest rate contracts	—			Interest expense	$	(7	)
Commodity contracts	$	(7	)	Gas purchased for resale	1
Total	$	(7	)		$	(6	)
Year Ended December 31, 2016
Interest rate contracts	$	(1	)	Interest expense	$	(7	)
Commodity contracts	5			Gas purchased for resale	(6		)
Total	$	4			$	(13	)

Derivatives Not Designated as Hedging Instruments [Table Text Block]

Derivatives Not Designated as Hedging Instruments

The Company and Consolidated SCE&G:	Gain (Loss) Deferred in			Gain (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	Regulatory Accounts			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	64		Interest Expense	$	(2	)
Interest rate contracts				Other Income	115
Year Ended December 31, 2017
Interest rate contracts	$	(32	)	Interest Expense	$	(3	)
Interest rate contracts				Impairment Loss	(173		)
Year Ended December 31, 2016
Interest rate contracts	$	(34	)	Other income	$	(2	)

Disclosure of Credit Derivatives [Table Text Block]

	The Company				Consolidated SCE&G
Millions of dollars	December 31, 2018		December 31, 2017		December 31, 2018		December 31, 2017
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	24.8	$	33.7	$	11.2	$	14.7
Fair value of collateral already posted	24.3		28.9		11.0		10.1
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	0.5	$	4.8	$	0.2	$	4.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position	—		$	53.5	—		$	53.5
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	—		$	53.5	—		$	53.5

Offsetting Assets [Table Text Block]

Information related to the offsetting derivative assets follows:

Derivative Assets	The Company										Consolidated SCE&G
Millions of dollars	Interest Rate Contracts		Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2018
Gross Amounts of Recognized Assets	—		$	1	$	13		$	14		—
Gross Amounts Offset in Statement of Financial Position	—		—		(11		)	(11		)	—
Net Amounts Presented in Statement of Financial Position	—		1		2			3			—
Gross Amounts Not Offset - Financial Instruments	—		—		—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—			—			—
Net Amount	—		$	1	$	2		$	3		—
Balance sheet location
Prepayments								$	12		—
Other current assets								1			—
Other deferred debits and other assets								1			—
Total								$	14		—
As of December 31, 2017
Gross Amounts of Recognized Assets	$	54	$	1	$	4		$	59		$	54
Gross Amounts Offset in Statement of Financial Position	—		—		—			—			—
Net Amounts Presented in Statement of Financial Position	54		1		4			59			54
Gross Amounts Not Offset - Financial Instruments	—		—		—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—			—			—
Net Amount	$	54	$	1	$	4		$	59		$	54
Balance sheet location
Other current assets								$	58		$	54
Other deferred debits and other assets								1			—
Total								$	59		$	54

Offsetting Liabilities [Table Text Block]

Information related to the offsetting of derivative liabilities follows:

Derivative Liabilities	The Company											Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2018
Gross Amounts of Recognized Liabilities	$	24		$	1	$	13		$	38		$	11
Gross Amounts Offset in Statement of Financial Position	—			—		(11		)	(11		)	—
Net Amounts Presented in Statement of Financial Position	24			1		2			27			11
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(24		)	—		—			(24		)	(11		)
Net Amount	—			$	1	$	2		$	3		—
Balance sheet location
Prepayments									$	13		—
Other current liabilities									3			$	1
Other deferred credits and other liabilities									22			10
Total									$	38		$	11

Derivative Liabilities	The Company											Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2017
Gross Amounts of Recognized Liabilities	$	32		$	3	$	3		$	38		$	15
Gross Amounts Offset in Statement of Financial Position	—			—		(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	32			3		2			37			15
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(28		)	—		(1		)	(29		)	—
Net Amount	$	4		3		$	1		$	8		$	15
Balance sheet location
Other current assets									$	2		—
Other current liabilities									7			$	2
Other deferred credits and other liabilities									28			13
Total									$	37		$	15

SCE&G

Derivative [Line Items]

Schedule of Derivative Instruments [Table Text Block]

The aggregate notional amounts of the interest rate swaps were as follows:

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	December 31, 2018		December 31, 2017		December 31, 2018		December 31, 2017
Designated as hedging instruments	$	106.8	$	111.2	$	36.4	$	36.4
Not designated as hedging instruments	35.0		735.0		35.0		735.0

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of December 31, 2018
Designated as hedging instruments
Interest rate contracts
	Other current liabilities	—		$	2	—		$	1
	Other deferred credits and other liabilities	—		19		—		7
Commodity contracts
	Prepayments	—		1		—		—
Total		—		$	22	—		$	8
Not designated as hedging instruments
Interest rate contracts
	Other deferred credits and other liabilities	—		$	3	—		$	3
Commodity contracts
	Prepayments	$	1	—		—		—
Energy management contracts
	Prepayments	11		12		—		—
	Other current assets	1		—		—		—
	Other current liabilities	—		1		—		—
	Other deferred debits and other assets	1		—		—		—
Total		$	14	$	16	—		$	3
As of December 31, 2017
Designated as hedging instruments
Interest rate contracts
	Other current liabilities	—		$	3	—		$	1
	Other deferred credits and other liabilities	—		24		—		9
Commodity contracts
	Prepayments	—		2		—		—
	Other current liabilities	—		1		—		—
Total		—		$	30	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets and current liabilities	$	54	$	1	$	54	$	1
	Other deferred credits and other liabilities	—		4		—		4
Commodity contracts
	Other current assets	1		—		—		—
Energy management contracts
	Prepayments	—		1		—		—
	Other current assets	3		—		—		—
	Other deferred debits and other assets	1		—		—		—
	Other current liabilities	—		2		—		—
Total		$	59	$	8	$	54	$	5

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

The effect of derivative instruments on the consolidated statements of operations is as follows: 

The Company and Consolidated SCE&G:	Gain (Loss) Deferred in Regulatory Accounts			Loss Reclassified from Deferred Accounts into Income (Effective Portion)
Millions of dollars	(Effective Portion)			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	1		Interest expense	$	(1	)
Year Ended December 31, 2017
Interest rate contracts	$	(2	)	Interest expense	$	(2	)
Year Ended December 31, 2016
Interest rate contracts	—			Interest expense	$	(2	)

Derivatives Not Designated as Hedging Instruments [Table Text Block]

Derivatives Not Designated as Hedging Instruments

The Company and Consolidated SCE&G:	Gain (Loss) Deferred in			Gain (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	Regulatory Accounts			Location	Amount
Year Ended December 31, 2018
Interest rate contracts	$	64		Interest Expense	$	(2	)
Interest rate contracts				Other Income	115
Year Ended December 31, 2017
Interest rate contracts	$	(32	)	Interest Expense	$	(3	)
Interest rate contracts				Impairment Loss	(173		)
Year Ended December 31, 2016
Interest rate contracts	$	(34	)	Other income	$	(2	)

Disclosure of Credit Derivatives [Table Text Block]

	The Company				Consolidated SCE&G
Millions of dollars	December 31, 2018		December 31, 2017		December 31, 2018		December 31, 2017
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	24.8	$	33.7	$	11.2	$	14.7
Fair value of collateral already posted	24.3		28.9		11.0		10.1
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	0.5	$	4.8	$	0.2	$	4.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position	—		$	53.5	—		$	53.5
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	—		$	53.5	—		$	53.5

Offsetting Assets [Table Text Block]

Information related to the offsetting derivative assets follows:

Derivative Assets	The Company										Consolidated SCE&G
Millions of dollars	Interest Rate Contracts		Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2018
Gross Amounts of Recognized Assets	—		$	1	$	13		$	14		—
Gross Amounts Offset in Statement of Financial Position	—		—		(11		)	(11		)	—
Net Amounts Presented in Statement of Financial Position	—		1		2			3			—
Gross Amounts Not Offset - Financial Instruments	—		—		—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—			—			—
Net Amount	—		$	1	$	2		$	3		—
Balance sheet location
Prepayments								$	12		—
Other current assets								1			—
Other deferred debits and other assets								1			—
Total								$	14		—
As of December 31, 2017
Gross Amounts of Recognized Assets	$	54	$	1	$	4		$	59		$	54
Gross Amounts Offset in Statement of Financial Position	—		—		—			—			—
Net Amounts Presented in Statement of Financial Position	54		1		4			59			54
Gross Amounts Not Offset - Financial Instruments	—		—		—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—			—			—
Net Amount	$	54	$	1	$	4		$	59		$	54
Balance sheet location
Other current assets								$	58		$	54
Other deferred debits and other assets								1			—
Total								$	59		$	54

Offsetting Liabilities [Table Text Block]

Information related to the offsetting of derivative liabilities follows:

Derivative Liabilities	The Company											Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2018
Gross Amounts of Recognized Liabilities	$	24		$	1	$	13		$	38		$	11
Gross Amounts Offset in Statement of Financial Position	—			—		(11		)	(11		)	—
Net Amounts Presented in Statement of Financial Position	24			1		2			27			11
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(24		)	—		—			(24		)	(11		)
Net Amount	—			$	1	$	2		$	3		—
Balance sheet location
Prepayments									$	13		—
Other current liabilities									3			$	1
Other deferred credits and other liabilities									22			10
Total									$	38		$	11

Derivative Liabilities	The Company											Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of December 31, 2017
Gross Amounts of Recognized Liabilities	$	32		$	3	$	3		$	38		$	15
Gross Amounts Offset in Statement of Financial Position	—			—		(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	32			3		2			37			15
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(28		)	—		(1		)	(29		)	—
Net Amount	$	4		3		$	1		$	8		$	15
Balance sheet location
Other current assets									$	2		—
Other current liabilities									7			$	2
Other deferred credits and other liabilities									28			13
Total									$	37		$	15

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair Value, Measurement Inputs, Disclosure [Table Text Block]

	As of December 31, 2018							As of December 31, 2017
	The Company				Consolidated SCE&G			The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 1	Level 2		Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	—		—		—	—		$	119	—		$	100	—
Held to maturity securities	—		$	6	—	—		—		$	6	—		—
Interest rate contracts	—		—		—	—		—		54		—		$	54
Commodity contracts	$	1	—		—	—		1		—		—		—
Energy management contracts	11		2		—	—		—		4		—		—
Liabilities:
Interest rate contracts	—		24		—	$	11	—		32		—		15
Commodity contracts	1		—		—	—		2		1		—		—
Energy management contracts	12		3		—	—		1		4		—		—

Fair Value, by Balance Sheet Grouping [Table Text Block]

	As of December 31, 2018				As of December 31, 2017
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,753.9	$	7,180.8	$	6,632.9	$	7,399.7
Consolidated SCE&G	5,145.6		5,469.7		5,163.3		5,790.3

SCE&G

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair Value, Measurement Inputs, Disclosure [Table Text Block]

	As of December 31, 2018							As of December 31, 2017
	The Company				Consolidated SCE&G			The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 1	Level 2		Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	—		—		—	—		$	119	—		$	100	—
Held to maturity securities	—		$	6	—	—		—		$	6	—		—
Interest rate contracts	—		—		—	—		—		54		—		$	54
Commodity contracts	$	1	—		—	—		1		—		—		—
Energy management contracts	11		2		—	—		—		4		—		—
Liabilities:
Interest rate contracts	—		24		—	$	11	—		32		—		15
Commodity contracts	1		—		—	—		2		1		—		—
Energy management contracts	12		3		—	—		1		4		—		—

Fair Value, by Balance Sheet Grouping [Table Text Block]

	As of December 31, 2018				As of December 31, 2017
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,753.9	$	7,180.8	$	6,632.9	$	7,399.7
Consolidated SCE&G	5,145.6		5,469.7		5,163.3		5,790.3

XML

EMPLOYEE BENEFIT PLANS (Tables)

12 Months Ended

Dec. 31, 2018

Defined Benefit Plan Disclosure [Line Items]

Schedule of Changes in Projected Benefit Obligations [Table Text Block]

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.

	The Company												Consolidated SCE&G
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017			2018			2017			2018			2017
Benefit obligation, January 1	$	933.2		$	904.3		$	289.2		$	274.7		$	793.0		$	768.4		$	216.6		$	207.2
Service cost	21.0			21.7			4.6			4.5			17.1			18.1			3.6			3.7
Interest cost	34.1			37.4			10.1			11.5			29.0			31.9			8.0			9.5
Plan participants’ contributions	—			—			1.4			1.3			—			—			1.1			1.1
Actuarial (gain) loss	(53.1		)	42.2			(38.4		)	9.7			(45.5		)	36.6			(30.7		)	6.8
Benefits paid	(71.7		)	(72.4		)	(13.2		)	(12.5		)	(61.3		)	(62.0		)	(10.4		)	(10.3		)
Amounts funded to parent	n/a			n/a			n/a			n/a			—			—			(0.8		)	(1.4		)
Benefit obligation, December 31	$	863.5		$	933.2		$	253.7		$	289.2		$	732.3		$	793.0		$	187.4		$	216.6

Schedule of Assumptions Used to Determine Benefit Obligations [Table Text Block]

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

	Pension Benefits				Other Postretirement Benefits
	2018		2017		2018		2017
Annual discount rate used to determine benefit obligation	4.35	%	3.71	%	4.38	%	3.74	%
Assumed annual rate of future salary increases for projected benefit obligation	3.00	%	3.00	%	3.00	%	3.00	%

Schedule of Net Funded Status [Table Text Block]

	The Company												Consolidated SCE&G
Millions of Dollars	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
December 31,	2018			2017			2018			2017			2018			2017			2018			2017
Fair value of plan assets	$	727.3		$	849.6		—			—			$	676.7		$	781.3		—			—
Benefit obligation	863.5			933.2			$	253.7		$	289.2		732.3			793.0			$	187.4		$	216.6
Funded status	$	(136.2	)	$	(83.6	)	$	(253.7	)	$	(289.2	)	$	(55.6	)	$	(11.7	)	$	(187.4	)	$	(216.6	)

Schedule of Amounts Recognized in Balance Sheet [Table Text Block]

Amounts recognized on the consolidated balance sheets were as follows:

	The Company												Consolidated SCE&G
Millions of Dollars	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
December 31,	2018			2017			2018			2017			2018			2017			2018			2017
Current liability	—			—			$	(13.3	)	$	(13.5	)	—			—			$	(10.5	)	$	(10.8	)
Noncurrent liability	$	(136.2	)	$	(83.6	)	(240.4		)	(275.7		)	$	(55.6	)	$	(11.7	)	(176.9		)	(205.8		)

Schedule of Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income (Loss) [Table Text Block]

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

The Company	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017			2016
Current year actuarial (gain) loss	$	4.5		$	(1.0	)	$	0.6		$	(2.4	)	$	1.1		$	0.8
Amortization of actuarial losses	(0.5		)	(0.6		)	(0.6		)	—			(0.1		)	—
Amortization of prior service cost	—			—			(0.1		)	—			—			—
Total recognized in OCI	$	4.0		$	(1.6	)	$	(0.1	)	$	(2.4	)	$	1.0		$	0.8

Schedule of defined benefit plan, amounts recognized in regulatory assets [Table Text Block]

Amounts recognized in regulatory assets were as follows:

	The Company								Consolidated SCE&G
Millions of Dollars	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
December 31,	2018		2017		2018		2017		2018		2017		2018		2017
Net actuarial loss	$	230.4	$	194.8	$	10.9	$	43.3	$	202.4	$	171.4	$	9.0	$	35.9
Prior service cost	0.7		1.2		—		—		0.6		1.0		—		—
Total	$	231.1	$	196.0	$	10.9	$	43.3	$	203.0	$	172.4	$	9.0	$	35.9

Schedule of Changes in Fair Value of Plan Assets [Table Text Block]

