10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2018

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 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 pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

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

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 Rule 12b-2 of the Exchange Act).

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

	Description of	Shares Outstanding
Registrant	Common Stock	at October 26, 2018
SCANA Corporation	Without Par Value	142,619,243
South Carolina Electric & Gas Company	Without Par Value	40,296,147 (a)

(a) Held beneficially and of record by SCANA Corporation.

This combined Form 10-Q is separately filed by SCANA Corporation and South Carolina Electric & Gas Company.  Information contained herein relating to any individual registrant is filed by such 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).

South Carolina Electric & Gas Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and therefore is filing this Form with the reduced disclosure format allowed under General Instruction H(2).

			Page
Cautionary Statement Regarding Forward-Looking Information			3
Definitions			4
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements			7
	SCANA Corporation		7
		Condensed Consolidated Balance Sheets	7
		Condensed Consolidated Statements of Income	9
		Condensed Consolidated Statements of Comprehensive Income	10
		Condensed Consolidated Statements of Cash Flows	11
		Condensed Consolidated Statements of Changes in Common Equity	12
	South Carolina Electric & Gas Company		13
		Condensed Consolidated Balance Sheets	13
		Condensed Consolidated Statements of Comprehensive Income	15
		Condensed Consolidated Statements of Cash Flows	16
		Condensed Consolidated Statements of Changes in Equity	17
	Notes to Condensed Consolidated Financial Statements		18
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			52
Item 3. Quantitative and Qualitative Disclosures About Market Risk			66
Item 4. Controls and Procedures			67
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			68
Item 1A. Risk Factors			72
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			88
Item 5. Other Information			89
Item 6. Exhibits			89
Exhibit Index			90
Signatures			91

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Statements included in this Quarterly Report on Form 10-Q 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 proposed merger with Dominion Energy, recovery of Nuclear Project abandonment costs, key earnings drivers, customer growth, environmental regulations and expenditures, leverage ratio, 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 occurrence of any event, change or other circumstances that could give rise to the failure to consummate the proposed merger with Dominion Energy; (2) 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 abandonment provisions of the BLRA or through other means; (3) uncertainties relating to the bankruptcy filing by WEC and WECTEC; (4) 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; (5) 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; (6) 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 or arising from the proposed merger with Dominion Energy, including the possible impacts on liquidity and other financial impacts therefrom; (7) the impact of any decision by SCANA to pay quarterly dividends to its shareholders or the reduction, suspension or elimination of the amount thereof; (8) 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 and its subsidiaries (the Company); (9) 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; (10) the results of efforts to ensure the physical and cyber security of key assets and processes; (11) changes in the economy, especially in areas served by subsidiaries of SCANA; (12) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial markets; (13) the impact of conservation and demand side management efforts and/or technological advances on customer usage; (14) the loss of electricity sales to distributed generation, such as solar photovoltaic systems or energy storage systems; (15) growth opportunities for SCANA’s regulated and other subsidiaries; (16) 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; (17) changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies; (18) payment and performance by counterparties and customers as contracted and when due; (19) the results of efforts to license, site, construct and finance facilities, and to receive related rate recovery, for generation and transmission; (20) 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; (21) 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; (22) 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 the announced potential merger with Dominion Energy; (23) labor disputes; (24) performance of SCANA’s pension plan assets and the effect(s) of associated discount rates; (25) inflation or deflation; (26) changes in interest rates; (27) compliance with regulations; (28) natural disasters, man-made mishaps and acts of terrorism that directly affect our operations or the regulations governing them; and (29) 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.

3

DEFINITIONS

The following abbreviations or terms used in the text have the meanings set forth below unless the context requires otherwise: 

TERM	MEANING
ACE	Affordable Clean Energy
Act 258	Act 258 (previously referenced as H. 4375) adopted by the South Carolina General Assembly
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
BLRA	Base Load Review Act
CAA	Clean Air Act, as amended
CAIR	Clean Air Interstate Rule
CCR	Coal Combustion Residuals
CEC	Columbia Energy Center
CEO	Chief Executive Officer
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 before the SCPSC related to the Nuclear Project which are being handled concurrently. The Concurrent Dockets are comprised of the Joint Petition, the Request, 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
CUT	Customer Usage Tracker (decoupling mechanism)
CWA	Clean Water Act
DER	Distributed Energy Resource
Derivative Litigation	Claims asserted against current and 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
Dominion Energy	Dominion Energy, Inc.
DOR	South Carolina Department of Revenue
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
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

4

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
LOC	Lines of Credit
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 and SCANA
MGP	Manufactured Gas Plant
MMBTU	Million British Thermal Units
MW or MWh	Megawatt or Megawatt-hour
NAAQS	National Ambient Air Quality Standards
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
NYMEX	New York Mercantile Exchange
OCI	Other Comprehensive Income
ORS	South Carolina Office of Regulatory Staff
PGA	Purchased Gas Adjustment
PHMSA	United States Pipeline Hazardous Materials Safety Administration
Price-Anderson	Price-Anderson Indemnification Act
PSNC Energy	Public Service Company of North Carolina, Incorporated
Registrants	SCANA and SCE&G
Reorganization Plan	Modified Second Amended Joint Chapter 11 Plan of Reorganization, filed by WEC
Request	Request for Rate Relief filed by the ORS on September 26, 2017, as subsequently amended on October 17, 2017
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
SCANA Energy	SCANA Energy Marketing, Inc.
SCANA Services	SCANA Services, Inc.
SCE&G	South Carolina Electric & Gas Company
SCEUC	South Carolina Energy Users Committee

5

SCPSC	Public Service Commission of South Carolina
SEC	United States Securities and Exchange Commission
Sedona	Sedona Corp., a wholly-owned subsidiary of Dominion Energy
SLC	Special Litigation Committee
SLED	South Carolina Law Enforcement Division
SO2	Sulfur Dioxide
Summer Station	V. C. Summer Nuclear Station
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
Unit 1	Nuclear Unit 1 at Summer Station
Unit 2	Nuclear Unit 2 at Summer Station (abandoned prior to completion)
Unit 3	Nuclear Unit 3 at Summer Station (abandoned prior to 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

6

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SCANA Corporation and Subsidiaries

Condensed Consolidated Balance Sheets

(Unaudited) 

Millions of dollars	September 30, 2018			December 31, 2017
Assets
Utility Plant In Service	$	15,012		$	14,370
Accumulated Depreciation and Amortization	(5,059		)	(4,611		)
Construction Work in Progress	537			471
Nuclear Fuel, Net of Accumulated Amortization	182			208
Goodwill, net of writedown of $230	210			210
Utility Plant, Net	10,882			10,648
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $140 and $133	269			270
Assets held in trust, net-nuclear decommissioning	139			136
Other investments	135			68
Nonutility Property and Investments, Net	543			474
Current Assets:
Cash and cash equivalents	462			409
Receivables:
Customer, net of allowance for uncollectible accounts of $4 and $6	474			665
Income taxes	—			198
Other	75			105
Inventories (at average cost):
Fuel and gas supply	123			143
Materials and supplies	166			161
Prepayments	108			99
Derivative financial instruments	—			54
Other current assets	12			17
Total Current Assets	1,420			1,851
Deferred Debits and Other Assets:
Regulatory assets	5,739			5,580
Other	232			186
Total Deferred Debits and Other Assets	5,971			5,766
Total	$	18,816		$	18,739

See Notes to Condensed Consolidated Financial Statements.

7

Millions of dollars	September 30, 2018			December 31, 2017
Capitalization and Liabilities
Common Stock - no par value, 143 million shares outstanding	$	2,389		$	2,390
Retained Earnings	3,036			2,915
Accumulated Other Comprehensive Loss	(34		)	(50		)
Total Common Equity	5,391			5,255
Long-Term Debt, net	6,735			5,906
Total Capitalization	12,126			11,161
Current Liabilities:
Short-term borrowings	314			350
Current portion of long-term debt	18			727
Accounts payable	263			438
Customer deposits and customer prepayments	146			112
Revenue subject to refund	61			—
Taxes accrued	179			214
Interest accrued	90			87
Dividends declared	18			86
Derivative financial instruments	3			6
Other	72			93
Total Current Liabilities	1,164			2,113
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,355			1,261
Asset retirement obligations	579			568
Pension and other postretirement benefits	347			360
Unrecognized tax benefits	19			19
Regulatory liabilities	3,040			3,059
Other	186			198
Total Deferred Credits and Other Liabilities	5,526			5,465
Commitments and Contingencies (Note 10)
Total	$	18,816		$	18,739

See Notes to Condensed Consolidated Financial Statements.

8

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Income

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Millions of dollars, except per share amounts	2018			2017			2018			2017
Operating Revenues:
Electric	$	669		$	786		$	1,767		$	2,042
Gas - regulated	122			123			631			584
Gas - nonregulated	135			167			550			623
Total Operating Revenues	926			1,076			2,948			3,249
Operating Expenses:
Fuel used in electric generation	188			167			503			464
Purchased power	10			22			77			54
Gas purchased for resale	177			211			774			808
Other operation and maintenance	201			181			610			535
Impairment loss	—			210			4			210
Depreciation and amortization	100			96			299			285
Other taxes	67			67			206			200
Total Operating Expenses	743			954			2,473			2,556
Operating Income	183			122			475			693
Other Income, net	3			19			136			45
Interest charges, net of allowance for borrowed funds used during construction of $3, $2, $9 and $16	(99		)	(95		)	(292		)	(270		)
Income Before Income Tax Expense	87			46			319			468
Income Tax Expense	20			12			75			142
Net Income	$	67		$	34		$	244		$	326
Earnings Per Share of Common Stock	$	0.47		$	0.24		$	1.71		$	2.28
Weighted Average Common Shares Outstanding (millions)	143			143			143			143
Dividends Declared Per Share of Common Stock	$	0.1237		$	0.6125		$	0.8599		$	1.8375

See Notes to Condensed Consolidated Financial Statements.

9

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income

(Unaudited) 

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of dollars	2018		2017		2018		2017
Net Income	$	67	$	34	$	244	$	326
Other Comprehensive Income (Loss), net of tax:
Unrealized Gains (Losses) on Cash Flow Hedging Activities:
Arising during period, net of tax of $-, $-, $1, and $(3)	1		—		5		(5		)
Reclassified as increase to interest expense, net of tax of $1, $1, $2, and $3	3		2		7		6
Reclassified as increase (decrease) to gas purchased for resale, net of tax of $-, $-, $1 and $(1)	—		—		2		(2		)
Net unrealized gains (losses) on cash flow hedging activities	4		2		14		(1		)
Deferred cost of employee benefit plans, net of tax of $-, $-, $-, and $-	1		1		2		1
Other Comprehensive Income	5		3		16		—
Total Comprehensive Income	$	72	$	37	$	260	$	326

See Notes to Condensed Consolidated Financial Statements.

10

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited) 

	Nine Months Ended September 30,
Millions of dollars	2018			2017
Cash Flows From Operating Activities:
Net income	$	244		$	326
Adjustments to reconcile net income to net cash provided from operating activities:
Impairment loss	4			210
Deferred income taxes, net	89			(395		)
Depreciation and amortization	327			302
Amortization of nuclear fuel	41			31
Allowance for equity funds used during construction	(12		)	(17		)
Carrying cost recovery	(4		)	(27		)
Changes in certain assets and liabilities:
Receivables	207			79
Income taxes receivable	198			136
Inventories	(40		)	(58		)
Prepayments	(5		)	(6		)
Regulatory assets	(10		)	(48		)
Regulatory liabilities	(95		)	(3		)
Accounts payable	(53		)	(22		)
Revenue subject to refund	61			—
Unrecognized tax benefits	—			183
Taxes accrued	(35		)	325
Derivative financial instruments	(2		)	(3		)
Other assets	(69		)	(37		)
Other liabilities	12			(49		)
Net Cash Provided From Operating Activities	858			927
Cash Flows From Investing Activities:
Property additions and construction expenditures	(743		)	(1,095		)
Proceeds from monetization of guaranty settlement	—			1,013
Proceeds from investments and sales of assets (including derivative collateral returned)	87			116
Purchase of investments (including derivative collateral posted)	(144		)	(115		)
Proceeds upon interest rate derivative contract settlements	115			—
Net Cash Used For Investing Activities	(685		)	(81		)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	935			150
Repayment of long-term debt	(828		)	(16		)
Dividends	(191		)	(258		)
Short-term borrowings, net	(36		)	81
Net Cash Used For Financing Activities	(120		)	(43		)
Net Increase In Cash and Cash Equivalents	53			803
Cash and Cash Equivalents, January 1	409			208
Cash and Cash Equivalents, September 30	$	462		$	1,011
Supplemental Cash Flow Information:
Cash for–Interest paid (net of capitalized interest of $9 and $16)	$	270		$	247
–Income taxes paid	3			1
–Income taxes received	206			123
Noncash Investing and Financing Activities:
Accrued construction expenditures	49			44
Capital leases	9			6
Guaranty settlement receivable	—			83

See Notes to Condensed Consolidated Financial Statements.