Pension Benefits	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Fair value of plan assets, January 1	$	849.6		$	793.6		$	781.3		$	732.9
Actual return (loss) on plan assets	(50.6		)	128.4			(43.3		)	110.4
Benefits paid	(71.7		)	(72.4		)	(61.3		)	(62.0		)
Fair value of plan assets, December 31	$	727.3		$	849.6		$	676.7		$	781.3

Schedule of Allocation of Plan Assets [Table Text Block]

The pension plan asset allocation at December 31, 2018 and 2017 and the target allocation for 2019 are as follows: 

	Percentage of Plan Assets
	Target Allocation		December 31,
Asset Category	2019		2018		2017
Equity Securities	58	%	55	%	58	%
Fixed Income	33	%	34	%	31	%
Hedge Funds	9	%	11	%	11	%

Schedule of Fair Value of Plan, Assets by Measurement Levels [Table Text Block]

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Investments with fair value measure at Level 2:
Mutual funds	$	107	$	120	$	99	$	110
Short-term investment vehicles	20		17		19		16
US Treasury securities	7		15		7		14
Corporate debt instruments	92		91		86		84
Government and other debt instruments	18		17		16		15
Total assets in the fair value hierarchy	244		260		227		239
Investments at net asset value:
Common collective trust	400		498		373		458
Joint venture interests	83		92		77		84
Total investments at fair value	$	727	$	850	$	677	$	781

Schedule of Expected Benefit Payments [Table Text Block]

	The Company				Consolidated SCE&G
Millions of dollars	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
2019	$	71.5	$	13.6	$	71.5	$	10.8
2020	62.4		14.3		62.4		11.4
2021	65.6		14.9		65.6		11.8
2022	69.6		15.4		69.6		12.2
2023	66.6		15.8		66.6		12.6
2024-2028	284.9		82.3		284.9		65.4

Schedule of Net Benefit Costs [Table Text Block]

The Company	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018		2017		2016
Service cost	$	21.0		$	21.7		$	20.7		$	4.6	$	4.5	$	4.4
Interest cost	34.1			37.4			39.4			10.1		11.5		12.1
Expected return on assets	(56.7		)	(54.7		)	(55.9		)	n/a		n/a		n/a
Prior service cost amortization	0.5			1.6			3.9			—		—		0.3
Amortization of actuarial losses	12.8			16.3			14.8			0.7		1.0		0.5
Net periodic benefit cost	$	11.7		$	22.3		$	22.9		$	15.4	$	17.0	$	17.3

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]

Amounts recognized in accumulated other comprehensive loss were as follows:

	The Company								Consolidated SCE&G
Millions of Dollars	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
December 31,	2018		2017		2018		2017		2018		2017		2018		2017
Net actuarial loss	$	12.8	$	8.8	$	1.1	$	3.5	$	3.4	$	2.1	$	0.5	$	1.5
Prior service cost	0.1		0.1		—		—		—		—		—		—
Total	$	12.9	$	8.9	$	1.1	$	3.5	$	3.4	$	2.1	$	0.5	$	1.5

Schedule of defined benefit plan, Other changes in plan assets recognized in regulatory assets [Table Text Block]

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

The Company	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017			2016
Current year actuarial (gain) loss	$	46.7		$	(27.1	)	$	29.4		$	(31.8	)	$	9.4		$	11.1
Amortization of actuarial losses	(11.1		)	(14.1		)	(12.7		)	(0.6		)	(0.8		)	(0.4		)
Amortization of prior service cost	(0.5		)	(1.4		)	(3.4		)	—			—			(0.3		)
Total recognized in regulatory assets	$	35.1		$	(42.6	)	$	13.3		$	(32.4	)	$	8.6		$	10.4

Schedule of Assumptions Used in Determining Net Periodic Benefit Cost [Table Text Block]

	Pension Benefits						Other Postretirement Benefits
	2018		2017		2016		2018		2017		2016
Discount rate	3.71	%	4.22	%	4.68	%	3.74	%	4.30	%	4.78	%
Expected return on plan assets	7.00	%	7.25	%	7.50	%	n/a		n/a		n/a
Rate of compensation increase	3.00	%	3.00	%	3.00	%	3.00	%	3.00	%	3.00	%
Health care cost trend rate	n/a		n/a		n/a		7.00	%	6.60	%	7.00	%
Ultimate health care cost trend rate	n/a		n/a		n/a		5.00	%	5.00	%	5.00	%
Year achieved	n/a		n/a		n/a		2023		2021		2021

Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]

The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2019 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant:

Millions of Dollars	Pension Benefits		Other Postretirement Benefits
Actuarial loss	$	0.8	—

Schedule of amounts in regulatory assets to be recognized over the next fiscal year [Table Text Block]

The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2019 are as follows:

	The Company			Consolidated SCE&G
Millions of Dollars	Pension Benefits		Other Postretirement Benefits	Pension Benefits		Other Postretirement Benefits
Actuarial loss	$	14.7	—	$	12.9	—
Prior service cost	0.3		—	0.3		—
Total	$	15.0	—	$	13.2	—

SCE&G

Defined Benefit Plan Disclosure [Line Items]

Schedule of Changes in Projected Benefit Obligations [Table Text Block]

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.

	The Company												Consolidated SCE&G
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017			2018			2017			2018			2017
Benefit obligation, January 1	$	933.2		$	904.3		$	289.2		$	274.7		$	793.0		$	768.4		$	216.6		$	207.2
Service cost	21.0			21.7			4.6			4.5			17.1			18.1			3.6			3.7
Interest cost	34.1			37.4			10.1			11.5			29.0			31.9			8.0			9.5
Plan participants’ contributions	—			—			1.4			1.3			—			—			1.1			1.1
Actuarial (gain) loss	(53.1		)	42.2			(38.4		)	9.7			(45.5		)	36.6			(30.7		)	6.8
Benefits paid	(71.7		)	(72.4		)	(13.2		)	(12.5		)	(61.3		)	(62.0		)	(10.4		)	(10.3		)
Amounts funded to parent	n/a			n/a			n/a			n/a			—			—			(0.8		)	(1.4		)
Benefit obligation, December 31	$	863.5		$	933.2		$	253.7		$	289.2		$	732.3		$	793.0		$	187.4		$	216.6

Schedule of Assumptions Used to Determine Benefit Obligations [Table Text Block]

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

	Pension Benefits				Other Postretirement Benefits
	2018		2017		2018		2017
Annual discount rate used to determine benefit obligation	4.35	%	3.71	%	4.38	%	3.74	%
Assumed annual rate of future salary increases for projected benefit obligation	3.00	%	3.00	%	3.00	%	3.00	%

Schedule of Net Funded Status [Table Text Block]

	The Company												Consolidated SCE&G
Millions of Dollars	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
December 31,	2018			2017			2018			2017			2018			2017			2018			2017
Fair value of plan assets	$	727.3		$	849.6		—			—			$	676.7		$	781.3		—			—
Benefit obligation	863.5			933.2			$	253.7		$	289.2		732.3			793.0			$	187.4		$	216.6
Funded status	$	(136.2	)	$	(83.6	)	$	(253.7	)	$	(289.2	)	$	(55.6	)	$	(11.7	)	$	(187.4	)	$	(216.6	)

Schedule of Amounts Recognized in Balance Sheet [Table Text Block]

Amounts recognized in accumulated other comprehensive loss were as follows:

	The Company								Consolidated SCE&G
Millions of Dollars	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
December 31,	2018		2017		2018		2017		2018		2017		2018		2017
Net actuarial loss	$	12.8	$	8.8	$	1.1	$	3.5	$	3.4	$	2.1	$	0.5	$	1.5
Prior service cost	0.1		0.1		—		—		—		—		—		—
Total	$	12.9	$	8.9	$	1.1	$	3.5	$	3.4	$	2.1	$	0.5	$	1.5

Schedule of Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income (Loss) [Table Text Block]

Consolidated SCE&G	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017		2016
Current year actuarial loss	$	1.4		$	0.3		—			$	(1.0	)	$	0.5	$	0.3
Amortization of actuarial losses	(0.1		)	(0.1		)	$	(0.1	)	—			—		—
Total recognized in OCI	$	1.3		$	0.2		$	(0.1	)	$	(1.0	)	$	0.5	$	0.3

Schedule of defined benefit plan, amounts recognized in regulatory assets [Table Text Block]

Amounts recognized in regulatory assets were as follows:

	The Company								Consolidated SCE&G
Millions of Dollars	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
December 31,	2018		2017		2018		2017		2018		2017		2018		2017
Net actuarial loss	$	230.4	$	194.8	$	10.9	$	43.3	$	202.4	$	171.4	$	9.0	$	35.9
Prior service cost	0.7		1.2		—		—		0.6		1.0		—		—
Total	$	231.1	$	196.0	$	10.9	$	43.3	$	203.0	$	172.4	$	9.0	$	35.9

Schedule of Changes in Fair Value of Plan Assets [Table Text Block]

Pension Benefits	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Fair value of plan assets, January 1	$	849.6		$	793.6		$	781.3		$	732.9
Actual return (loss) on plan assets	(50.6		)	128.4			(43.3		)	110.4
Benefits paid	(71.7		)	(72.4		)	(61.3		)	(62.0		)
Fair value of plan assets, December 31	$	727.3		$	849.6		$	676.7		$	781.3

Schedule of Allocation of Plan Assets [Table Text Block]

The pension plan asset allocation at December 31, 2018 and 2017 and the target allocation for 2019 are as follows: 

	Percentage of Plan Assets
	Target Allocation		December 31,
Asset Category	2019		2018		2017
Equity Securities	58	%	55	%	58	%
Fixed Income	33	%	34	%	31	%
Hedge Funds	9	%	11	%	11	%

Schedule of Fair Value of Plan, Assets by Measurement Levels [Table Text Block]

	The Company				Consolidated SCE&G
Millions of dollars	2018		2017		2018		2017
Investments with fair value measure at Level 2:
Mutual funds	$	107	$	120	$	99	$	110
Short-term investment vehicles	20		17		19		16
US Treasury securities	7		15		7		14
Corporate debt instruments	92		91		86		84
Government and other debt instruments	18		17		16		15
Total assets in the fair value hierarchy	244		260		227		239
Investments at net asset value:
Common collective trust	400		498		373		458
Joint venture interests	83		92		77		84
Total investments at fair value	$	727	$	850	$	677	$	781

Schedule of Expected Benefit Payments [Table Text Block]

	The Company				Consolidated SCE&G
Millions of dollars	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
2019	$	71.5	$	13.6	$	71.5	$	10.8
2020	62.4		14.3		62.4		11.4
2021	65.6		14.9		65.6		11.8
2022	69.6		15.4		69.6		12.2
2023	66.6		15.8		66.6		12.6
2024-2028	284.9		82.3		284.9		65.4

Schedule of Net Benefit Costs [Table Text Block]

Consolidated SCE&G	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018		2017		2016
Service cost	$	17.1		$	18.1		$	16.9		$	3.6	$	3.7	$	3.6
Interest cost	29.0			31.9			33.4			8.0		9.5		9.9
Expected return on assets	(48.1		)	(46.7		)	(47.4		)	n/a		n/a		n/a
Prior service cost amortization	0.4			1.4			3.4			—		—		0.3
Amortization of actuarial losses	10.9			13.9			12.5			0.6		0.8		0.4
Net periodic benefit cost	$	9.3		$	18.6		$	18.8		$	12.2	$	14.0	$	14.2

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]

Amounts recognized in accumulated other comprehensive loss were as follows:

	The Company								Consolidated SCE&G
Millions of Dollars	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
December 31,	2018		2017		2018		2017		2018		2017		2018		2017
Net actuarial loss	$	12.8	$	8.8	$	1.1	$	3.5	$	3.4	$	2.1	$	0.5	$	1.5
Prior service cost	0.1		0.1		—		—		—		—		—		—
Total	$	12.9	$	8.9	$	1.1	$	3.5	$	3.4	$	2.1	$	0.5	$	1.5

Schedule of defined benefit plan, Other changes in plan assets recognized in regulatory assets [Table Text Block]

Consolidated SCE&G	Pension Benefits									Other Postretirement Benefits
Millions of dollars	2018			2017			2016			2018			2017			2016
Current year actuarial (gain) loss	$	40.7		$	(24.8	)	$	26.3		$	(26.4	)	$	7.3		$	9.2
Amortization of actuarial losses	(9.7		)	(12.5		)	(11.2		)	(0.5		)	(0.7		)	(0.3		)
Amortization of prior service cost	(0.4		)	(1.3		)	(3.0		)	—			—			(0.2		)
Total recognized in regulatory assets	$	30.6		$	(38.6	)	$	12.1		$	(26.9	)	$	6.6		$	8.7

Schedule of Assumptions Used in Determining Net Periodic Benefit Cost [Table Text Block]

	Pension Benefits						Other Postretirement Benefits
	2018		2017		2016		2018		2017		2016
Discount rate	3.71	%	4.22	%	4.68	%	3.74	%	4.30	%	4.78	%
Expected return on plan assets	7.00	%	7.25	%	7.50	%	n/a		n/a		n/a
Rate of compensation increase	3.00	%	3.00	%	3.00	%	3.00	%	3.00	%	3.00	%
Health care cost trend rate	n/a		n/a		n/a		7.00	%	6.60	%	7.00	%
Ultimate health care cost trend rate	n/a		n/a		n/a		5.00	%	5.00	%	5.00	%
Year achieved	n/a		n/a		n/a		2023		2021		2021

Schedule of amounts in regulatory assets to be recognized over the next fiscal year [Table Text Block]

The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2019 are as follows:

	The Company			Consolidated SCE&G
Millions of Dollars	Pension Benefits		Other Postretirement Benefits	Pension Benefits		Other Postretirement Benefits
Actuarial loss	$	14.7	—	$	12.9	—
Prior service cost	0.3		—	0.3		—
Total	$	15.0	—	$	13.2	—

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COMMITMENTS AND CONTINGENCIES ARO (Tables)

12 Months Ended

Dec. 31, 2018

Change in Asset Retirement Obligations [Line Items]

Change in Asset Retirement Obligations [Table Text Block]

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

	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Beginning balance	$	568		$	558		$	529		$	522
Liabilities incurred	—			—			—			—
Liabilities settled	(15		)	(10		)	(15		)	(9		)
Accretion expense	25			25			23			23
Revisions in estimated cash flows	(1		)	(5		)	4			(7		)
Ending balance	$	577		$	568		$	541		$	529

SCE&G

Change in Asset Retirement Obligations [Line Items]

Change in Asset Retirement Obligations [Table Text Block]

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

	The Company						Consolidated SCE&G
Millions of dollars	2018			2017			2018			2017
Beginning balance	$	568		$	558		$	529		$	522
Liabilities incurred	—			—			—			—
Liabilities settled	(15		)	(10		)	(15		)	(9		)
Accretion expense	25			25			23			23
Revisions in estimated cash flows	(1		)	(5		)	4			(7		)
Ending balance	$	577		$	568		$	541		$	529

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COMMITMENTS AND CONTINGENCIES Operating Leases Tables (Tables) - USD ($)

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Operating Leased Assets [Line Items]

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

	Rent Expense						Future Minimum Rental Payments
Millions of dollars	2016		2017		2018		2019		2020		2021		2022		2023		Thereafter
The Company	$	10.2	$	10	$	9.7	$	10	$	8	$	7	$	6	$	4	$	30
Consolidated SCE&G	12.2		11.4		10.2		3		2		1		1		—		16

Operating Leases, Future Minimum Payments Due, Next Twelve Months

$ 10,000,000

Operating Leases, Future Minimum Payments, Due in Two Years

8,000,000

Operating Leases, Future Minimum Payments, Due in Three Years

7,000,000

Operating Leases, Future Minimum Payments, Due in Four Years

6,000,000

Operating Leases, Future Minimum Payments, Due in Five Years

4,000,000

Operating Leases, Future Minimum Payments, Due Thereafter

$ 30,000,000

Long-term Purchase Commitment [Table Text Block]