11

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Changes in Common Equity

(Unaudited)

	Common Stock									Accumulated Other Comprehensive Income (Loss)
Millions	Shares	Outstanding Amount		Treasury Amount			Retained Earnings			Gains (Losses) from Cash Flow Hedges			Deferred Employee Benefit Plans			Total AOCI			Total
Balance as of January 1, 2018	143	$	2,402	$	(12	)	$	2,915		$	(37	)	$	(13	)	$	(50	)	$	5,255
Net Income							169												169
Other Comprehensive Income
Gains arising during the period										3			—			3			3
Losses/amortization reclassified from AOCI										4			1			5			5
Total Comprehensive Income							169			7			1			8			177
Purchase of Treasury Stock				(1		)													(1		)
Dividends Declared ($0.6125 per share)							(87		)										(87		)
Balance as of March 31, 2018	143	$	2,402	$	(13	)	$	2,997		$	(30	)	$	(12	)	$	(42	)	$	5,344
Net Income							8												8
Other Comprehensive Income
Gains arising during the period										1			—			1			1
Losses/amortization reclassified from AOCI										2			—			2			2
Total Comprehensive Income							8			3			—			3			11
Dividends Declared ($0.1237 per share)							(18		)										(18		)
Balance as of June 30, 2018	143	$	2,402	$	(13	)	$	2,987		$	(27	)	$	(12	)	$	(39	)	$	5,337
Net Income							67												67
Other Comprehensive Income
Gains arising during the period										1			—			1			1
Losses/amortization reclassified from AOCI										3			1			4			4
Total Comprehensive Income							67			4			1			5			72
Dividends Declared ($0.1237 per share)							(18		)										(18		)
Balance as of September 30, 2018	143	$	2,402	$	(13	)	$	3,036		$	(23	)	$	(11	)	$	(34	)	$	5,391
Balance as of January 1, 2017	143	$	2,402	$	(12	)	$	3,384		$	(36	)	$	(13	)	$	(49	)	$	5,725
Net Income							171												171
Other Comprehensive Income (Loss)
Losses arising during the period										(2		)	—			(2		)	(2		)
Total Comprehensive Income							171			(2		)	—			(2		)	169
Purchase of Treasury Stock				(1		)													(1		)
Dividends Declared ($0.6125 per share)							(87		)										(87		)
Balance as of March 31, 2017	143	$	2,402	$	(13	)	$	3,468		$	(38	)	$	(13	)	$	(51	)	$	5,806
Net Income							121												121
Other Comprehensive Income (Loss)
Losses arising during the period										(3		)	—			(3		)	(3		)
Losses/amortization reclassified from AOCI										2			—			2			2
Total Comprehensive Income							121			(1		)	—			(1		)	120
Dividends Declared ($0.6125 per share)							(88		)										(88		)
Balance as of June 30, 2017	143	$	2,402	$	(13	)	$	3,501		$	(39	)	$	(13	)	$	(52	)	$	5,838
Net Income							34												34
Other Comprehensive Income
Losses/amortization reclassified from AOCI										2			1			3			3
Total Comprehensive Income							34			2			1			3			37
Dividends Declared ($0.6125 per share)							(88		)										(88		)
Balance as of September 30, 2017	143	$	2,402	$	(13	)	$	3,447		$	(37	)	$	(12	)	$	(49	)	$	5,787

See Notes to Condensed Consolidated Financial Statements.

12

South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Balance Sheets

(Unaudited)

Millions of dollars	September 30, 2018			December 31, 2017
Assets
Utility Plant In Service	$	12,716		$	12,161
Accumulated Depreciation and Amortization	(4,541		)	(4,124		)
Construction Work in Progress	333			375
Nuclear Fuel, Net of Accumulated Amortization	182			208
Utility Plant, Net ($677 and $711 related to VIEs)	8,690			8,620
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	73			71
Assets held in trust, net-nuclear decommissioning	139			136
Other investments	1			2
Nonutility Property and Investments, Net	213			209
Current Assets:
Cash and cash equivalents	439			395
Receivables:
Customer, net of allowance for uncollectible accounts of $3 and $4	357			390
Affiliated companies	186			32
Income taxes	—			198
Other	54			85
Inventories (at average cost):
Fuel	64			90
Materials and supplies	155			149
Prepayments	95			82
Derivative financial instrument	—			54
Other current assets	2			2
Total Current Assets ($74 and $191 related to VIEs)	1,352			1,477
Deferred Debits and Other Assets:
Regulatory assets	5,623			5,476
Other	180			164
Other affiliate	71			—
Total Deferred Debits and Other Assets ($34 and $50 related to VIEs)	5,874			5,640
Total	$	16,129		$	15,946

See Notes to Condensed Consolidated Financial Statements.

13

Millions of dollars	September 30, 2018			December 31, 2017
Capitalization and Liabilities
Common Stock - no par value, 40.3 million shares outstanding	$	2,860		$	2,860
Retained Earnings	2,146			1,982
Accumulated Other Comprehensive Loss	(3		)	(4		)
Total Common Equity	5,003			4,838
Noncontrolling Interest	169			142
Total Equity	5,172			4,980
Long-Term Debt, net	5,132			4,441
Total Capitalization	10,304			9,421
Current Liabilities:
Short-term borrowings	173			252
Current portion of long-term debt	14			723
Accounts payable	136			251
Affiliated payables	259			102
Customer deposits and customer prepayments	117			70
Revenue subject to refund	61			—
Taxes accrued	169			208
Interest accrued	64			67
Dividends declared	9			82
Derivative financial instruments	1			2
Other	34			47
Total Current Liabilities	1,037			1,804
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,266			1,173
Asset retirement obligations	539			529
Pension and other postretirement benefits	207			217
Unrecognized tax benefits	19			19
Regulatory liabilities	2,635			2,667
Other	104			97
Other affiliate	18			19
Total Deferred Credits and Other Liabilities	4,788			4,721
Commitments and Contingencies (Note 10)
Total	$	16,129		$	15,946

See Notes to Condensed Consolidated Financial Statements.

14

South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Statements of Comprehensive Income

(Unaudited) 

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Millions of dollars	2018			2017			2018			2017
Operating Revenues:
Electric	$	669		$	786		$	1,767		$	2,042
Electric - nonconsolidated affiliate	1			1			3			4
Gas	69			69			303			284
Gas - nonconsolidated affiliate	—			—			1			1
Total Operating Revenues	739			856			2,074			2,331
Operating Expenses:
Fuel used in electric generation	153			132			408			370
Fuel used in electric generation - nonconsolidated affiliate	35			35			95			94
Purchased power	10			22			77			54
Gas purchased for resale	41			39			161			147
Other operation and maintenance	105			109			320			305
Other operation and maintenance - nonconsolidated affiliate	39			44			135			135
Impairment loss	—			210			4			210
Depreciation and amortization	81			78			242			232
Other taxes	61			62			188			183
Other taxes - nonconsolidated affiliate	2			1			4			4
Total Operating Expenses	527			732			1,634			1,734
Operating Income	212			124			440			597
Other Income (Expense), net	(1		)	11			124			26
Interest charges, net of allowance for borrowed funds used during construction of $2, $2, $7 and $15	(79		)	(76		)	(232		)	(214		)
Income Before Income Tax Expense	132			59			332			409
Income Tax Expense	29			17			70			129
Net Income	103			42			262			280
Other Comprehensive Income
Deferred cost of employee benefit plans, net of tax of $-, $-, $- and $-	1			—			1			—
Total Comprehensive Income	104			42			263			280
Less Comprehensive Income Attributable to Noncontrolling Interest	6			3			15			10
Comprehensive Income Available to Common Shareholder	$	98		$	39		$	248		$	270
Dividends Declared on Common Stock	$	17		$	81		$	91		$	240

See Notes to Condensed Consolidated Financial Statements.