	Future Payments
Millions of dollars	2019		2020		2021		2022		2023		Thereafter
The Company and Consolidated SCE&G	$	40	$	39	$	39	$	38	$	38	$	396

Contractual Obligation, Due in Next Fiscal Year

$ 23.7

$ 3.6

Contractual Obligation, Due in Second Year

39,000,000

Contractual Obligation, Due in Third Year

39,000,000

Contractual Obligation, Due in Fourth Year

38,000,000

Contractual Obligation, Due in Fifth Year

38,000,000

Contractual Obligation, Due after Fifth Year

$ 396,000,000

Operating Lease, Payments

10

SCE&G

Operating Leased Assets [Line Items]

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

	Rent Expense						Future Minimum Rental Payments
Millions of dollars	2016		2017		2018		2019		2020		2021		2022		2023		Thereafter
The Company	$	10.2	$	10	$	9.7	$	10	$	8	$	7	$	6	$	4	$	30
Consolidated SCE&G	12.2		11.4		10.2		3		2		1		1		—		16

Operating Leases, Future Minimum Payments Due, Next Twelve Months

$ 3,000,000

Operating Leases, Future Minimum Payments, Due in Two Years

2,000,000

Operating Leases, Future Minimum Payments, Due in Three Years

1,000,000

Operating Leases, Future Minimum Payments, Due in Four Years

1,000,000

Operating Leases, Future Minimum Payments, Due in Five Years

0

Operating Leases, Future Minimum Payments, Due Thereafter

$ 16,000,000

Long-term Purchase Commitment [Table Text Block]

	Future Payments
Millions of dollars	2019		2020		2021		2022		2023		Thereafter
The Company and Consolidated SCE&G	$	40	$	39	$	39	$	38	$	38	$	396

Operating Lease, Payments

$ 10

$ 11

$ 12

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COMMITMENTS AND CONTINGENCIES Nuclear (Tables)

12 Months Ended

Dec. 31, 2018

Long-term Purchase Commitment [Table Text Block]

	Future Payments
Millions of dollars	2019		2020		2021		2022		2023		Thereafter
The Company and Consolidated SCE&G	$	40	$	39	$	39	$	38	$	38	$	396

SCE&G

Long-term Purchase Commitment [Table Text Block]

	Future Payments
Millions of dollars	2019		2020		2021		2022		2023		Thereafter
The Company and Consolidated SCE&G	$	40	$	39	$	39	$	38	$	38	$	396

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SEGMENT OF BUSINESS INFORMATION (Tables)

12 Months Ended

Dec. 31, 2018

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Disclosure of Reportable Segments 

The Company:

Millions of dollars	Electric Operations			Gas Distribution		Gas Marketing		All Other			Adjustments/ Eliminations			Consolidated Total
2018
External Revenue	$	2,322		$	934	$	796	—			—			$	4,052
Intersegment Revenue	5			1		139		$	470		$	(615	)	—
Operating Income (Loss)	(894		)	173		n/a		—			(8		)	(729		)
Interest Expense	18			37		1		—			328			384
Depreciation and Amortization	307			94		2		15			(15		)	403
Income Tax Expense (Benefit)	9			26		15		(25		)	(437		)	(412		)
Net Income (Loss)	n/a			n/a		43		(90		)	(481		)	(528		)
Segment Assets	7,988			3,517		305		1,212			4,632			17,654
Expenditures for Assets	973			345		2		8			(438		)	890
Deferred Tax Assets	4			17		2		—			(23		)	—
2017
External Revenue	$	2,659		$	874	$	874	—			—			$	4,407
Intersegment Revenue	5			2		127		$	389		$	(523	)	—
Operating Income (Loss)	(154		)	187		n/a		—			52			85
Interest Expense	19			28		1		—			315			363
Depreciation and Amortization	295			85		2		16			(16		)	382
Income Tax Expense (Benefit)	8			41		25		(7		)	(179		)	(112		)
Net Income (Loss)	n/a			n/a		27		(46		)	(100		)	(119		)
Segment Assets	11,979			3,259		230		1,042			2,229			18,739
Expenditures for Assets	216			417		2		7			583			1,225
Deferred Tax Assets	6			25		9		—			(40		)	—
2016
External Revenue	$	2,614		$	788	$	825	—			—			$	4,227
Intersegment Revenue	5			2		111		$	414		$	(532	)	—
Operating Income	969			149		n/a		—			49			1,167
Interest Expense	17			25		1		—			299			342
Depreciation and Amortization	287			82		2		16			(16		)	371
Income Tax Expense	8			32		19		—			212			271
Net Income (Loss)	n/a			n/a		30		(18		)	583			595
Segment Assets	11,929			2,892		230		1,124			2,532			18,707
Expenditures for Assets	1,275			276		2		11			15			1,579

Deferred Tax Assets 9 32 11 — (52 ) —

SCE&G

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Consolidated SCE&G:

Millions of dollars	Electric Operations			Gas Distribution		Adjustments/ Eliminations			Consolidated Total
2018
External Revenue	$	2,327		$	435	—			$	2,762
Operating Income (Loss)	(894		)	63		—			(831		)
Interest Expense	18			—		$	285		303
Depreciation and Amortization	307			32		(12		)	327
Segment Assets	7,988			934		6,041			14,963
Expenditures for Assets	973			90		(430		)	633
Deferred Tax Assets	4			n/a		(4		)	—
2017
External Revenue	$	2,664		$	406	—			$	3,070
Operating Income (Loss)	(154		)	71		—			(83		)
Interest Expense	19			—		$	269		288
Depreciation and Amortization	295			30		(13		)	312
Segment Assets	11,979			869		3,098			15,946
Expenditures for Assets	216			65		647			928
Deferred Tax Assets	6			n/a		(6		)	—
2016
External Revenue	$	2,619		$	367	—			$	2,986
Operating Income	969			56		—			1,025
Interest Expense	17			—		$	253		270
Depreciation and Amortization	287			28		(13		)	302
Segment Assets	11,929			825		3,337			16,091
Expenditures for Assets	1,275			78		46			1,399
Deferred Tax Assets	9			n/a		(9		)	—

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UTILITY PLANT AND NONUTILITY PROPERTY Utility and Nonutiltiy Property (Tables)

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment [Table Text Block]

Millions of dollars	The Company		Consolidated SCE&G
Gross Utility Plant:
Generation	$	5,751	$	5,751
Transmission	2,417		1,758
Distribution	6,032		4,456
Storage	99		74
General and other	631		535
Intangible	241		229
Construction work in progress	527		350
Nuclear Fuel	611		611
Total Gross Utility Plant	$	16,309	$	13,764
Gross Nonutility Property	$	410	$	73

Schedule of Jointly Owned Utility Plants [Table Text Block]

As of December 31,	2018			2017
	Unit 1			Unit 1
Percent owned	66.7%			66.7%
Plant in service	$	1.5	billion	$	1.5	billion
Accumulated depreciation	$	643.9	million	$	637.6	million
Construction work in progress	$	127.5	million	$	110.1	million

SCE&G

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment [Table Text Block]

Millions of dollars	The Company		Consolidated SCE&G
Gross Utility Plant:
Generation	$	5,751	$	5,751
Transmission	2,417		1,758
Distribution	6,032		4,456
Storage	99		74
General and other	631		535
Intangible	241		229
Construction work in progress	527		350
Nuclear Fuel	611		611
Total Gross Utility Plant	$	16,309	$	13,764
Gross Nonutility Property	$	410	$	73

Schedule of Jointly Owned Utility Plants [Table Text Block]

As of December 31,	2018			2017
	Unit 1			Unit 1
Percent owned	66.7%			66.7%
Plant in service	$	1.5	billion	$	1.5	billion
Accumulated depreciation	$	643.9	million	$	637.6	million
Construction work in progress	$	127.5	million	$	110.1	million

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AFFILIATED TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2018

Related Party Transaction [Line Items]

Schedule of Related Party Transactions [Table Text Block]

Millions of Dollars	2018		2017		2016
Purchases from Canadys Refined Coal, LLC	$	149.9	$	162.1	$	161.8
Sales to Canadys Refined Coal, LLC	149.0		161.1		160.8

Millions of Dollars	2018		2017
Receivable from Canadys Refined Coal, LLC	$	6.8	$	4.9
Payable to Canadys Refined Coal, LLC	6.8		4.9

SCE&G

Related Party Transaction [Line Items]

Schedule of Related Party Transactions [Table Text Block]

Millions of Dollars	2018		2017		2016
Purchases from Canadys Refined Coal, LLC	$	149.9	$	162.1	$	161.8
Sales to Canadys Refined Coal, LLC	149.0		161.1		160.8

Millions of Dollars	2018		2017
Receivable from Canadys Refined Coal, LLC	$	6.8	$	4.9
Payable to Canadys Refined Coal, LLC	6.8		4.9

Millions of Dollars	2018		2017		2016
Purchases from SCANA Energy	$	139.0	$	127.4	$	111.5
Direct and Allocated Costs from SCANA Services	283.3		302.8		337.7

Millions of Dollars	2018		2017
Payable to SCANA Energy	$	14.1	$	10.0
Payable to SCANA Services	37.7		42.0

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OTHER INCOME (EXPENSE), NET (Tables)

12 Months Ended

Dec. 31, 2018

Schedule of Other Operating Cost and Expense, by Component [Table Text Block]

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
Revenues from contracts with customers	$	20		—			—			$	5		—			—
Other income	180			$	79		$	64		141			$	45		$	29
Other expense	(46		)	(55		)	(52		)	(28		)	(32		)	(36		)
Allowance for equity funds used during construction	19			23			29			11			15			26
Other income (expense), net	$	173		$	47		$	41		$	129		$	28		$	19

SCE&G

Schedule of Other Operating Cost and Expense, by Component [Table Text Block]

	The Company									Consolidated SCE&G
Millions of dollars	2018			2017			2016			2018			2017			2016
Revenues from contracts with customers	$	20		—			—			$	5		—			—
Other income	180			$	79		$	64		141			$	45		$	29
Other expense	(46		)	(55		)	(52		)	(28		)	(32		)	(36		)
Allowance for equity funds used during construction	19			23			29			11			15			26
Other income (expense), net	$	173		$	47		$	41		$	129		$	28		$	19

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QUARTERLY FINANCIAL INFORMATION (Tables)

12 Months Ended

Dec. 31, 2018

Statement [Line Items]

Schedule of Quarterly Financial Information [Table Text Block]

The Company Millions of dollars, except per share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Annual
2018
Total Operating Revenues	$	1,180	$	843	$	926	$	1,103		$	4,052
Operating Income (Loss)	189		103		183		(1,204		)	(729		)
Net Income (Loss)	169		8		67		(772		)	(528		)
Earnings (Loss) Per Share of Common Stock	1.18		0.06		0.47		(5.41		)	(3.70		)
2017
Total Operating Revenues	$	1,173	$	1,001	$	1,076	$	1,157		$	4,407
Operating Income (Loss)	320		251		122		(608		)	85
Net Income (Loss)	171		121		34		(445		)	(119		)
Earnings (Loss) Per Share of Common Stock	1.19		0.85		0.24		(3.11		)	(0.83		)

SCE&G

Statement [Line Items]

Schedule of Quarterly Financial Information [Table Text Block]

Consolidated SCE&G Millions of dollars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Annual
2018
Total Operating Revenues	$	702	$	632	$	739	$	689		$	2,762
Operating Income (Loss)	121		107		212		(1,271		)	(831		)
Total Comprehensive Income (Loss)	128		31		104		(852		)	(589		)
Comprehensive Income Available (Loss Attributable) to Common Shareholder	124		26		98		(861		)	(613		)
2017
Total Operating Revenues	$	719	$	756	$	856	$	739		$	3,070
Operating Income (Loss)	226		247		124		(680		)	(83		)
Total Comprehensive Income (Loss)	112		126		42		(452		)	(172		)
Comprehensive Income Available (Loss Attributable) to Common Shareholder	109		123		39		(456		)	(185		)

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Long Term Purchase Commitment (Tables)

12 Months Ended

Dec. 31, 2018

Long-term Purchase Commitment [Line Items]

Long-term Purchase Commitment [Table Text Block]

	Future Payments
Millions of dollars	2019		2020		2021		2022		2023		Thereafter
The Company and Consolidated SCE&G	$	40	$	39	$	39	$	38	$	38	$	396

SCE&G

Long-term Purchase Commitment [Line Items]

Long-term Purchase Commitment [Table Text Block]

	Future Payments
Millions of dollars	2019		2020		2021		2022		2023		Thereafter
The Company and Consolidated SCE&G	$	40	$	39	$	39	$	38	$	38	$	396

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) shares in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2019 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($) MW shares	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($) shares
Significant Accounting Policies
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 30,000,000	$ 35,000,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents			$ 115,000,000
Utilities Operating Expense, Maintenance and Operations, Affiliate			18,400,000
Cost, Maintenance			16,300,000	$ 26,100,000
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA				18.00%
Reclassification Operations and Maintenance Expense				$ (9,000,000)	$ (14,000,000)
Long-term Debt, Current Maturities			59,000,000	727,000,000
Short-term borrowings			173,000,000	350,000,000
Regulated Operating Revenue, Gas			934,000,000	874,000,000	788,000,000
Decommissioning Liability, Noncurrent			625,800,000
Payments to Acquire Investments to be Held in Decommissioning Trust Fund			3,200,000
Unbilled Receivables, Current			217,500,000	220,900,000
Goodwill			210,000,000	210,000,000
Accumulated Amortization and Write-down, Goodwill			230,000,000
Nuclear refueling outage cost			28,600,000	23,200,000
Property, Plant and Equipment, Net			267,000,000	270,000,000
Reclassification Total Operating Expense				(9,000,000)	(14,000,000)
Reclassification Operating Income				9,000,000	14,000,000
Reclassification Other Income(Expense)				$ (9,000,000)	(14,000,000)
Change in Retail Electric Rates Approved Under BLRA			$ 2,768,000,000		$ 64,400,000
Public Utilities, Approved Return on Equity, Percentage		10.00%			10.50%
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent	8,000,000
Asset Management and Supply Service Agreements
Public Utilities, Allowance for Funds Used During Construction, Rate			0.00%	0.00%	0.00%
Earnings Per Share
Weighted Average Shares Outstanding - Basic | shares			143	143	143
SCE&G
Significant Accounting Policies
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	15,000,000	$ 20,000,000
Utilities Operating Expense, Maintenance and Operations, Affiliate			$ 182,000,000	$ 180,000,000	$ 199,000,000
Reclassification Operations and Maintenance Expense				(7,000,000)	(12,000,000)
Long-term Debt, Current Maturities			14,000,000	723,000,000
Short-term borrowings			73,000,000	252,000,000
Regulated Operating Revenue, Gas			434,000,000	405,000,000	366,000,000
Environmental Remediation Costs Recognized in Regulatory Assets			23,300,000
Unbilled Receivables, Current			129,300,000	140,300,000
Property, Plant and Equipment, Net			$ 72,000,000	71,000,000
Reclassification Total Operating Expense				(7,000,000)	(12,000,000)
Reclassification Operating Income				7,000,000	12,000,000
Reclassification Other Income(Expense)				$ (7,000,000)	$ (12,000,000)
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent	$ 1,000,000
Asset Management and Supply Service Agreements
Public Utilities, Allowance for Funds Used During Construction, Rate			0.00%	0.00%	0.00%
Genco [Member]
Significant Accounting Policies
Power Generation Capacity Megawatts | MW			605
Property, Plant and Equipment, Net			$ 500,000,000
PSNC Energy
Significant Accounting Policies
Natural gas inventory, carrying amount			$ 13,900,000	$ 11,500,000
PercentOfStorageFeesCreditedToRatePayers			75.00%
PSNC Energy
Significant Accounting Policies
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)			46.00%	39.00%
Summer Station Unit 2 and Unit 3 [Domain]
Significant Accounting Policies
Jointly Owned Utility Plant, Proportionate Ownership Share			55.00%
SCE&G
Significant Accounting Policies
Amount accrued annually for nuclear fuel outages			$ 17,200,000
Electric Generation Equipment [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.61%
Electric Generation Equipment [Member] | SCE&G
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.61%
Gas Transmission Equipment [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.47%
Gas Transmission Equipment [Member] | SCE&G
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.74%
Gas Distribution Equipment [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.48%
Gas Distribution Equipment [Member] | SCE&G
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.41%
Natural Gas, Storage [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.48%
Natural Gas, Storage [Member] | SCE&G
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.71%
Other Energy Equipment [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			5.64%
Other Energy Equipment [Member] | SCE&G
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			3.18%

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RATE AND OTHER REGULATORY MATTERS RATE AND OTHER REGULATORY MATTERS (Details) - USD ($)	3 Months Ended					12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
PSNC Energy Rate Case Application, Increase Amount									$ 0.18
Public Utilities, Approved Rate Increase (Decrease), Percentage							3.20%
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances							$ 2,000,000,000
Deferred Revenue, Refund Payments							2,039,000,000
Customer Refundable Fees, Alternative Plan over 20 yrs							1,032,000,000
Customer Refundable Fees, Alternative Plan							1,007,000,000
Refundable Gas Costs		$ 2,450,000					2,450,000
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Charitable Contributions, Amount							1,000,000
SCPSC Order, Recovery Of Projected DER Program Costs							29,300,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery						$ 35,400,000	$ 1,300,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent					35.00%		21.00%	35.00%
Refund to Customer Related to Tax Act							$ 73,700,000
Change in Retail Electric Rates Approved Under BLRA							2,768,000,000		$ 64,400,000
Public Utilities, Approved Return on Equity, Percentage						10.00%			10.50%
SCE&G
Demand Side Management Program Costs, Noncurrent		33,000,000		$ 37,000,000		$ 30,300,000	33,000,000	$ 37,000,000	$ 37,600,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances							31,000,000		61,000,000
SCPSC Order, Recovery Of Projected DER Program Costs								16,500,000	6,900,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery								61,000,000
Carrying costs on deferred income tax assets								18,800,000	$ 14,000,000
SCPSC Order, Approx Annual pension rider decrease amount								11,900,000
Refund to Customer Related to Tax Act						67,000,000	$ 100,000,000
PSNC Energy [Member]
Customer Credits, Alternative Plan over 3 yrs						$ 1,250,000
PSNC Energy Rate Case Application, Increase Amount								$ 19,100,000
Public Utilities, Approved Rate Increase (Decrease), Percentage								4.39%
Pipeline integrity mgmt annual revenue requirement approved by NCUC	$ 1,700,000	$ 1,100,000	$ 14,700,000	$ 700,000	$ 1,900,000
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period							106 years
Revenue Subject to Refund [Member] | SCE&G
Refund to Customer Related to Tax Act							$ 3,700,000
Revenue Subject to Refund [Member] | PSNC Energy [Member]
Refund to Customer Related to Tax Act							$ 15,400,000

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RATE AND OTHER REGULATORY MATTERS ELECTRIC-BLRA (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Entity Information [Line Items]
Utilities Operating Expense, Impairments	$ 1,376.0	$ 1,118.0
Accumulated Carrying Costs Written Off		$ 51.0
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA		18.00%
SCE&G
Entity Information [Line Items]
Utilities Operating Expense, Impairments	$ 1,376.0	$ 1,118.0

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RATE AND OTHER REGULATORY MATTERS GAS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Entity Information [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.20%
PSNC Energy Rate Case Application, Increase Amount			$ 0.18
SCE&G
Entity Information [Line Items]
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates	4.60%	2.20%	1.20%
Public Utilities changes in Retail Natural Gas Rates Approved under RSA	$ 19,700,000	$ 8,600,000	$ 4,100,000
PSNC Energy [Member]
Entity Information [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage		4.39%
Public Utilities, Authorized Allowable Return on Common Equity, Percentage		9.70%
PSNC Energy Rate Case Application, Increase Amount		$ 19,100,000

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REGULATORY ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Mar. 31, 2019	Dec. 31, 2017
Regulatory Assets, Noncurrent	$ 4,380.0		$ 5,580.0
Regulatory Liability, Noncurrent	2,789.0		3,059.0
Asset Retirement Obligation Costs [Member]
Regulatory Liability, Noncurrent	779.0		757.0
Deferred Income Tax Charge [Member]
Regulatory Liability, Noncurrent	814.0		1,076.0
Deferred gains on interest rate derivatives [Member]
Regulatory Liability, Noncurrent	77.0		131.0
Other Regulatory Liability [Member]
Regulatory Liability, Noncurrent	21.0		0.0
Unrecovered nuclear project costs post impairment [Member]
Regulatory Assets, Noncurrent	2,768.0
Demand Side Management programs [Member]
Regulatory Assets, Noncurrent	65.0		59.0
Pipeline integrity management costs [Member]
Regulatory Assets, Noncurrent	73.0		51.0
Storm Costs [Member]
Regulatory Assets, Noncurrent	35.0		24.0
Deferred transmission operating costs [Member] [Domain]
Regulatory Assets, Noncurrent	$ 15.0		0.0
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period	106 years
Regulatory Assets, Noncurrent	$ 406.0		434.0
Pension Costs [Member]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	1.0
Regulatory Assets, Noncurrent	302.0		305.0
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets, Noncurrent	448.0		456.0
Canadys Refined Coal [Member]
Regulatory Assets, Noncurrent	93.0		105.0
Environmental Restoration Costs [Member]
Regulatory Assets, Noncurrent	$ 27.0		30.0
Other Regulatory Assets [Member]
Regulatory Asset Recovery Assessments	2047
Regulatory Assets, Noncurrent	$ 148.0		140.0
Summer Station Unit 2 and Unit 3 [Domain] | Settlement Proceeds [Member]
Regulatory Liability, Noncurrent	1,098.0		1,095.0
SCE&G
Regulatory Assets, Noncurrent	4,256.0		5,476.0
Regulatory Liability, Noncurrent	2,380.0		2,667.0
SCE&G | Settlement Proceeds [Member]
Regulatory Liability, Noncurrent	1,098.0		1,095.0
SCE&G | Asset Retirement Obligation Costs [Member]
Regulatory Liability, Noncurrent	541.0		527.0
SCE&G | Deferred Income Tax Charge [Member]
Regulatory Liability, Noncurrent	659.0		914.0
SCE&G | Deferred gains on interest rate derivatives [Member]
Regulatory Liability, Noncurrent	77.0		131.0
SCE&G | Other Regulatory Liability [Member]
Regulatory Liability, Noncurrent	5.0		0.0
SCE&G | Unrecovered nuclear project costs post impairment [Member]
Regulatory Assets, Noncurrent	2,768.0		3,976.0
SCE&G | Demand Side Management programs [Member]
Regulatory Assets, Noncurrent	65.0		59.0
SCE&G | Pipeline integrity management costs [Member]
Regulatory Assets, Noncurrent	9.0		8.0
Pipeline integrity management costs, annual amortization amount	3.2	$ 1.9
SCE&G | Storm Costs [Member]
Regulatory Assets, Noncurrent	35.0		24.0
SCE&G | Deferred transmission operating costs [Member] [Domain]
Regulatory Assets, Noncurrent	15.0		0.0
SCE&G | Asset Retirement Obligation Costs [Member]
Regulatory Assets, Noncurrent	380.0		410.0
SCE&G | Pension Costs [Member]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	2.0
Regulatory Assets, Noncurrent	272.0		273.0
SCE&G | Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets, Noncurrent	448.0		456.0
SCE&G | Canadys Refined Coal [Member]
Regulatory Assets, Noncurrent	93.0		105.0
SCE&G | Environmental Restoration Costs [Member]
Regulatory Assets, Noncurrent	24.0		25.0
SCE&G | Other Regulatory Assets [Member]
Regulatory Assets, Noncurrent			$ 140.0
PSNC Energy [Member]
Pipeline integrity management costs, amount recovering beginning November 2016	4.1
Pipeline integrity management costs, amount deferred pending future approval of rate recovery	$ 51.3

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RATE AND OTHER REGULATORY MATTERS NARRATIVE (Details)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period	106 years
PSNC Energy [Member]
MPG environmental remediation	3.8

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REVENUE RECOGNITION (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Contract with Customer, Liability	$ 9.4				$ 8.3				$ 9.4	$ 8.3
Total Operating Revenues Gas									931.0
Regulated Operating Revenue, Gas									934.0	874.0	$ 788.0
Electric Regulated Revenue									2,322.0	2,659.0	2,614.0
Residential [Member]
Gas -non regulated revenues									244.0
Total Operating Revenues Gas									533.0
Commercial [Member]
Gas -non regulated revenues									92.0
Total Operating Revenues Gas									242.0
Industrial [Member]
Gas -non regulated revenues									422.0
Total Operating Revenues Gas									107.0
Wholesale [Member]
Gas -non regulated revenues									38.0
Total Operating Revenues Gas									4.0
Gas Distribution
Regulated Operating Revenue, Other									4.0
Total Operating Revenues Gas									935.0
Gas Marketing segment [Member]
Regulated Operating Revenue, Other									0.0
Regulated Operating Revenue									796.0
Revenue from Contract with Customer, Excluding Assessed Tax									796.0
SCE&G
Contract with Customer, Liability	3.6				2.9				3.6	2.9
Regulated Operating Revenue	689.0	$ 739.0	$ 632.0	$ 702.0	739.0	$ 856.0	$ 756.0	$ 719.0	2,762.0	3,070.0	2,986.0
Capitalized Contract Cost, Amortization									(1.5)
Capitalized Contract Cost, Gross	0.0								0.0
Capitalized Contract Cost, Net	$ 14.8				$ 16.3				14.8	16.3
Regulated Operating Revenue, Gas									434.0	405.0	366.0
Electric Regulated Revenue									2,322.0	$ 2,659.0	$ 2,614.0
SCE&G | Residential [Member]
Regulated Operating Revenue, Gas									208.0
Electric Regulated Revenue									1,054.0
SCE&G | Commercial [Member]
Regulated Operating Revenue, Gas									117.0
Electric Regulated Revenue									744.0
SCE&G | Industrial [Member]
Regulated Operating Revenue, Gas									92.0
Electric Regulated Revenue									385.0
SCE&G | Transportation [Member] [Domain]
Gas -non regulated revenues									0.0
Total Operating Revenues Gas									45.0
Regulated Operating Revenue, Gas									13.0
Electric Regulated Revenue									0.0
SCE&G | Wholesale [Member]
Regulated Operating Revenue, Gas									4.0
Electric Regulated Revenue									132.0
SCE&G | Electric Operations
Regulated Operating Revenue, Other									12.0
Regulated Operating Revenue									2,327.0
Revenue from Contract with Customer, Excluding Assessed Tax									2,315.0
SCE&G | Gas Distribution
Regulated Operating Revenue, Other									1.0
Regulated Operating Revenue									435.0
Revenue from Contract with Customer, Excluding Assessed Tax									434.0
PSNC Energy [Member] | Residential [Member]
Regulated Operating Revenue, Gas									325.0
PSNC Energy [Member] | Commercial [Member]
Regulated Operating Revenue, Gas									125.0
PSNC Energy [Member] | Industrial [Member]
Regulated Operating Revenue, Gas									15.0
PSNC Energy [Member] | Transportation [Member] [Domain]
Regulated Operating Revenue, Gas									32.0
PSNC Energy [Member] | Wholesale [Member]
Regulated Operating Revenue, Gas									0.0
PSNC Energy [Member] | Gas Distribution
Regulated Operating Revenue, Other									3.0
Regulated Operating Revenue									500.0
Revenue from Contract with Customer, Excluding Assessed Tax									$ 497.0

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COMMON EQUITY (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	200,000,000
SCE&G
Schedule of Capitalization, Equity [Line Items]
Retained Earnings, Appropriated	$ 115.0	$ 93.9
Common Stock, Shares Authorized	50,000,000
Preferred Stock, Shares Authorized	20,000,000
Preferred Stock, Shares Outstanding	1,000
Genco [Member]
Schedule of Capitalization, Equity [Line Items]
General Partners' Contributed Capital	$ 23.0
Fuel Company [Member]
Schedule of Capitalization, Equity [Line Items]
General Partners' Contributed Capital	1.0
SCANA [Member]
Schedule of Capitalization, Equity [Line Items]
General Partners' Contributed Capital	$ 675.0
PSNC Energy [Member]
Schedule of Capitalization, Equity [Line Items]
Dividend Payment Restrictions Schedule, Description	$30 million plus 85%
Dividends, Common Stock, Cash	$ 100.0