15

South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended September 30,
Millions of dollars	2018			2017
Cash Flows From Operating Activities:
Net income	$	262		$	280
Adjustments to reconcile net income to net cash provided from operating activities:
Impairment loss	4			210
Deferred income taxes, net	93			(434		)
Depreciation and amortization	259			238
Amortization of nuclear fuel	41			31
Allowance for equity funds used during construction	(7		)	(13		)
Carrying cost recovery	(4		)	(27		)
Changes in certain assets and liabilities:
Receivables	49			(27		)
Receivables - affiliate	(4		)	8
Income tax receivable	198			53
Inventories	(15		)	(34		)
Prepayments	(13		)	(10		)
Regulatory assets	2			(40		)
Regulatory liabilities	(102		)	(1		)
Accounts payable	(10		)	31
Accounts payable - affiliate	—			(28		)
Revenue subject to refund	61			—
Taxes accrued	(39		)	468
Unrecognized tax benefit	—			166
Other assets	(44		)	(29		)
Other liabilities	38			(14		)
Net Cash Provided From Operating Activities	769			828
Cash Flows From Investing Activities:
Property additions and construction expenditures	(538		)	(882		)
Proceeds from monetization of guaranty settlement	—			1,013
Proceeds from investments and sales of assets (including derivative collateral returned)	35			96
Purchase of investments (including derivative collateral posted)	(21		)	(98		)
Purchase of investments - affiliate	(113		)	—
Proceeds from interest rate derivative contract settlement	115			—
Proceeds from investments - affiliate	42			—
Investment in affiliate	(150		)	—
Net Cash Provided From (Used For) Investing Activities	(630		)	129
Cash Flows From Financing Activities:
Proceeds from issuance of debt	795			—
Repayment of long-term debt	(824		)	(11		)
Dividends	(164		)	(238		)
Money pool borrowings, net	157			2
Contribution from parent	20			—
Short-term borrowings, net	(79		)	141
Net Cash Used For Financing Activities	(95		)	(106		)
Net Increase In Cash and Cash Equivalents	44			851
Cash and Cash Equivalents, January 1	395			164
Cash and Cash Equivalents, September 30	$	439		$	1,015
Supplemental Cash Flow Information:
Cash for–Interest (net of capitalized interest of $7 and $15)	$	211		$	195
–Income taxes paid	3			3
–Income taxes received	216			143
Noncash Investing and Financing Activities:
Accrued construction expenditures	25			21
Capital leases	7			6
Guaranty settlement receivable	—			83

See Notes to Condensed Consolidated Financial Statements.

16

South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Statements of Changes in Common Equity

(Unaudited)

	Common Stock
Millions	Shares	Amount		Retained Earnings			AOCI			Noncontrolling Interest			Total Equity
Balance at January 1, 2018	40	$	2,860	$	1,982		$	(4	)	$	142		$	4,980
Earnings available to common shareholder				124						4			128
Total Comprehensive Income				124			—			4			128
Cash dividend declared				(72		)				(2		)	(74		)
Balance at March 31, 2018	40	2,860		2,034			(4		)	144			5,034
Earnings available to common shareholder				26						5			31
Total Comprehensive Income				26			—			5			31
Contribution from Parent										20			20
Balance at June 30, 2018	40	2,860		2,060			(4		)	169			5,085
Earnings available to common shareholder				97			—			6			103
Deferred Cost of Employee Benefit Plans, net of tax $-							1						1
Total Comprehensive Income				97			1			6			104
Cash dividend declared				(11		)				(6		)	(17		)
Balance at September 30, 2018	40	$	2,860	$	2,146		$	(3	)	$	169		$	5,172
Balance at January 1, 2017	40	$	2,860	$	2,481		$	(3	)	$	134		$	5,472
Earnings available to common shareholder				109						3			112
Total Comprehensive Income				109			—			3			112
Cash dividend declared				(77		)				(2		)	(79		)
Balance at March 31, 2017	40	2,860		2,513			(3		)	135			5,505
Earnings available to common shareholder				122						4			126
Total Comprehensive Income				122			—			4			126
Cash dividend declared				(78		)				(3		)	(81		)
Balance at June 30, 2017	40	2,860		2,557			(3		)	136			5,550
Earnings available to common shareholder				39						3			42
Total Comprehensive Income				39			—			3			42
Cash dividend declared				(78		)				(2		)	(80		)
Balance at September 30, 2017	40	$	2,860	$	2,518		$	(3	)	$	137		$	5,512

See Notes to Condensed Consolidated Financial Statements.

17

SCANA Corporation and Subsidiaries

South Carolina Electric & Gas Company and Affiliates

Notes to Condensed Consolidated Financial Statements

(Unaudited)

The following unaudited notes to the condensed 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).

The following condensed notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in each company's Annual Report on Form 10-K for the year ended December 31, 2017, which also were a combined presentation. These are interim financial statements and, due to the seasonality of each company's business and matters that may occur during the rest of the year, including the matters described in Note 10 under Impairment Considerations, the amounts reported in the Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Comprehensive Income are not necessarily indicative of amounts expected for the full year.  In the opinion of management of the respective companies, the information furnished herein reflects all adjustments which are necessary for a fair statement of the results for the interim periods reported, and such adjustments are of a normal recurring nature. In addition, 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.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation and Variable Interest Entities

     The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed 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 condensed 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 $495 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.

Income Statement 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 11) are presented within Operating Income, and other activities are presented within Other Income (Expense).

Asset Management and Supply Service Agreement

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, 45% and 39% of PSNC Energy’s natural gas inventory at September 30, 2018 and December 31, 2017, respectively, with a carrying value of $14.3 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 expires on March 31, 2019.

18

Earnings Per Share

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

Reclassifications

In the statement of operations, amounts reported for 2017 under the captions “Other income,” “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net.” Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated.

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.

• In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company adopted this guidance on January 1, 2018.

• Effective January 1, 2018, the Company and Consolidated SCE&G adopted new accounting guidance for revenue arising from contracts with customers. This guidance 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 are 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.

• Effective January 1, 2018, the Company and Consolidated SCE&G adopted accounting guidance that changed the required presentation of net periodic pension and postretirement benefit costs. As a result, net periodic pension and postretirement benefit costs have been separated into their 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 during the period. Non-service cost components are now excluded from operating income. This guidance has been applied on a retrospective basis for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017.