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LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($) $ in Millions	6 Months Ended		9 Months Ended	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Contractual Obligation, Due in Next Fiscal Year				$ 40.0
Repayments of First Mortgage Bond			$ 250.0
interest rate first mortgage bonds redeemed			6.50%
interest rate on first mortgage bonds issued			4.25%
Medium-term Notes				800.0	$ 800.0
Senior Notes				70.0	75.0
Borrowings under credit agreement				100.0
First Mortgage Bonds				4,990.0	4,840.0
GENCO Notes				40.0	207.0
Industrial and Pollution Control Bonds				122.0	122.0
Senior Notes, Noncurrent				700.0	600.0
Other Long-term Debt				73.0	28.0
Long-term Debt, Gross				6,795.0	6,672.0
Long-term Debt, Current Maturities				(59.0)	(727.0)
Debt Instrument, Unamortized Discount				2.0	1.0
Unamortized Debt Issuance Expense				(39.0)	(38.0)
Long-term Debt				6,695.0	$ 5,906.0
Long-term Line of Credit				$ 40.0
Line of Credit Facility, Interest Rate at Period End				3.87%
Proceeds from Issuance of First Mortgage Bond				$ 300.0
Long-term Debt Current Maturities in Next Twelve Months				59.0
Long-term Debt, Maturities, Repayments of Principal in Year Two				368.0
Long-term Debt, Maturities, Repayments of Principal in Year Three				797.0
Long-term Debt, Maturities, Repayments of Principal in Year Four				266.0
Long-term Debt, Maturities, Repayments of Principal in Year Five				14.0
Aggregate Purchase Price Bonds				$ 1,000.0
Medium-term Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				5.42%	5.42%
Debt Instrument, Redemption Period, Start Date					Apr. 01, 2020
Debt Instrument, Redemption Period, End Date					Feb. 01, 2022
First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				5.52%	5.80%
Debt Instrument, Redemption Period, Start Date					Nov. 01, 2021
Debt Instrument, Redemption Period, End Date					Jun. 01, 2065
Genco Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				5.49%	5.94%
Debt Instrument, Redemption Period, Start Date					Feb. 01, 2019
Debt Instrument, Redemption Period, End Date					Feb. 01, 2024
Industrial and Pollution Control Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				3.52%	3.52%
Debt Instrument, Redemption Period, Start Date					Feb. 01, 2028
Debt Instrument, Redemption Period, End Date					Dec. 01, 2038
Long-term Debt, Percentage Bearing Variable Interest, Amount				$ 67.8
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate				1.72%	1.85%
Senior Debentures [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				5.07%	5.19%
Debt Instrument, Redemption Period, Start Date					Mar. 30, 2020
Debt Instrument, Redemption Period, End Date					Dec. 15, 2047
Other Debt [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				3.46%	2.83%
Debt Instrument, Redemption Period, Start Date					Jan. 01, 2019
Debt Instrument, Redemption Period, End Date					Sep. 30, 2027
Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				3.44%	2.18%
Debt Instrument, Redemption Period, Start Date					Jun. 01, 2019
Debt Instrument, Redemption Period, End Date					Jun. 01, 2034
Long-term Debt, Percentage Bearing Fixed Interest, Percentage Rate				6.17%
SCE&G
Debt Instrument [Line Items]
Repayments of First Mortgage Bond			$ 300.0
interest rate first mortgage bonds redeemed			5.25%
Medium-term Notes				$ 300.0
First Mortgage Bonds				4,990.0	$ 4,840.0
GENCO Notes			$ 160.0	40.0	207.0
Industrial and Pollution Control Bonds				122.0	122.0
Other Long-term Debt				30.0	28.0
Long-term Debt, Gross				5,182.0	5,197.0
Long-term Debt, Current Maturities				(14.0)	(723.0)
Debt Instrument, Unamortized Discount (Premium), Net				(1.0)	1.0
Unamortized Debt Issuance Expense				(35.0)	(34.0)
Long-term Debt				5,132.0	4,441.0
Debt, Weighted Average Interest Rate			6.06%
Proceeds from Issuance of First Mortgage Bond			$ 400.0
Long-term Debt, Maturities, Repayments of Principal in Year Two					$ 13.0
Long-term Debt, Maturities, Repayments of Principal in Year Three				342.0
Long-term Debt, Maturities, Repayments of Principal in Year Four				11.0
Long-term Debt, Maturities, Repayments of Principal in Year Five				$ 9.0
SCE&G | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				5.52%	5.80%
Debt Instrument, Redemption Period, End Date					Jun. 01, 2065
SCE&G | Genco Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				5.49%	5.94%
Debt Instrument, Redemption Period, End Date					Feb. 01, 2024
SCE&G | Industrial and Pollution Control Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				3.52%	3.52%
Debt Instrument, Redemption Period, End Date					Dec. 01, 2038
Long-term Debt, Percentage Bearing Variable Interest, Amount				$ 67.8
SCE&G | Other Debt [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				2.97%	2.83%
Debt Instrument, Redemption Period, Start Date					Jan. 31, 2019
Debt Instrument, Redemption Period, End Date					Sep. 30, 2027
SCEG including Fuel Company [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				3.82%	1.92%
Long-term Debt Current Maturities in Next Twelve Months				$ 14.0
PSNC Energy [Member]
Debt Instrument [Line Items]
Senior Notes	$ 100.0	$ 150.0
Debt Instrument, Interest Rate, Increase (Decrease)	4.33%	4.18%
Debt, Weighted Average Interest Rate				3.49%	1.93%
First Mortgage Bond rate [Domain]
Debt Instrument [Line Items]
interest rate on first mortgage bonds issued				3.50%

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LONG-TERM AND SHORT-TERM DEBT (Details 2)	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2018
Debt Instrument, Redemption [Line Items]
Medium-term Notes	$ 800,000,000	$ 800,000,000
Interest Income, Related Party	4,000,000
Related Party Transaction, Due from (to) Related Party, Current	$ 282,000,000	28,000,000
Bond Ratio	4.01
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,800,000,000	2,000,000,000
Long-term Line of Credit	$ 40,000,000
Line of Credit Facility, Interest Rate at Period End	3.87%
Commercial Paper	$ 172,900,000	350,300,000
commercial paper available to be borrowed		600,000,000
Letters of Credit Outstanding, Amount	37,600,000	3,300,000
Line of Credit Facility, Remaining Borrowing Capacity	1,549,500,000	1,646,400,000
Genco [Member]
Debt Instrument, Redemption [Line Items]
Commercial Paper		200,000,000
SCEG including Fuel Company [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,200,000,000	1,400,000,000
Commercial Paper	$ 73,200,000	$ 251,600,000
Debt, Weighted Average Interest Rate	3.82%	1.92%
Letters of Credit Outstanding, Amount	$ 300,000	$ 300,000
Line of Credit Facility, Remaining Borrowing Capacity	1,126,500,000	1,148,100,000
Commercial paper borrowing limit		1,600,000,000
SCANA [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	400,000,000	400,000,000
Commercial Paper	$ 2,000,000	0
Debt, Weighted Average Interest Rate	3.65%
Letters of Credit Outstanding, Amount	$ 37,300,000	3,000,000
Line of Credit Facility, Remaining Borrowing Capacity	320,700,000	397,000,000
Fuel Company [Member]
Debt Instrument, Redemption [Line Items]
Long-Term Line of Credit - SC Fuel Co only	500,000,000	500,000,000
SCE&G
Debt Instrument, Redemption [Line Items]
Medium-term Notes	300,000,000
Related Party Transaction, Due from (to) Related Party, Current	353,000,000	37,000,000
Line of Credit Facility, Maximum Borrowing Capacity	700,000,000	700,000,000
Debt, Weighted Average Interest Rate			6.06%
Long-term Line of Credit - SCE&G only		200,000,000
First Mortgage Bonds	1,200,000,000
PSNC Energy [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200,000,000	200,000,000
Commercial Paper	$ 97,700,000	$ 98,700,000
Debt, Weighted Average Interest Rate	3.49%	1.93%
Line of Credit Facility, Remaining Borrowing Capacity	$ 102,300,000	$ 101,300,000
Industrial and Pollution Control Bonds [Member]
Debt Instrument, Redemption [Line Items]
Debt, Weighted Average Interest Rate	3.52%	3.52%
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	1.72%	1.85%
Industrial and Pollution Control Bonds [Member] | SCE&G
Debt Instrument, Redemption [Line Items]
Debt, Weighted Average Interest Rate	3.52%	3.52%
Wells Fargo, National Association, Bank of America & Morgan Stanley [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity		$ 0.095
JP Morgan Chase, Mizuho Corp, TD Bank, Credit Suisse AG ,Cayman Islands Branch and UBS Loan Finance [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity		7.9
royal bank of canada [Domain]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity		0.055
3 Year Credit [Domain]
Debt Instrument, Redemption [Line Items]
Long-term Line of Credit - SCE&G only		200,000,000
five year credit [Domain]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,300,000,000	$ 1,300,000,000

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LONG-TERM AND SHORT-TERM DEBT (NARRATIVE) (Details)	12 Months Ended
	Dec. 31, 2018
Debt Instrument [Line Items]
months preceding issuance of bonds	18
Unfunded property additions	70.00%
Consecutive months for bond ratio	12

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INCOME TAXES (Details) - USD ($)	3 Months Ended			12 Months Ended
	Dec. 31, 2018	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Investments, Owned, Federal Income Tax Note [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	$ 539,000,000			$ 539,000,000	$ 600,000,000
Deferred Tax Asset, Legal Settlement net of tax	274,000,000			274,000,000	273,000,000
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards	106,000,000			106,000,000	$ 98,000,000	$ 350,000,000	$ 49,000,000
Decrease in Unrecognized Tax Benefits is Reasonably Possible	11,000,000			11,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	106,000,000			$ 106,000,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent			35.00%	21.00%	35.00%
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)				$ (8,000,000)	$ (414,000,000)	36,000,000
Current State and Local Tax Expense (Benefit)				5,000,000	18,000,000	13,000,000
Current Income Tax Expense (Benefit)				(3,000,000)	(396,000,000)	49,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred State and Local Income Tax Expense (Benefit)				(55,000,000)	(37,000,000)	21,000,000
Income Tax Reconciliation, Tax Credits, Investment [Abstract]
Income Tax Expense (Benefit)				(412,000,000)	(112,000,000)	271,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic				(940,000,000)	(231,000,000)	866,000,000
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount				(197,000,000)	(81,000,000)	303,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount				(37,000,000)	(7,000,000)	27,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits				(3,000,000)	(5,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction				(4,000,000)	(8,000,000)	(10,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Dividends, Amount				(2,000,000)	(9,000,000)	(10,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits				(2,000,000)	(2,000,000)	(2,000,000)
Section 45 tax credit				(9,000,000)	(8,000,000)	(8,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent				0	(18,000,000)	(23,000,000)
Income Tax Reconcilation, Tax Reform Remeasurement				188,000,000	(30,000,000)
Income Tax Reconciliation, Sale of Subsidiaries				5,000,000	0	0
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount				2,000,000	(4,000,000)	(1,000,000)
Deferred tax Nuclear Decommissioning	143,000,000			143,000,000	141,000,000
Deferred Tax Asset, Remeasurement	0			0	54,000,000
Deferred Tax Assets, Financial Instruments	10,000,000			10,000,000	15,000,000
Deferred Tax Asset, Unamortized Investment, Tax Credits	7,000,000			7,000,000	8,000,000
Deferred Tax Assets, Other	4,000,000			4,000,000	6,000,000
Deferred Tax Assets, Net	1,061,000,000			1,061,000,000	1,185,000,000
Deferred Tax Liabilities, Property, Plant and Equipment	1,227,000,000			1,227,000,000	1,220,000,000
Deferred Tax Liability, Impairment	668,000,000			668,000,000	962,000,000
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	60,000,000			60,000,000	60,000,000
Deferred Tax Liabilities, Asset Retirement Obligation	94,000,000			94,000,000	91,000,000
Deferred tax asset unrecovered plant	24,000,000			24,000,000	27,000,000
Deferred Tax Liability, Demand Side Management	16,000,000			16,000,000	16,000,000
deferred tax liability, prepayments	21,000,000			21,000,000	21,000,000
Deferred Tax Liabilities, Other	63,000,000			63,000,000	49,000,000
Deferred Tax Liabilities, Net	2,173,000,000			2,173,000,000	2,446,000,000
Deferred Tax Liabilities, Net, Noncurrent	1,112,000,000			1,112,000,000	1,261,000,000
Unrecognized tax benefits	38,000,000			38,000,000	19,000,000
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions				8,000,000	0	94,000,000
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions				0	(273,000,000)	0
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions				0	21,000,000	207,000,000
Utilities Operating Loss, Impairment, Net of Taxes	870,000,000	$ 3,000,000		53,000,000	690,000,000
SCE&G
Investments, Owned, Federal Income Tax Note [Line Items]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest				(614,000,000)
Deferred Tax Assets, Operating Loss Carryforwards	493,000,000			493,000,000	541,000,000
Deferred Tax Asset, Legal Settlement net of tax	274,000,000			274,000,000	273,000,000
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards	106,000,000			106,000,000	98,000,000	350,000,000	$ 49,000,000
Unrecognized Tax Benefits, Income Tax Penalties Expense				0
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)				(16,000,000)	(410,000,000)	50,000,000
Current State and Local Tax Expense (Benefit)				0	(18,000,000)	13,000,000
Current Income Tax Expense (Benefit)				(16,000,000)	(428,000,000)	63,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred State and Local Income Tax Expense (Benefit)				52,000,000	(2,000,000)	20,000,000
Income Tax Reconciliation, Tax Credits, Investment [Abstract]
Income Tax Expense (Benefit)				(416,000,000)	(171,000,000)	248,000,000
Net Income (Loss) Attributable to Noncontrolling Interest				25,000,000	13,000,000	13,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic				(1,005,000,000)	(343,000,000)	774,000,000
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount				(211,000,000)	(120,000,000)	271,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount				(38,000,000)	(8,000,000)	26,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits				(3,000,000)	(5,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction				(2,000,000)	(5,000,000)	(9,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits				(2,000,000)	(2,000,000)	(2,000,000)
Section 45 tax credit				(9,000,000)	(8,000,000)	(8,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent				0	(18,000,000)	(23,000,000)
Income Tax Reconcilation, Tax Reform Remeasurement				176,000,000	1,000,000
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount				2,000,000	(4,000,000)	(2,000,000)
Deferred tax Nuclear Decommissioning	135,000,000			135,000,000	132,000,000
Deferred Tax Asset, Remeasurement	0			0	54,000,000
Deferred Tax Asset, Unamortized Investment, Tax Credits	7,000,000			7,000,000	8,000,000
Deferred Tax Assets, Other	5,000,000			5,000,000	5,000,000
Deferred Tax Assets, Net	954,000,000			954,000,000	1,055,000,000
Deferred Tax Liabilities, Property, Plant and Equipment	1,033,000,000			1,033,000,000	1,035,000,000
Deferred Tax Liability, Impairment	668,000,000			668,000,000	962,000,000
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	53,000,000			53,000,000	53,000,000
Deferred Tax Liabilities, Asset Retirement Obligation	88,000,000			88,000,000	85,000,000
Deferred tax asset unrecovered plant	24,000,000			24,000,000	27,000,000
Deferred Tax Liability, Demand Side Management	16,000,000			16,000,000	16,000,000
deferred tax liability, prepayments	20,000,000			20,000,000	19,000,000
Deferred Tax Liabilities, Other	41,000,000			41,000,000	31,000,000
Deferred Tax Liabilities, Net	1,943,000,000			1,943,000,000	2,228,000,000
Deferred Tax Liabilities, Net, Noncurrent	989,000,000			989,000,000	1,173,000,000
Unrecognized tax benefits	$ 38,000,000			38,000,000	19,000,000
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions				8,000,000	0	94,000,000
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions				0	(273,000,000)	0
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions				0	$ 21,000,000	$ 207,000,000
Utilities Operating Loss, Impairment, Net of Taxes				$ 46,000,000

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INCOME TAXES INCOME TAXES (Details 2) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
income tax [Line Items]
Deferred Tax Liability, Impairment	$ 668,000,000				$ 962,000,000				$ 668,000,000	$ 962,000,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent								35.00%	21.00%	35.00%
Income Available to Common Shareholders	(772,000,000)	$ 67,000,000	$ 8,000,000	$ 169,000,000	(445,000,000)	$ 34,000,000	$ 121,000,000	$ 171,000,000	$ (528,000,000)	$ (119,000,000)	$ 595,000,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate									(197,000,000)	(81,000,000)	303,000,000
Income Tax Expense (Benefit) Continuing Operations, Income Tax Reconciliation, Changes [Abstract]
Income Tax Reconciliation, State and Local Income Taxes									(37,000,000)	(7,000,000)	27,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits									(3,000,000)	(5,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction									(4,000,000)	(8,000,000)	(10,000,000)
Income Tax Reconciliation, Deductions, Dividends									2,000,000	9,000,000	10,000,000
Amortization of Amounts Deferred under Federal Investment Tax Credits									2,000,000	2,000,000	2,000,000
Section 45 tax credit									9,000,000	8,000,000	8,000,000
Income Tax Reconciliation, Other Adjustments									2,000,000	(4,000,000)	(1,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent									0	(18,000,000)	(23,000,000)
Income Tax Expense (Benefit)									(412,000,000)	(112,000,000)	271,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic									(940,000,000)	(231,000,000)	866,000,000
Income Tax Reconciliation, Sale of Subsidiaries									5,000,000	0	0
SCE&G
income tax [Line Items]
Deferred Tax Liability, Impairment	668,000,000				962,000,000				668,000,000	962,000,000
Net Income (Loss) Attributable to Parent	$ (861,000,000)	$ 98,000,000	$ 26,000,000	$ 124,000,000	$ (456,000,000)	$ 39,000,000	$ 123,000,000	$ 109,000,000	(613,000,000)	(185,000,000)	513,000,000
Net Income (Loss) Attributable to Noncontrolling Interest									25,000,000	13,000,000	13,000,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate									(211,000,000)	(120,000,000)	271,000,000
Income Tax Expense (Benefit) Continuing Operations, Income Tax Reconciliation, Changes [Abstract]
Income Tax Reconciliation, State and Local Income Taxes									(38,000,000)	(8,000,000)	26,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits									(3,000,000)	(5,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction									(2,000,000)	(5,000,000)	(9,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits									2,000,000	2,000,000	2,000,000
Section 45 tax credit									9,000,000	8,000,000	8,000,000
Income Tax Reconciliation, Other Adjustments									2,000,000	(4,000,000)	(2,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent									0	(18,000,000)	(23,000,000)
Income Tax Expense (Benefit)									(416,000,000)	(171,000,000)	248,000,000
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest									(1,005,000,000)	(343,000,000)	774,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic									$ (1,005,000,000)	$ (343,000,000)	$ 774,000,000

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INCOME TAXES INCOME TAXES (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Investments, Owned, Federal Income Tax Note [Line Items]
Deferred Income Tax Expense (Benefit)	$ (407)	$ 286	$ 224
Deferred Federal Income Tax Expense (Benefit)	(352)	323	203
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	84	88
Deferred tax Nuclear Decommissioning	143	141
Deferred Tax Assets, Financial Instruments	10	15
Deferred Tax Asset, Unamortized Investment, Tax Credits	7	8
Deferred Tax Assets, Other	4	6
Deferred Tax Assets, Net	1,061	1,185
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	1,227	1,220
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	60	60
Deferred Tax Liabilities, Asset Retirement Obligation	94	91
Deferred tax asset unrecovered plant	24	27
Deferred Tax Liability, Demand Side Management	16	16
deferred tax liability, prepayments	21	21
Deferred Tax Liabilities, Other	63	49
Deferred Tax Liabilities, Gross	2,173	2,446
Deferred Tax Liabilities, Net, Noncurrent	1,112	1,261
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	8	0	94
Gross decreases tax positions in prior period	0	(273)	0
Gross increases current period tax positions	0	21	207
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards	106	98	350	$ 49
SCE&G
Investments, Owned, Federal Income Tax Note [Line Items]
Deferred Income Tax Expense (Benefit)	398	259	187
Deferred Federal Income Tax Expense (Benefit)	(346)	261	167
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	40	42
Deferred tax Nuclear Decommissioning	135	132
Deferred Tax Asset, Unamortized Investment, Tax Credits	7	8
Deferred Tax Assets, Other	5	5
Deferred Tax Assets, Net	954	1,055
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	1,033	1,035
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	53	53
Deferred Tax Liabilities, Asset Retirement Obligation	88	85
Deferred tax asset unrecovered plant	24	27
Deferred Tax Liability, Demand Side Management	16	16
deferred tax liability, prepayments	20	19
Deferred Tax Liabilities, Other	41	31
Deferred Tax Liabilities, Gross	1,943	2,228
Deferred Tax Liabilities, Net, Noncurrent	989	1,173
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	8	0	94
Gross decreases tax positions in prior period	0	(273)	0
Gross increases current period tax positions	0	21	207
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards	$ 106	$ 98	$ 350	$ 49

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INCOME TAXES INCOME TAXES CARRYFORWARD (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended						24 Months Ended
	Mar. 31, 2017	Dec. 31, 2037	Dec. 31, 2035	Dec. 31, 2032	Dec. 31, 2026	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2037
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%					21.00%	35.00%
Deferred Tax Assets, State Taxes						$ 30
Operating Loss Carryforwards						1,807
Renewable Energy Tax Credit						83
State Operating Loss Carryforward						2,447
Tax Credit Carryforward, Amount						4,367
Tax Carryforward [Member]
Tax Credit Carryforward, Ending Expiration Date		Dec. 31, 2037
Renewable Energy Tax Credit [Member]
Tax Credit Carryforward Expiration Date, Beginning			2035
Tax Credit Carryforward, Ending Expiration Date								Dec. 31, 2038
State NOL Carryforwards [Member]
Tax Credit Carryforward, Ending Expiration Date		Dec. 31, 2037
State and Local Jurisdiction [Member]
Tax Credit Carryforward, Ending Expiration Date				Dec. 31, 2033	Dec. 31, 2026
SCE&G
Deferred Tax Assets, State Taxes						30
Operating Loss Carryforwards						1,642
Renewable Energy Tax Credit						83
State Operating Loss Carryforward						2,198
Tax Credit Carryforward, Amount						$ 3,953

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DERIVATIVE FINANCIAL INSTRUMENTS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) MMBTU		Dec. 31, 2017 USD ($) MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	66	[1]	62
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6		6
Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	60	[1]	55
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	47	[1]	42
Energy Related Derivative [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	47		42
Commodity Contract [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	19		20
Commodity Contract [Member] | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6		6
Commodity Contract [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	13		13
Basis Swap [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	5		3
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 106.8		$ 111.2
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	35.0		735.0
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	36.4		36.4
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 35.0		$ 735.0

[1] (a) Includes amounts related to basis swap contracts totaling 5.1 bcf in 2018 and 2.6 bcf in 2017.

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DERIVATIVE FINANCIAL INSTRUMENTS FAIR VALUE ON BALANCE SHEET (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 38	$ 38
Derivative Liability	38	37
Derivative Asset	14	59
Derivative Asset, Fair Value, Gross Asset	14	59
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	1	1
Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	22	28
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability		2
Derivative Asset	1	58
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	3	7
Prepayments [Member]
Derivative [Line Items]
Derivative Liability	13
Derivative Asset	12
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	24	32
Derivative Liability	24	32
Derivative Asset	0	54
Derivative Asset, Fair Value, Gross Asset	0	54
Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1	3
Derivative Liability	1	3
Derivative Asset	1	1
Derivative Asset, Fair Value, Gross Asset	1	1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	13	3
Derivative Liability	2	2
Derivative Asset	2	4
Derivative Asset, Fair Value, Gross Asset	13	4
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	22	30
Derivative Asset, Fair Value, Gross Asset	0	0
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	2	3
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	19	24
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		1
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1	2
Derivative Asset, Fair Value, Gross Asset		0
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	16	8
Derivative Asset, Fair Value, Gross Asset	14	59
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		1
Derivative Asset, Fair Value, Gross Asset		54
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	3	4
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		1
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		2
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1	1
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Derivative Asset, Fair Value, Gross Asset	1	3
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	12	1
Derivative Asset, Fair Value, Gross Asset	11	0
SCE&G
Derivative [Line Items]
Derivative Liability	11	15
Derivative Asset	0	54
SCE&G | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	0	0
SCE&G | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	10	13
SCE&G | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset		54
SCE&G | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	1	2
SCE&G | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	11	15
Derivative Liability	11	15
Derivative Asset	0	54
Derivative Asset, Fair Value, Gross Asset	0	54
SCE&G | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	8	10
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1	1
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	7	9
SCE&G | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	3	5
Derivative Asset, Fair Value, Gross Asset	0	54
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		1
Derivative Asset, Fair Value, Gross Asset		54
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 3	$ 4

XML

DERIVATIVE FINANCIAL INSTRUMENTS ON INCOME STATEMENT (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ (2.0)	$ (7.0)	$ 4.0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	(16.0)	(6.0)	$ (13.0)
Utilities Operating Expense, Impairments	$ 1,376.0	$ 1,118.0
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 9.0	$ 7.0	$ 7.0
Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	(8.7)
Commodity Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	7.0	(1.0)	6.0
Commodity Contract [Member] | Gas Purchased for Resale [Member] [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	(0.6)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	64.0	(32.0)	(34.0)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Nonoperating Income (Expense) [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	0.0	(173.0)	$ (2.0)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(2.0)	(3.0)
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	2.8
SCE&G
Derivative [Line Items]
Utilities Operating Expense, Impairments	$ 1,376.0	$ 1,118.0
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ 64.0	$ (32.0)	$ (34.0)
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Nonoperating Income (Expense) [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income			(2.0)
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(2.0)	(3.0)
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Operating Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	115.0	(173.0)
Cash Flow Hedging [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	1.0	0.0	(1.0)
Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	1.0	(2.0)	0.0
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(1.0)	(2.0)	(2.0)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(9.0)	(7.0)	(7.0)
Cash Flow Hedging [Member] | Commodity Contract [Member]
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	(3.0)	(7.0)	5.0
Cash Flow Hedging [Member] | Commodity Contract [Member] | Gas Purchased for Resale [Member] [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(7.0)	1.0	(6.0)
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	0.9
Cash Flow Hedging [Member] | SCE&G | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	1.0	(2.0)	0.0
Cash Flow Hedging [Member] | SCE&G | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(1.0)	$ (2.0)	$ (2.0)
Cash Flow Hedging [Member] | SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	0.9
Cash Flow Hedging [Member] | SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	$ 2.8

XML

DERIVATIVE FINANCIAL INSTRUMENTS (CREDIT RISK) (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Gain (Loss) on Derivatives
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	$ 24.3	$ 28.9
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	0.5	4.8
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	24.8	33.7
Cash collateral requested from counterparty	0.0	53.5
Derivative, net asset position	0.0	53.5
Letter of Credit Available Commodity Derivatives,asset position		1.2
Commodity Derivative, net asset position	$ 1.7	$ 4.0
SCE&G
Gain (Loss) on Derivatives
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	$ 11.0	$ 10.1
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	0.2	4.6
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	11.2	14.7
Cash collateral requested from counterparty	0.0	53.5
Derivative, net asset position	0.0	53.5
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	64.0	(32.0)	$ (34.0)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	64.0	(32.0)	(34.0)
Interest Rate Contract [Member] | Interest Expense [Member] | Not Designated as Hedging Instrument [Member]
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(2.0)	(3.0)
Interest Rate Contract [Member] | Interest Expense [Member] | Not Designated as Hedging Instrument [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(2.0)	(3.0)
Interest Rate Contract [Member] | Operating Expense [Member] | Not Designated as Hedging Instrument [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	115.0	(173.0)
Interest Rate Contract [Member] | Other Nonoperating Income (Expense) [Member] | Not Designated as Hedging Instrument [Member]
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	0.0	(173.0)	(2.0)
Interest Rate Contract [Member] | Other Nonoperating Income (Expense) [Member] | Not Designated as Hedging Instrument [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income			(2.0)
Interest Rate Contract [Member] | Cash Flow Hedging [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	1.0	(2.0)	0.0
Interest Rate Contract [Member] | Cash Flow Hedging [Member] | Interest Expense [Member]
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ 1.0	$ (2.0)	$ 0.0

XML

DERIVATIVE FINANCIAL INSTRUMENTS OFFSETTING ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 3
Derivative Liability	38	$ 37
Derivative, Fair Value, Net	27
Derivative Asset, Fair Value, Gross Liability	(11)	0
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	0
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Liability, Fair Value, Gross Asset	(11)	(1)
Derivative Liabilities, Net Amount	3	8
Derivative Liability, Fair Value, Gross Liability	38	38
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	0
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	24	(29)
Derivative Assets, Net Amount	3	59
Derivative Asset	14	59
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	1	1
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability		2
Derivative Asset	1	58
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	3	7
Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	22	28
Prepayments [Member]
Derivative [Line Items]
Derivative Liability	13
Derivative Asset	12
SCE&G
Derivative [Line Items]
Derivative Liability	11	15
Derivative Asset	0	54
SCE&G | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	0	0
SCE&G | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset		54
SCE&G | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	1	2
SCE&G | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	10	13
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability	24	32
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	0
Derivative Liabilities, Net Amount	0	4
Derivative Liability, Fair Value, Gross Liability	24	32
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments		0
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	24	(28)
Derivative Assets, Net Amount	0	54
Derivative Asset	0	54
Interest Rate Contract [Member] | SCE&G
Derivative [Line Items]
Derivative Liability	11	15
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	0
Derivative Liabilities, Net Amount	0	15
Derivative Liability, Fair Value, Gross Liability	11	15
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	0
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted		0
Derivative Assets, Net Amount	0	54
Derivative Asset	0	54
Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability	1	3
Derivative Liabilities, Net Amount	1	3
Derivative Liability, Fair Value, Gross Liability	1	3
Derivative Assets, Net Amount	1	1
Derivative Asset	1	1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability	2	2
Derivative Asset, Fair Value, Gross Liability	(11)	0
Derivative Liability, Fair Value, Gross Asset	(11)	(1)
Derivative Liabilities, Net Amount	2	1
Derivative Liability, Fair Value, Gross Liability	13	3
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	0	(1)
Derivative Assets, Net Amount	2	4
Derivative Asset	2	$ 4
Other Energy Management Contract [Member] | SCE&G
Derivative [Line Items]
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	$ (11)

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 14	$ 59
Derivative Liability	$ 38	$ 37
Liabilities, Fair Value Disclosure [Abstract]
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Level 3 Fair Value Measurements	no	no
Available-for-sale Securities [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	$ 0	$ 119
Held-to-maturity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	6	6
Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	54
Derivative Liability	24	32
Interest Rate Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	54
Financial and Nonfinancial Liabilities, Fair Value Disclosure	24	32
Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	1	1
Derivative Liability	1	3
Commodity Contract [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	1	1
Financial and Nonfinancial Liabilities, Fair Value Disclosure	1	2
Commodity Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	0
Financial and Nonfinancial Liabilities, Fair Value Disclosure	0	1
Other Energy Management Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	2	4
Derivative Liability	2	2
Other Energy Management Contract [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	11	0
Financial and Nonfinancial Liabilities, Fair Value Disclosure	12	1
Other Energy Management Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	2	4
Financial and Nonfinancial Liabilities, Fair Value Disclosure	3	4
SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	54
Derivative Liability	$ 11	$ 15
Liabilities, Fair Value Disclosure [Abstract]
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Level 3 Fair Value Measurements	no	no
SCE&G | Available-for-sale Securities [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	$ 0	$ 100
SCE&G | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	54
Derivative Liability	11	15
SCE&G | Interest Rate Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	54
Financial and Nonfinancial Liabilities, Fair Value Disclosure	$ 11	$ 15

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other Long-term Debt, Noncurrent	$ 6,753.9	$ 6,632.9
Long-term debt, Fair Value	7,180.8	7,399.7
SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other Long-term Debt, Noncurrent	5,145.6	5,163.3
Long-term debt, Fair Value	$ 5,469.7	$ 5,790.3