Increase (Decrease) Millions of dollars	The Company						Consolidated SCE&G
September 30, 2017	Three Months Ended			Nine Months Ended			Three Months Ended			Nine Months Ended
Other operation and maintenance	$	(2	)	$	(8	)	$	(1	)	$	(6	)
Total Operating Expenses	(2		)	(8		)	(1		)	(6		)
Operating Income	2			8			1			6
Other Income (Expense), Net	(2		)	(8		)	(1		)	(6		)

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, and the adoption of this guidance did not result in a material impact on the Company’s and Consolidated SCE&G’s respective financial statements. Amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets.

19

• 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 accounting guidance related to the recognition, measurement and presentation of leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further,

depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. In the first quarter of 2018, FASB amended this accounting guidance to clarify that land easements are within the scope of the new guidance and to provide an optional transition practical expedient, that the Company and Consolidated SCE&G intend to adopt, that allows adopters to not evaluate under the new guidance existing or expired land easements that were not previously accounted for as leases. FASB also approved a new transition option in the first quarter of 2018, that the Company and Consolidated SCE&G intend to adopt, that will allow the new standard to be adopted without revising comparative period reporting or disclosures. The new guidance is effective for years beginning in 2019, and the Company and Consolidated SCE&G do not anticipate that its adoption will have a material impact on their respective financial statements other than increasing amounts reported for assets and liabilities on the balance sheet and changing the location on their respective statements of operations where certain expenses are recorded. No impact on net income is expected. The identification and analysis of leasing and related contracts to which the guidance will apply continues. In addition, the Company and Consolidated SCE&G are implementing a third party software tool to assist with initial adoption and ongoing compliance. System configuration has been completed and data input for financing leases is underway.

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. 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 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 expect to 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

20

or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2019 and do not expect it to have any impact 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 the NCUC have sought information from utilities under their respective jurisdictions that would disclose the impact of the Tax Act on their individual company's operations and would propose procedures for changing customer rates to reflect those impacts. In addition, the SCPSC and NCUC have issued orders that require SCE&G and PSNC Energy to track and defer such impacts arising from customer rates in 2018 as subject to refund. See Gas - SCE&G below for a discussion of related SCPSC action. For electric rates, SCE&G expects the SCPSC will take further action on this matter in 2018 but cannot determine what form that action will take. PSNC Energy has been ordered by the NCUC to (1) propose adjustments to customer rates to reflect the reduction in the federal corporate tax rate, which adjustments, if approved by the NCUC, are expected to be made effective on or before January 1, 2019; (2) continue to defer as a regulatory liability such amounts arising from customer rates in 2018; and (3) continue to defer as a regulatory liability amounts arising from excess deferred income taxes, as further described below. The NCUC order requires the regulatory liability related to items (2) and (3) 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 income tax rate reflected in various riders for PSNC Energy will be addressed in its next annual rider proceedings.

As of September 30, 2018, SCE&G has recorded approximately $60.9 million as Revenue subject to refund and approximately $3.8 million as Regulatory liabilities on the condensed consolidated balance sheet for the Company and Consolidated SCE&G, and PSNC Energy has recorded approximately $10.1 million of such deferrals within Regulatory liabilities on the condensed consolidated balance sheet for the Company. These amounts include the accrual of estimated carrying costs. 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 regulations and will be amortized over the remaining lives of related property, and certain of these amounts will be amortized to the benefit of customers over a prescribed period as instructed by regulators.

Electric - BLRA and Joint Petition

On January 12, 2018, SCE&G and Dominion Energy filed with the SCPSC the Joint Petition for review and approval of a proposed business combination whereby SCANA would become a wholly-owned subsidiary of Dominion Energy. In the Joint Petition, approval of a customer benefits plan and a cost recovery plan for the Nuclear Project is also sought. Key provisions of this Joint Petition are summarized at Note 10. In September and October 2018, the SCPSC received public testimony on the Joint Petition and other Concurrent Dockets. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets regarding the merits of the Joint Petition and related issues. As noted below, the SCPSC is required by law to issue its order related to the Joint Petition no later than December 21, 2018.

On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA. Act 258 requires the SCPSC to order a reduction in 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%, or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On

21

July 2 and 3, 2018, the SCPSC issued orders implementing the rate reduction required by Act 258. The rates and retroactive credits required by Act 258 were put into effect in August 2018, with the retroactive credits for the second quarter being applied in August's billing cycles. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 also alters certain provisions previously applicable under the BLRA, including redefining the standard of care required by the BLRA 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.

On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented.

Electric - Cost of Fuel

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 SCE&G’s increase to certain environmental, avoided capacity and DER 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 the gains realized from the settlement of certain interest rate derivatives in early 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.

In August 2018, the SCPSC initiated its 2019 annual review of base rates for fuel costs. A public hearing on this matter is scheduled to begin April 3, 2019.

Electric - Other

On April 25, 2018, the SCPSC approved SCE&G's request to recover approximately $33.0 million of costs and net lost revenues associated with DSM Programs, along with an incentive to invest in such programs. Changes in rates became effective beginning with the first billing cycle of May 2018.

Gas - SCE&G

On October 10, 2018, the SCPSC approved an overall decrease of approximately $19.7 million, or 4.61%, to SCE&G's natural gas rates under the terms of the RSA including 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. This rate adjustment and rider will become effective with the first billing cycle of November 2018.

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. SCE&G’s annual PGA hearing for the 12-month period ending July 31, 2018, is scheduled for November 8, 2018.

Gas - PSNC Energy

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. In 2018, the NCUC has approved those applications for the incremental annual revenue requirements, as follows:

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Rates Effective	Incremental Increase
March 1, 2018	$14.7 million
September 1, 2018	$1.1 million

On October 4, 2018, Dominion Energy and SCANA filed a stipulation agreement with the Public Staff of the NCUC and an intervenor in the proposed merger between the two companies.  Among other things, in the event the merger closes, the stipulation agreement provides for (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. The NCUC conducted a hearing on the proposed merger in October 2018. The Company cannot predict the timing or the outcome of this matter.