XML

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		$ 71.7
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year, Description		no
Defined Benefit Plan, Accumulated Benefit Obligation		$ 842.4	$ 905.8
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		$ 0.7	1.6
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation		0.6	1.4
Defined Benefit Plan, Plan Assets, Amount		727.3	849.6	$ 793.6
Defined Benefit Plan, Plan Assets, Increase (Decrease) for Actual Return (Loss)		(50.6)	128.4
Defined Benefit Plan, Shared Costs Deferred		$ 24.9	$ 21.4
Defined Benefit Plan Health Care Cost Trend Rate, Assumed		6.60%
Defined Benefit Plan, Target Allocation, Equity Securities		55.00%	58.00%
Defined Benefit Plan, Target Plan Asset Allocations		34.00%	31.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
Defined Benefit Plan, Benefit Obligation, Benefits Paid			$ 72.4
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid			12.5
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		$ 1.4	1.3
Defined Benefit Plan, Benefit Obligation		253.7	289.2	274.7
Defined Benefit Plan, Service Cost		4.6	4.5	4.4
Defined Benefit Plan, Interest Cost		10.1	11.5	$ 12.1
Defined Benefit Plan, Actuarial Net (Gains) Losses		$ 38.4	$ (9.7)
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
Defined Benefit Plan, Plan Assets, Amount		$ 0.0	$ 0.0
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(253.7)	(289.2)
Liability, Defined Benefit Plan, Current		(13.3)	(13.5)
Liability, Other Postretirement Defined Benefit Plan, Noncurrent		(240.4)	(275.7)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax		1.1	3.5
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax		0.0	0.0
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax		1.1	3.5
pension and other postretirement benefit plans, regulated assets, net gains, before tax		10.9	43.3
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		0.0	0.0
Pension and other postretirement benefit plans, regulatory assets, before tax		10.9	43.3
Defined Benefit Plan, Shared Costs Deferred		12.4	14.7
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		(31.8)	9.4	$ 11.1
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(0.6)	(0.8)	(0.4)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		0.0	0.0	(0.3)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ (32.4)	$ 8.6	$ 10.4
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.74%	4.30%	4.78%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year		7.00%	6.60%	7.00%
Defined Benefit Plan, Benefit Obligation, Benefits Paid		$ 13.2
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		863.5	$ 933.2	$ 904.3
Defined Benefit Plan, Service Cost		21.0	21.7	20.7
Defined Benefit Plan, Interest Cost		34.1	37.4	39.4
Defined Benefit Plan, Actuarial Net (Gains) Losses		$ 53.1	$ (42.2)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.35%	3.71%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.00%	3.00%
Defined Benefit Plan, Plan Assets, Amount		$ 727.3	$ 849.6
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(136.2)	(83.6)
Liability, Defined Benefit Plan, Current			0.0
Liability, Defined Benefit Pension Plan, Noncurrent		(136.2)	(83.6)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax		12.8	8.8
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax		0.1	0.1
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax		12.9	8.9
pension and other postretirement benefit plans, regulated assets, net gains, before tax		230.4	194.8
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		0.7	1.2
Pension and other postretirement benefit plans, regulatory assets, before tax		231.1	196.0
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		46.7	(27.1)	29.4
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(11.1)	(14.1)	(12.7)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		(0.5)	(1.4)	(3.4)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ 35.1	$ (42.6)	$ 13.3
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.00%	7.25%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.71%	4.22%	4.68%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Benefit Obligation, Benefits Paid		$ 71.7	$ 72.4
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		$ 61.3	62.0
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year, Description		no
Defined Benefit Plan, Period for which Annual Base Earnings are Considered Under Average Pay Formula		3
Defined Benefit Plan, Accumulated Benefit Obligation		$ 714.3	769.7
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		$ 0.6	1.3
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation		0.5	1.1
Defined Benefit Plan, Plan Assets, Amount		676.7	781.3	$ 732.9
Defined Benefit Plan, Plan Assets, Increase (Decrease) for Actual Return (Loss)		$ (43.3)	$ 110.4
Defined Benefit Plan Health Care Cost Trend Rate, Assumed		6.60%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.00%
Defined Benefit Plan, Target Allocation, Equity Securities		55.00%	58.00%
Defined Benefit Plan, Target Plan Asset Allocations		34.00%	31.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
SCE&G | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		$ 10.4	$ 10.3
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		1.1	1.1
Defined Benefit Plan, Benefit Obligation		187.4	216.6	207.2
Defined Benefit Plan, Service Cost		3.6	3.7	3.6
Defined Benefit Plan, Interest Cost		8.0	9.5	$ 9.9
Defined Benefit Plan, Actuarial Net (Gains) Losses		30.7	(6.8)
Defined Benefit Plan, Amounts Funded to Parent		$ (0.8)	$ (1.4)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.38%	3.74%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.00%	3.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
Defined Benefit Plan, Plan Assets, Amount		$ 0.0	$ 0.0
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(187.4)	(216.6)
Liability, Defined Benefit Plan, Current		(10.5)	(10.8)
Liability, Other Postretirement Defined Benefit Plan, Noncurrent		(176.9)	(205.8)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax		0.5	1.5
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax		0.0	0.0
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax		0.5	1.5
pension and other postretirement benefit plans, regulated assets, net gains, before tax		9.0	35.9
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		0.0	0.0
Pension and other postretirement benefit plans, regulatory assets, before tax		9.0	35.9
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		(26.4)	7.3	$ 9.2
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(0.5)	(0.7)	0.3
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		0.0	0.0	(0.2)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ (26.9)	$ 6.6	$ 8.7
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.74%	4.30%	4.78%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year		7.00%	6.60%	7.00%
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		$ 61.3	$ 62.0
Defined Benefit Plan, Benefit Obligation		732.3	793.0	$ 768.4
Defined Benefit Plan, Service Cost		17.1	18.1	16.9
Defined Benefit Plan, Interest Cost		29.0	31.9	33.4
Defined Benefit Plan, Actuarial Net (Gains) Losses		45.5	(36.6)
Defined Benefit Plan, Amounts Funded to Parent		$ 0.0	$ 0.0
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.35%	3.71%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.00%	3.00%
Defined Benefit Plan, Plan Assets, Amount		$ 676.7	$ 781.3
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(55.6)	(11.7)
Liability, Defined Benefit Plan, Current			0.0
Liability, Defined Benefit Pension Plan, Noncurrent		(55.6)	(11.7)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax		3.4	2.1
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax		0.0	0.0
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax		3.4	2.1
pension and other postretirement benefit plans, regulated assets, net gains, before tax		202.4	171.4
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		0.6	1.0
Pension and other postretirement benefit plans, regulatory assets, before tax		203.0	172.4
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		40.7	(24.8)	26.3
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(9.7)	(12.5)	(11.2)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		(0.4)	(1.3)	(3.0)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ 30.6	$ (38.6)	$ 12.1
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.00%	7.25%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.71%	4.22%	4.68%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Pension Costs [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority		$ 1.0
Pension Costs [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority		$ 2.0
Scenario, Forecast [Member]
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%
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%
Scenario, Forecast [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%

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EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 2)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities		55.00%	58.00%
Defined Benefit Plan, Target Plan Asset Allocations		34.00%	31.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities		55.00%	58.00%
Defined Benefit Plan, Target Plan Asset Allocations		34.00%	31.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
Scenario, Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%
Scenario, Forecast [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%

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EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 727.3	$ 849.6	$ 793.6
Compensation and Benefits Trust	$ 400.0	$ 498.0
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Alternative Investment	$ 727.0	$ 850.0
Noncontrolling Interest in Joint Ventures	83.0	92.0
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	244.0	260.0
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	107.0	120.0
Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	20.0	17.0
Fair Value, Inputs, Level 2 [Member] | Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	7.0	15.0
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	92.0	91.0
Fair Value, Inputs, Level 2 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	18.0	17.0
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	676.7	781.3	$ 732.9
Compensation and Benefits Trust	$ 373.0	$ 458.0
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Alternative Investment	$ 677.0	$ 781.0
Noncontrolling Interest in Joint Ventures	77.0	84.0
SCE&G | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	227.0	239.0
SCE&G | Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	99.0	110.0
SCE&G | Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	19.0	16.0
SCE&G | Fair Value, Inputs, Level 2 [Member] | Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	7.0	14.0
SCE&G | Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	86.0	84.0
SCE&G | Fair Value, Inputs, Level 2 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 16.0	$ 15.0

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EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 4) $ in Millions	Dec. 31, 2018 USD ($)
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	$ 71.5
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	62.4
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	65.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	69.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	66.6
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	284.9
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	13.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	14.3
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	14.9
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	15.4
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	15.8
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	82.3
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	71.5
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	62.4
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	65.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	69.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	66.6
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	284.9
SCE&G | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	10.8
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	11.4
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	11.8
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	12.2
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	12.6
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	$ 65.4

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EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		$ 2.0	$ 0.0	$ 0.0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		$ (2.0)	0.0	1.0
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%
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, Cost		$ 24.1	27.9	27.5
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		4.5	(1.0)	0.6
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		(0.5)	(0.6)	(0.6)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax		0.0	0.0	(0.1)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		4.0	(1.6)	(0.1)
Defined Benefit Plan, Service Cost		21.0	21.7	20.7
Defined Benefit Plan, Interest Cost		34.1	37.4	39.4
Defined Benefit Plan, Expected Return (Loss) on Plan Assets		(56.7)	(54.7)	(55.9)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0.5	1.6	3.9
Defined Benefit Plan, Amortization of Gain (Loss)		12.8	16.3	14.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 11.7	$ 22.3	$ 22.9
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.71%	4.22%	4.68%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.00%	7.25%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		$ (2.4)	$ 1.1	$ 0.8
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		0.0	(0.1)	0.0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax		0.0	0.0	0.0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		(2.4)	1.0	0.8
Defined Benefit Plan, Service Cost		4.6	4.5	4.4
Defined Benefit Plan, Interest Cost		10.1	11.5	12.1
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0.0	0.0	0.3
Defined Benefit Plan, Amortization of Gain (Loss)		0.7	1.0	0.5
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 15.4	$ 17.0	$ 17.3
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.74%	4.30%	4.78%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year		7.00%	6.60%	7.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		$ 0.0	$ 0.0	$ 0.0
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		$ 0.0	(1.0)	0.0
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year		insignificant
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, Cost		$ 19.6	23.4	22.9
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		1.4	0.3	0.0
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		(0.1)	(0.1)	(0.1)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		1.3	0.2	(0.1)
Defined Benefit Plan, Service Cost		17.1	18.1	16.9
Defined Benefit Plan, Interest Cost		29.0	31.9	33.4
Defined Benefit Plan, Expected Return (Loss) on Plan Assets		(48.1)	(46.7)	(47.4)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0.4	1.4	3.4
Defined Benefit Plan, Amortization of Gain (Loss)		10.9	13.9	12.5
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 9.3	$ 18.6	$ 18.8
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.71%	4.22%	4.68%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.00%	7.25%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
SCE&G | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		$ (1.0)	$ 0.5	$ 0.3
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		0.0	0.0	0.0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		(1.0)	0.5	0.3
Defined Benefit Plan, Service Cost		3.6	3.7	3.6
Defined Benefit Plan, Interest Cost		8.0	9.5	9.9
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0.0	0.0	0.3
Defined Benefit Plan, Amortization of Gain (Loss)		0.6	0.8	0.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 12.2	$ 14.0	$ 14.2
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.74%	4.30%	4.78%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year		7.00%	6.60%	7.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
Scenario, Forecast [Member]
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%
Scenario, Forecast [Member] | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Amortization of Net Gains (Losses)	$ 0.8
Defined benefit plan, future amortization of gain or loss from regulatory assets	14.7
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	0.3
Defined benefit plan, amount to be amortized from regulatory assets next year	15.0
Scenario, Forecast [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Amortization of Net Gains (Losses)	0.0
Defined benefit plan, future amortization of gain or loss from regulatory assets	0.0
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	0.0
Defined benefit plan, amount to be amortized from regulatory assets next year	0.0
Scenario, Forecast [Member] | SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, future amortization of gain or loss from regulatory assets	12.9
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	0.3
Defined benefit plan, amount to be amortized from regulatory assets next year	13.2
Scenario, Forecast [Member] | SCE&G | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, future amortization of gain or loss from regulatory assets	0.0
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	0.0
Defined benefit plan, amount to be amortized from regulatory assets next year	$ 0.0

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SHARE-BASED COMPENSATION (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost	$ 28,600,000
Employee Service Share-based Compensation, Cash Flow Effect, Cash Used to Settle Awards	$ 19,600,000	$ 9,100,000	$ 6,700,000	$ 5.5	$ 28.0	$ 18.4
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized				5,000,000
Restricted Stock Units
Share-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized				1,000,000

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SHARE-BASED COMPENSATION Liability Awards (Details) - USD ($)		3 Months Ended	12 Months Ended
	Feb. 28, 2019	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Liability Awards
Cash-Settled Liabilities		$ 19,600,000	$ 9,100,000	$ 6,700,000	$ 5.5	$ 28.0	$ 18.4
Compensation Expenses Recognized Resulting From Fair Value Adjustments of Performance Awards					$ (1.7)	(9.0)	25.6
Capitalized Compensation Expense						(1.3)	3.3
Performance Shares [Member]
Liability Awards
Weight of Entity's Performance Against Pre-Determined Measures of Total Stockholder Return As Compared to Peer Groups of Utilities to Determine Payout of Performance Shares as a Percentage					50.00%
Weight of Growth in GAAP-adjusted net earnings per share from operations to determine payout of performance shares as a percent					50.00%
SCE&G
Liability Awards
Cash-Settled Liabilities					$ 3.5	20.2	13.2
Compensation Expenses Recognized Resulting From Fair Value Adjustments of Performance Awards					$ (0.9)	(6.3)	17.3
Capitalized Compensation Expense						$ (0.9)	$ 3.1
SCE&G | Restricted Stock Units
Liability Awards
Performance Cycle (in years)				3 years
Percentage of Performance Award Granted in Form of Restricted Stock Units (as a percent)					30.00%
SCE&G | Performance Shares [Member]
Liability Awards
Percentage of Performance Award Granted in Form of Performance Shares (as a percent)					70.00%
Weight of Entity's Performance Against Pre-Determined Measures of Total Stockholder Return As Compared to Peer Groups of Utilities to Determine Payout of Performance Shares as a Percentage					50.00%
Weight of Growth in GAAP-adjusted net earnings per share from operations to determine payout of performance shares as a percent					50.00%
Subsequent Event [Member] | Restricted Stock Units
Liability Awards
Percentage of Performance Award Granted in Form of Restricted Stock Units (as a percent)	30.00%
Subsequent Event [Member] | Performance Shares [Member]
Liability Awards
Percentage of Performance Award Granted in Form of Performance Shares (as a percent)	70.00%
Subsequent Event [Member] | SCE&G | Restricted Stock Units
Liability Awards
Percentage of Performance Award Granted in Form of Restricted Stock Units (as a percent)	30.00%
Subsequent Event [Member] | SCE&G | Performance Shares [Member]
Liability Awards
Percentage of Performance Award Granted in Form of Performance Shares (as a percent)	70.00%

XML

COMMITMENTS AND CONTINGENCIES (Details)	3 Months Ended		12 Months Ended
	Dec. 31, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Commitments and contingencies
Legal Expense, net of taxes			$ 118,000,000
Operating Lease, Payments				$ 10
Estimate of aggregate amount of subcontractor and vendor liens filed			285,000,000
Guarantee Settlement Receipts			2,200,000,000
Impairment loss write off	$ 1,372,000,000	$ 4,000,000	1,372,000,000	1,118,000,000
Monetization Settlement Exceeding Costs Incurred			1,997,000,000
Asset Retirement Obligation Other Conditional Obligations	359,000,000		359,000,000
Asset Retirement Obligation	$ 577,000,000		577,000,000	568,000,000	$ 558,000,000
Asset Retirement Obligation, Liabilities Incurred			0	0
Asset Retirement Obligation, Liabilities Settled			(15,000,000)	(10,000,000)
Asset Retirement Obligation, Accretion Expense			25,000,000	25,000,000
Asset Retirement Obligation, Revision of Estimate			$ (1,000,000)	$ (5,000,000)
Environmental
Emission Rate Standard For Coal Fired Power Plants Under Clean Air Act	1,400		1,400
Emission Rate Standard for Natural Gas	1,000		1,000
Goal For Reduced Carbon Dioxide Emissions From 2005 Levels By 2030 Under Clean Air Act			32.00%
Number of States affected by CSAPR	28		28
Nuclear Generation
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA				18.00%
Change in Retail Electric Rates Approved Under BLRA			$ 2,768,000,000		64,400,000
Public Utilities, Requested Rate Increase (Decrease), Amount			31,000,000
Managing Member or General Partner, Subsequent Distribution Amount			115,000,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances			2,000,000,000
Contractual Obligation, Due in Next Fiscal Year	$ 23.7		23.7	$ 3.6
SCE&G
Commitments and contingencies
Operating Lease, Payments			10	11	12
Estimate of aggregate amount of subcontractor and vendor liens filed			33,000,000
Guarantee Settlement Receipts			1,200,000,000
Monetization Settlement Exceeding Costs Incurred			1,098,000,000
Asset Retirement Obligation Other Conditional Obligations	323,000,000		323,000,000
Asset Retirement Obligation	541,000,000		541,000,000	529,000,000	522,000,000
Asset Retirement Obligation, Liabilities Incurred			0	0
Asset Retirement Obligation, Liabilities Settled			(15,000,000)	(9,000,000)
Asset Retirement Obligation, Accretion Expense			23,000,000	23,000,000
Asset Retirement Obligation, Revision of Estimate			4,000,000	$ (7,000,000)
Nuclear Insurance
Maximum Insurance Coverage For Each Nuclear Plant by ANI	450,000,000		450,000,000
Federal Limit on Public Liability Claims from Nuclear Incident Approximate			14,000,000,000
Maximum liability assessment per reactor for each nuclear incident			137,700,000
Maximum yearly assessment per reactor			20,500,000
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3			91,800,000
Maximum Insurance Coverage for Nuclear events	2,750,000,000		2,750,000,000
NEIL Maximum Insurance Coverage To Nuclear Facility For Property Damage And Outage Costs From Non-Nuclear Event			2,330,000,000
Maximum prosepective insurance premium per nuclear incident			23,400,000
Maximum amount of coverage to nuclear facility for property damage and outage costs	2,750,000,000		2,750,000,000
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
Environmental
Environmental Remediation Expense			9,500,000
Deferred costs, net of costs previously recovered through rates and insurance settlements included in regulatory assets	23,300,000		23,300,000
Nuclear Generation
Asset Retirement Obligation Nuclear Decommissioning	218,000,000		218,000,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances			31,000,000		$ 61,000,000
SCE&G | SCE&G
Nuclear Insurance
Maximum yearly assessment per reactor			13,700,000
Summer Station Unit 2 and Unit 3 [Domain]
Commitments and contingencies
Transmission Assets related to BLRA Capital Costs	$ 367,000,000		367,000,000
Estimate of aggregate amount of subcontractor and vendor liens filed			$ 60,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%		55.00%
Other Regulatory Assets (Liabilities) [Member] | Summer Station Unit 2 and Unit 3 [Domain]
Commitments and contingencies
Transmission Assets related to BLRA Capital Costs	$ 15,000,000		$ 15,000,000

XML

COMMITMENTS AND CONTINGENCIES Nuclear (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Legal Settlements				$ 157,000
Deferred Tax Asset, Legal Settlement net of tax	$ 274,000			$ 274,000	$ 273,000
Loss Contingency, Actions Taken by Plaintiff				75
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 31,000
Impairment loss write off	1,372,000	$ 4,000		1,372,000	1,118,000
Increase (Decrease) in Client Funds Held				2,000,000
Utilities Operating Expense, Impairments				1,376,000	1,118,000
Utilities Operating Loss, Impairment, Net of Taxes	870,000	$ 3,000		53,000	690,000
Guarantee Settlement Receipts				2,200,000
Estimate of aggregate amount of subcontractor and vendor liens filed				285,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances				2,000,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery			$ 35,400	1,300
Monetization Settlement Exceeding Costs Incurred				1,997,000
Long-term Debt, Current Maturities	59,000			59,000	727,000
Short-term borrowings	173,000			173,000	$ 350,000
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment				105,000
Customer Fees, Refunds Payments, Additional Liability Alternative Plan	1,007,000			1,007,000
Refundable Gas Costs	2,450			2,450
Multiemployer Plans, Minimum Contribution	22,000			22,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Impairment Losses	145,000			145,000
Increase (Decrease) in Property and Other Taxes Payable			$ 410,000
PSNC Energy [Member]
Public Utilities, Authorized Allowable Return on Common Equity, Percentage					9.70%
Multiemployer Plans, Minimum Contribution	1,000			1,000
SCE&G
Deferred Tax Asset, Legal Settlement net of tax	274,000			274,000	$ 273,000
EMANI Maximum Insurance Coverage for Summer Station Unit 1 For Property Damage And Outage Costs From Non-Nuclear Event				415,000
Federal Limit on Public Liability Claims from Nuclear Incident Approximate				14,000,000
EMANI Maximum Retrospective Premium Assessment				2,000
Utilities Operating Expense, Impairments				1,376,000	1,118,000
Utilities Operating Loss, Impairment, Net of Taxes				46,000
Guarantee Settlement Receipts				1,200,000
Estimate of aggregate amount of subcontractor and vendor liens filed				33,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances				31,000		$ 61,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery					61,000
Monetization Settlement Exceeding Costs Incurred				1,098,000
Long-term Debt, Current Maturities	14,000			14,000	723,000
Short-term borrowings	73,000			73,000	$ 252,000
Maximum Insurance Coverage For Each Nuclear Plant by ANI	450,000			450,000
Summer Station Unit 2 and Unit 3 [Domain]
Transmission Assets related to BLRA Capital Costs	367,000			367,000
Estimate of aggregate amount of subcontractor and vendor liens filed				60,000
Summer Station Unit 2 and Unit 3 [Domain]
Transmission Assets related to BLRA Capital Costs	$ 15,000			$ 15,000

XML

SEGMENT OF BUSINESS INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Total	$ 17,654				$ 18,739				$ 17,654	$ 18,739	$ 18,707
Additions to Other Assets, Amount									890	1,225	1,579
Deferred Tax Assets, Gross	0				0				0	0	0
Regulated and Unregulated Operating Revenue	1,103	$ 926	$ 843	$ 1,180	1,157	$ 1,076	$ 1,001	$ 1,173	4,052	4,407	4,227
Intersegment Revenue									0	0	0
Operating Income	(1,204)	183	103	189	(608)	122	251	320	(729)	85	1,167
Interest Expense									384	363	342
Depreciation, Depletion and Amortization									403	382	371
Income Tax Expense (Benefit)									(412)	(112)	271
Income Available to Common Shareholders	(772)	67	8	169	(445)	34	121	171	(528)	(119)	595
Regulated Operating Revenue, Gas									934	874	788
Electric Operations
Segment Reporting Information [Line Items]
Total	7,988				11,979				7,988	11,979	11,929
Additions to Other Assets, Amount									973	216	1,275
Deferred Tax Assets, Gross	(4)				(6)				(4)	(6)	(9)
Regulated and Unregulated Operating Revenue									2,322	2,659	2,614
Intersegment Revenue									5	5	5
Operating Income									(894)	(154)	969
Interest Expense									18	19	17
Depreciation, Depletion and Amortization									307	295	287
Income Tax Expense (Benefit)									9	8	8
Gas Distribution
Segment Reporting Information [Line Items]
Total	3,517				3,259				3,517	3,259	2,892
Additions to Other Assets, Amount									345	417	276
Deferred Tax Assets, Gross	(17)				(25)				(17)	(25)	(32)
Regulated and Unregulated Operating Revenue									934	874	788
Intersegment Revenue									1	2	2
Operating Income									173	187	149
Interest Expense									37	28	25
Depreciation, Depletion and Amortization									94	85	82
Income Tax Expense (Benefit)									26	41	32
Gas Marketing [Member]
Segment Reporting Information [Line Items]
Total	305				230				305	230	230
Additions to Other Assets, Amount									2	2	2
Deferred Tax Assets, Gross	(2)				(9)				(2)	(9)	(11)
Regulated and Unregulated Operating Revenue									796	874	825
Intersegment Revenue									139	127	111
Interest Expense									1	1	1
Depreciation, Depletion and Amortization									2	2	2
Income Tax Expense (Benefit)									15	25	19
Income Available to Common Shareholders									43	27	30
All Other [member]
Segment Reporting Information [Line Items]
Total	1,212				1,042				1,212	1,042	1,124
Additions to Other Assets, Amount									8	7	11
Deferred Tax Assets, Gross	0				0				0	0	0
Regulated and Unregulated Operating Revenue									0	0	0
Intersegment Revenue									470	389	414
Operating Income									0	0	0
Interest Expense									0	0	0
Depreciation, Depletion and Amortization									15	16	16
Income Tax Expense (Benefit)									(25)	(7)	0
Income Available to Common Shareholders									(90)	(46)	(18)
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Total	4,632				2,229				4,632	2,229	2,532
Additions to Other Assets, Amount									(438)	583	15
Deferred Tax Assets, Gross	23				40				23	40	52
Regulated and Unregulated Operating Revenue									0	0	0
Intersegment Revenue									(615)	(523)	(532)
Operating Income									(8)	52	49
Interest Expense									328	315	299
Depreciation, Depletion and Amortization									(15)	(16)	(16)
Income Tax Expense (Benefit)									(437)	(179)	212
Income Available to Common Shareholders									(481)	(100)	583
SCE&G
Segment Reporting Information [Line Items]
Total	14,963				15,946				14,963	15,946	16,091
Additions to Other Assets, Amount									633	928	1,399
Deferred Tax Assets, Gross	0				0				0	0	0
Regulated Operating Revenue	689	739	632	702	739	856	756	719	2,762	3,070	2,986
Operating Income	(1,271)	$ 212	$ 107	$ 121	(680)	$ 124	$ 247	$ 226	(831)	(83)	1,025
Interest Expense									303	288	270
Depreciation, Depletion and Amortization									327	312	302
Income Tax Expense (Benefit)									(416)	(171)	248
Regulated Operating Revenue, Gas									434	405	366
SCE&G | Electric Operations
Segment Reporting Information [Line Items]
Total	7,988								7,988		11,929
Additions to Other Assets, Amount									973		1,275
Deferred Tax Assets, Gross	(4)								(4)		(9)
Regulated Operating Revenue									2,327
Operating Income									(894)		969
Interest Expense									18	19	17
Depreciation, Depletion and Amortization									307	295	287
SCE&G | Gas Distribution
Segment Reporting Information [Line Items]
Total	934				869				934	869	825
Additions to Other Assets, Amount									90	65	78
Regulated and Unregulated Operating Revenue									435	406	367
Regulated Operating Revenue									435
Operating Income									63	71	56
Depreciation, Depletion and Amortization									32	30	28
SCE&G | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Total	6,041				3,098				6,041	3,098	3,337
Additions to Other Assets, Amount									(430)	647	46
Deferred Tax Assets, Gross	$ 4				$ 6				4	6	9
Operating Income											0
Interest Expense									285	269	253
Depreciation, Depletion and Amortization									(12)	(13)	(13)
External revenue [Member] | SCE&G
Segment Reporting Information [Line Items]
Regulated and Unregulated Operating Revenue									$ 2,327	$ 2,664	$ 2,619

XML

UTILITY PLANT AND NONUTILITY PROPERTY Jointly Owned Utiltiy Plant (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Utility Plant In Service	$ 15,171.0	$ 14,370.0
Property, Plant and Equipment, Gross	410.0
Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	5,751.0
Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	16,309.0
Gas Transmission Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	2,417.0
Electric Distribution [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	6,032.0
Natural Gas, Storage [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	99.0
Other Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	631.0
Other Intangible Assets [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	241.0
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	527.0
Nuclear Fuel [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	611.0
Summer Station Units 1 [Domain]
Property, Plant and Equipment [Line Items]
Accounts Receivable, Net	$ 46.3	$ 53.8
Jointly Owned Utility Plant, Proportionate Ownership Share	67.00%	67.00%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 1,500.0	$ 1,500.0
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	643.9	637.6
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	127.5	110.1
SCE&G
Property, Plant and Equipment [Line Items]
Utility Plant In Service	12,803.0	$ 12,161.0
SCE&G | Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	5,751.0
Property, Plant and Equipment, Gross	73.0
SCE&G | Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	13,764.0
SCE&G | Gas Transmission Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	1,758.0
SCE&G | Electric Distribution [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	4,456.0
SCE&G | Natural Gas, Storage [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	74.0
SCE&G | Other Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	535.0
SCE&G | Other Intangible Assets [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	229.0
SCE&G | Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	350.0
SCE&G | Nuclear Fuel [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	$ 611.0

XML

AFFILIATED TRANSACTIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Proceeds from Equity Method Investment, Distribution	$ 2.3	$ 2.8	$ 3.7
Equity Method Investments	4.2	4.6	5.5
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Related Party Tax Expense, Due to Affiliates, Current	6.8	4.9
Related Party Transaction, Purchases from Related Party	149.9	162.1	161.8
Related Party Tax Expense, Due from Affiliates, Current	$ 6.8	4.9
Equity Method Investment, Ownership Percentage	40.00%
Sales to Affiliate	$ 149.0	161.1	160.8
Energy Marketing [Member]
Related Party Transaction [Line Items]
Utilities Operating Expense, Gas and Petroleum Purchased, affiliate	139.0	127.4	111.5
SCE&G
Related Party Transaction [Line Items]
Utilities Operating Expense, Gas and Petroleum Purchased, affiliate			9.0
Related Party Tax Expense, Due to Affiliates, Current	14.1	10.0
Accounts Payable, Related Parties, Current	37.7	42.0
SCANA Services [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 283.3	$ 302.8	$ 337.7

XML

OTHER INCOME (EXPENSE), NET (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other income	$ 180	$ 79	$ 64
Other Nonoperating Expense	(46)	(55)	(52)
Public Utilities, Allowance for Funds Used During Construction, Additions	19	23	29
Nonoperating Income (Expense)	(173)	(47)	(41)
SCE&G
Other income	141	45	29
Other Nonoperating Expense	(28)	(32)	(36)
Public Utilities, Allowance for Funds Used During Construction, Additions	11	15	26
Nonoperating Income (Expense)	(129)	$ (28)	$ (19)
Interest Rate Contract [Member] | Other Income [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ 114

XML

QUARTERLY FINANCIAL INFORMATION (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Regulated and Unregulated Operating Revenue	$ 1,103	$ 926	$ 843	$ 1,180	$ 1,157	$ 1,076	$ 1,001	$ 1,173	$ 4,052	$ 4,407	$ 4,227
Operating Income (Loss)	(1,204)	183	103	189	(608)	122	251	320	(729)	85	1,167
Income Available to Common Shareholders	$ (772)	$ 67	$ 8	$ 169	$ (445)	$ 34	$ 121	$ 171	$ (528)	$ (119)	$ 595
Earnings Per Share, Basic and Diluted	$ (5.41)	$ 0.47	$ 0.06	$ 1.18	$ (3.11)	$ 0.24	$ 0.85	$ 1.19	$ (3.70)	$ (0.83)	$ 4.16
SCE&G
Regulated Operating Revenue	$ 689	$ 739	$ 632	$ 702	$ 739	$ 856	$ 756	$ 719	$ 2,762	$ 3,070	$ 2,986
Operating Income (Loss)	(1,271)	212	107	121	(680)	124	247	226	(831)	(83)	1,025
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(852)	104	31	128	(452)	42	126	112	(589)	(172)	526
Net Income (Loss) Attributable to Parent	$ (861)	$ 98	$ 26	$ 124	$ (456)	$ 39	$ 123	$ 109	(613)	$ (185)	$ 513
Income (Loss) from Continuing Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest									$ (613)

XML

SCHEDULE II (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
SEC Schedule, 12-09, Allowance, Credit Loss [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	$ 7	$ 6	$ 6	$ 5
Valuation Allowances and Reserves, Charged to Cost and Expense	15	13	12
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	14	13	11
General Liability [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	7	9	9	6
Valuation Allowances and Reserves, Charged to Cost and Expense	5	8	5
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	7	8	2
SCE&G | SEC Schedule, 12-09, Allowance, Credit Loss [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	4	4	3	3
Valuation Allowances and Reserves, Charged to Cost and Expense	7	8	6
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	7	7	6
SCE&G | General Liability [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	6	8	8	$ 5
Valuation Allowances and Reserves, Charged to Cost and Expense	5	8	5
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	$ 7	$ 8	$ 2