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
Millions of dollars	September 30, 2018		December 31, 2017		September 30, 2018		December 31, 2017
Regulatory Assets:
Unrecovered Nuclear Project costs	$	4,140	$	3,976	$	4,140	$	3,976
AROs and related funding	448		434		423		410
Deferred employee benefit plan costs	282		305		254		273
Deferred losses on interest rate derivatives	446		456		446		456
Other unrecovered plant	96		105		96		105
DSM Programs	57		59		57		59
Pipeline integrity management costs	67		51		9		8
Environmental remediation costs	28		30		24		25
Deferred storm damage costs	29		24		29		24
Deferred transmission operating costs	11		—		11		—
Other	135		140		134		140
Total Regulatory Assets	$	5,739	$	5,580	$	5,623	$	5,476

Regulatory Liabilities:
Monetization of guaranty settlement	$	1,098	$	1,095	$	1,098	$	1,095
Accumulated deferred income taxes	1,075		1,076		916		914
Asset removal costs	775		757		539		527
Deferred gains on interest rate derivatives	77		131		77		131
Other	15		—		5		—
Total Regulatory Liabilities	$	3,040	$	3,059	$	2,635	$	2,667

Regulatory assets for unrecovered Nuclear Project costs have been recorded based on such amounts 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, but are not limited to, certain costs which have not been specifically approved for recovery by one of these regulatory agencies, including unrecovered nuclear project costs and deferred transmission operating costs that are the subject of regulatory proceedings as further discussed above and in Note 10. 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

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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 as a result of the decision to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs under the abandonment provisions of the BLRA or through other regulatory means, net of an estimated impairment loss and net of the cost of certain assets that have been or will be placed in service. See also Note 10.

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 107 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. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065.

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 currently being recovered over approximately five years through an approved rate rider. 

Pipeline integrity management costs represent operating costs incurred 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 September 30, 2018 costs of $44.9 million have been deferred pending future approval of rate recovery. SCE&G amortizes $1.9 million of such costs 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 17 years, and PSNC Energy's remediation costs of $4.2 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 includes deferred depreciation and property taxes associated with certain transmission assets for which SCE&G expects recovery from customers through future rates. See also Note 10.

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. The SCPSC is expected to determine how SCE&G's customers will realize the value of these proceeds in connection with its consideration of the Request by the ORS and the Joint Petition (see above and Note 10).

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Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act (certain of which are protected under normalization regulations and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over a prescribed period 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.

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.

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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 12). Such revenues are outside the scope of revenues from contracts with customers.

Non-operating revenues are further described in Note 12. 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, such as 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.

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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				Gas-nonregulated
Millions of dollars	Electric		Gas-regulated		Gas-regulated		Total  Gas-regulated
Three months ended September 30, 2018
Customer class:
Residential	$	310	$	25	$	27	$	52	$	22
Commercial	231		19		19		38		14
Industrial	95		19		—		19		93
Other	31		6		7		13		6
Revenues from contracts with customers	667		69		53		122		135
Other operating revenues	3		—		—		—		—
Total Operating Revenues	$	670	$	69	$	53	$	122	$	135
Nine months ended September 30, 2018
Customer class:
Residential	$	805	$	145	$	210	$	355	$	158
Commercial	571		80		85		165		64
Industrial	286		64		10		74		304
Other	99		13		22		35		24
Revenues from contracts with customers	1,761		302		327		629		550
Other operating revenues	9		1		1		2		—
Total Operating Revenues	$	1,770	$	303	$	328	$	631	$	550

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 condensed 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.

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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	(1.1		)
Impairment	—
September 30, 2018	$	15.2

4.    COMMON EQUITY

SCANA shareholders approved the Merger Agreement at a special meeting on July 31, 2018. Certain regulatory approvals must be obtained and other conditions must be met before the merger may be consummated.

SCANA had 200 million shares of common stock authorized as of September 30, 2018 and December 31, 2017.

Authorized shares of SCE&G common stock were 50 million as of September 30, 2018 and December 31, 2017. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were issued and outstanding as of September 30, 2018 and December 31, 2017. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA.

In June 2018, SCANA made an equity contribution to GENCO of $20 million.

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. SCANA has agreed to obtain the consent of Dominion Energy, which consent cannot be unreasonably withheld, prior to making dividend payments to shareholders greater than $0.6125 per share for any quarter while the Merger Agreement is pending.

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 September 30, 2018 and 2017, retained earnings of approximately $99.9 million and $83.9 million, respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

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 September 30, 2018, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million.

5.     LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In June 2018, GENCO redeemed at maturity $160 million of 6.06% secured notes. The repayment was funded using a combination of utility 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 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.

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

Liquidity

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. Committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Committed LOC, outstanding LOC advances, commercial paper, and LOC-supported letter of credit obligations were as follows: 

September 30, 2018 (Millions of dollars)	Total		SCANA			Consolidated SCE&G			PSNC  Energy
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
LOC advances	40.0		40.0			—			—
Weighted average interest rate			3.78		%	—			—
Outstanding commercial paper (270 or fewer days)	314.2		3.7			173.2			137.3
Weighted average interest rate			3.20		%	3.21		%	3.13		%
Letters of credit supported by LOC	37.6		37.3			0.3			—
Available	$	1,608.2	$	319.0		$	1,226.5		$	62.7

December 31, 2017 (Millions of dollars)	Total		SCANA		Consolidated SCE&G			PSNC  Energy
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

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.

In September 2018, SCANA borrowed $40 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at September 30, 2018 was 3.78%, and this draw is classified as long-term debt. Proceeds from the draw were deposited with two natural gas suppliers to provide contractually required credit support, and this deposit is reflected within other assets on the condensed consolidated balance sheet.

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

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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 ongoing proceedings involving the ORS and Act 258, as well as the pending 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.

Proceeds received under or arising from the monetization of the Toshiba Settlement in 2017 have been utilized to repay maturing commercial paper balances, which short-term borrowings had been incurred primarily for the construction of Unit 2 and Unit 3 prior to the decision to stop their construction (see Note 10). Should the SCPSC or a court direct that these proceeds be refunded to customers in the near-term, or direct that such funds be escrowed or otherwise made unavailable to SCE&G, it is anticipated that SCE&G would issue commercial paper, draw on its credit facilities or issue long-term debt or the Company would issue equity to fund such requirement. However, if the SCPSC were to rule in favor of the ORS in response to the Request that SCE&G suspend collections from customers of amounts previously authorized under the BLRA, if the temporary rate reduction arising from the implementation of Act 258 were to remain in effect following the order of the SCPSC arising from the Joint Petition, or were other actions of the SCPSC or others taken in order to significantly restrict SCE&G’s access to revenues or impose additional adverse refund obligations on SCE&G, the Company’s and Consolidated SCE&G's assessments regarding the recoverability of all or a portion of the remaining balance of unrecovered Nuclear Project costs would be adversely impacted (see Note 2 and Note 10). Further, the recognition of significant additional impairment losses with respect to unrecovered Nuclear Project costs could increase the Company’s and Consolidated SCE&G’s debt to total capitalization to a level which may limit their ability to borrow under their commercial paper programs or under their credit facilities. Borrowing costs for long-term debt issuances could also be impacted.

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. These 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 three and nine months ended September 30, 2018, Consolidated SCE&G recorded interest income from money pool transactions of $1.1 million and $2.5 million, respectively, and for the same periods Consolidated SCE&G recorded interest expense from money pool transactions of $1.1 million and $2.5 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 $195 million and investments due from an affiliate of $177 million at September 30, 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 condensed consolidated balance sheet, Consolidated SCE&G includes money pool borrowings within Affiliated payables and money pool investments within Affiliated companies receivables.

6.    INCOME TAXES

The Company files consolidated federal income tax returns which include Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns.

The Company’s federal returns through 2007 are closed by statute. In addition, federal returns for 2008 and 2009 are closed except to the extent of the examination of amended return claims discussed below. Federal returns for years 2010 through 2017 are currently being examined as noted 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.

During 2013 and 2014, the Company amended certain of its income tax returns for 2008 through 2012 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, 2017 and 2018, 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,

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2016 and 2017 income tax returns. 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 2008-2012 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 are 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 are recorded as unrecognized tax benefits in the financial statements. Also, 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, would instead be expected to be deductible in 2017 under IRC Section 165. The abandonment loss deduction is also considered an uncertain tax position; however, under relevant accounting guidance, no estimated unrecognized tax benefits were recorded as of September 30, 2018. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, credits, and certain unrecognized state tax benefits.

As of September 30, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $98 million ($19 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, $98 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. These unrecognized tax benefits are not expected to increase significantly within the next 12 months. It is also 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 September 30, 2018 (see Note 10).

In connection with the research and experimentation deduction and credit claims reflected on the 2015, 2016 and 2017 income tax returns and under the provisions of an SCPSC order, the Company and Consolidated SCE&G recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, with the expectation that these deferred costs and related interest thereon would be recoverable through customer rates in future years. However, an impairment loss with respect to such deferred regulatory asset was recorded in 2017 (see Note 10).

Also under the provisions of an SCPSC order, estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 and 2016 income tax returns was deferred as a regulatory asset and was expected to be recoverable through customer rates in future years. An impairment loss with respect to these deferred amounts was also recorded as of December 31, 2017 (see Note 10). Otherwise, 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. Related to the unrecognized tax benefits noted above, the Company and Consolidated SCE&G accrued interest expense of $6.8 million and interest income of $1.4 million during 2018. Amounts recorded for such interest income and interest expense were mostly deferred within regulatory assets during 2017, and such deferred amounts were subsequently included within the impairment loss recorded by the Company and Consolidated SCE&G in 2017. Penalties were not material in either period presented.

In December of 2017, the Tax Act was enacted to lower the federal statutory corporate tax rate from 35% to 21%. The rate change resulted in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory corporate tax rate as of December 31, 2017. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in deferred income tax balances within regulatory liabilities. As of September 30, 2018, the amortization of amounts arising from remeasurement have not significantly affected the Company’s or Consolidated SCE&G’s effective tax rate for 2018 due to such amortization being deferred pending implementation of decisions by regulators prescribing how the benefits of such excess deferred tax amounts will be realized by customers. The Company filed a superseding 2017 consolidated income tax return on October 10, 2018. Adjustments to deferred income taxes resulting from the completion and filing of this return will be recorded in the fourth quarter of 2018 but are not expected to have a material impact on the Company’s or Consolidated SCE&G's financial position, results of operations, or cash flows.

The State of North Carolina lowered its corporate income tax rate to 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

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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.

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.  SCANA’s Board of Directors has 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 is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Board of Directors with regard to the management of risk and brings 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 that are designated as cash flow hedges may be 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 have not been 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 12 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 Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Gas Marketing	Total
As of September 30, 2018
Commodity contracts	7,050,000	16,856,000	23,906,000
Energy management contracts (a)	—	40,949,232	40,949,232
Total (a)	7,050,000	57,805,232	64,855,232
As of December 31, 2017
Commodity contracts	6,430,000	13,433,000	19,863,000
Energy management contracts (a)	—	41,856,890	41,856,890
Total (a)	6,430,000	55,289,890	61,719,890

(a)  Includes amounts related to basis swap contracts totaling 9,396,000 MMBTU in 2018 and 2,582,000 MMBTU 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	September 30, 2018		December 31, 2017		September 30, 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 September 30, 2018
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	2	—	$	1
	Other deferred credits and other liabilities	—		16		—	6
Commodity contracts	Prepayments	$	1	—		—	—
Total		$	1	$	18	—	$	7
Not designated as hedging instruments
Interest rate contracts	Other deferred credits and other liabilities	—		$	2	—	$	2
Commodity contracts	Prepayments	$	1	—		—	—
Energy management contracts	Prepayments	1		—		—	—
	Other current assets	1		—		—	—
	Other current liabilities	—		2		—	—
Total		$	3	$	4	—	$	2

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		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of December 31, 2017
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	3	—		$	1
	Other deferred credits and other liabilities	—		24		—		9
Commodity contracts	Prepayments	—		2		—		—
	Other current assets	—		1		—		—
Total		—		$	30	—		$	10
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	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		—		—		—
	Derivative financial instruments	—		2		—		—
Total		$	59	$	8	$	54	$	5

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

Derivatives in Cash Flow Hedging Relationships

The Company and Consolidated SCE&G:
	Gain (Loss) Deferred in Regulatory Accounts						(Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	—		—			Interest expense	—			—
Nine Months Ended September 30,
Interest rate contracts	$	2	$	(1	)	Interest expense	$	(1	)	$	(1	)

The Company:
	Gain (Loss) Recognized in OCI, net of tax						Gain (Loss) Reclassified from AOCI into Income, net of tax
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	$	1	—			Interest expense	$	(3	)	$	(2	)
Total	$	1	—				$	(3	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	3	$	(1	)	Interest expense	$	(7	)	$	(6	)
Commodity contracts	2		(4		)	Gas purchased for resale	(2		)	2
Total	$	5	$	(5	)		$	(9	)	$	(4	)

As of September 30, 2018, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $0.5 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.9 million as an increase to interest expense.  Reclassifications related to commodity and energy management contracts are not expected to be significant. As of September 30, 2018, all of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2021.

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As of September 30, 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 $1.0 million 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 during all periods presented.

Derivatives Not designated as Hedging Instruments
The Company and Consolidated SCE&G:
	Gain (Loss) Deferred in Regulatory Accounts						Gain (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	$	1	$	(6	)	Interest Expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	66	$	(30	)	Interest Expense	$	(2	)	$	(2	)
						Other Income	115			—

As of September 30, 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	September 30, 2018			December 31, 2017		September 30, 2018		December 31, 2017
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	20.8		$	33.7	$	8.7	$	14.7
Fair value of collateral already posted	22.3			28.9		8.7		10.1
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	(1.5	)	$	4.8	—		$	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, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of $0.3 million related to $2.9 million in commodity derivatives that are in a net asset position at September 30, 2018, compared to letters of credit in the amount of $1.2 million related to derivatives of $4.0 million at December 31, 2017, if all the contingent features underlying these instruments had been fully triggered.

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Information related to the offsetting of derivative assets and derivative liabilities 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 September 30, 2018
Gross Amounts of Recognized Assets	—		$	2	$	2	$	4	—
Gross Amounts Offset in Statement of Financial Position	—		—		—		—		—
Net Amounts Presented in Statement of Financial Position	—		2		2		4		—
Gross Amounts Not Offset - Financial Instruments	—		—		—		—		—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—		—		—
Net Amount	—		$	2	$	2	$	4	—
Balance sheet location
Prepayments							$	3	—
Other current assets							1		—
Total							$	4	—
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

Derivative Liabilities
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of September 30, 2018
Gross Amounts of Recognized Liabilities	$	20		—		$	2		$	22		$	9
Gross Amounts Offset in Statement of Financial Position	—			—		—			—			—
Net Amounts Presented in Statement of Financial Position	20			—		2			22			9
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(21		)	—		(1		)	(22		)	(9		)
Net Amount	$	(1	)	—		$	1		—			—
Balance sheet location
Derivative financial instruments									$	2		$	1
Other current liabilities									2			—
Other deferred credits and other liabilities									18			8
Total									$	22		$	9
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		)	27			—
Net Amount	$	60		$	3	$	1		$	64		$	15
Balance sheet location
Other current assets									$	2		—
Derivative financial instruments									7			$	2
Other deferred credits and other liabilities									28			13
Total									$	37		$	15

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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 September 30, 2018						As of December 31, 2017
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	15	—		—		$	119	—		$	100	—
Held to maturity securities	—		$	6	—		—		$	6	—		—
Interest rate contracts	—		—		—		—		54		—		$	54
Commodity contracts	2		—		—		1		—		—		—
Energy management contracts	—		2		—		—		4		—		—
Liabilities:
Interest rate contracts	—		20		$	9	—		32		—		15
Commodity contracts	—		—		—		2		1		—		—
Energy management contracts	—		4		—		1		4		—		—

The Company and Consolidated SCE&G had no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during either period presented.

Financial instruments for which the carrying amount may not equal estimated fair value were as follows:

Long-Term Debt	September 30, 2018				December 31, 2017
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,753.3	$	6,980.8	$	6,632.9	$	7,399.7
Consolidated SCE&G	5,145.2		5,295.2		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 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.

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9.    EMPLOYEE BENEFIT PLANS

Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows: 

The Company	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017
Three months ended September 30,
Service cost	$	5.9		$	5.7		$	1.1		$	1.0
Interest cost	8.5			9.2			2.2			2.8
Expected return on assets	(14.0		)	(13.4		)	—			—
Prior service cost amortization	0.1			0.4			—			—
Amortization of actuarial (gains) losses	3.7			4.4			(0.5		)	—
Net periodic benefit cost	$	4.2		$	6.3		$	2.8		$	3.8
Nine months ended September 30,
Service cost	$	15.8		$	16.3		$	3.4		$	3.4
Interest cost	25.6			28.0			7.6			8.6
Expected return on assets	(42.6		)	(41.0		)	—			—
Prior service cost amortization	0.4			1.2			—			—
Amortization of actuarial losses	9.6			12.2			0.6			0.8
Net periodic benefit cost	$	8.8		$	16.7		$	11.6		$	12.8

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017
Three months ended September 30,
Service cost	$	4.8		$	4.8		$	0.9		$	0.8
Interest cost	7.2			7.8			1.7			2.3
Expected return on assets	(11.8		)	(11.4		)	—			—
Prior service cost amortization	0.1			0.3			—			—
Amortization of actuarial (gains) losses	3.1			3.7			(0.4		)	—
Net periodic benefit cost	$	3.4		$	5.2		$	2.2		$	3.1
Nine months ended September 30,
Service cost	$	12.9		$	13.6		$	2.7		$	2.8
Interest cost	21.6			24.0			6.0			7.1
Expected return on assets	(36.0		)	(35.0		)	—			—
Prior service cost amortization	0.3			1.0			—			—
Amortization of actuarial losses	8.1			10.4			0.5			0.6
Net periodic benefit cost	$	6.9		$	14.0		$	9.2		$	10.5

No significant contribution to the pension trust is expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either 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.

10.    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. Various difficulties were encountered which affected the ability of the Consortium to adhere to established budgets and construction schedules for the Nuclear Project and which, in light of Santee Cooper's decision to suspend construction of the Nuclear Project, led to the Company's decision on July 31, 2017 to stop the construction and seek cost recovery under the abandonment provisions of the BLRA. These difficulties and other developments occurring prior to the bankruptcy filing by WEC and WECTEC and other matters are described in Note 10 to the consolidated financial statements included in the Company's and Consolidated SCE&G's combined Form 10-K for the year ended December 31, 2017. Significant developments and continuing contingencies and uncertainties regarding the abandoned Nuclear Project subsequent to December 31, 2017 are discussed below.

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EPC Contract and BLRA 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 assert against WEC and WECTEC any and all claims that are based thereon or that may be 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 $290 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 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.

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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 below. 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. The proceeds received under or arising from the monetization of the Toshiba Settlement are recorded as a regulatory liability on the accompanying condensed consolidated balance sheets, as the net value of the proceeds will be utilized to benefit SCE&G's customers in a manner to be determined by the SCPSC.

As described 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 the reduction. On January 2, 2018, the purchase agreement with Citibank was amended to limit the amount that SCE&G and Santee Cooper could be required to reimburse Citibank for valid subcontractor and vendor pre-petition liens to $60 million ($33 million for SCE&G's 55% share).

Regulatory, Political and Legal Developments

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

On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, and in reliance on the opinion from the Office of Attorney General, the ORS filed the Request seeking an order from the SCPSC directing SCE&G to immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS, which the ORS believes should have been disclosed, that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections. On October 17, 2017, the ORS filed a motion with the SCPSC to amend the Request, in which motion the ORS asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. See Claims and Litigation herein for additional discussions regarding regarding the constitutionality of the BLRA.

On December 20, 2017, the SCPSC denied a motion by SCE&G to dismiss the Request. Parties who have intervened in the Request or who filed a letter in support of it include the state's Governor, Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, Santee Cooper, the SCEUC, certain large industrial

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customers, and several environmental groups. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets, including the Request, regarding the merits of the Joint Petition and related issues. This schedule was established in response to legislation described below. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the outcome of this matter. See also Note 2.

In 2017, special committees of the South Carolina General Assembly, both in the House of Representatives and in the Senate, conducted public hearings regarding the Company's decision to abandon the Nuclear Project. Several legislative proposals adverse to the Company and Consolidated SCE&G resulted from the work of these committees, two of which became law in 2018 and are described below.

On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA. Act 258 requires the SCPSC to order a reduction in 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%, or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On July 2 and 3, 2018, the SCPSC issued orders implementing the temporary rate reduction required by Act 258. The resulting new rates and retroactive credits required by Act 258 were put into effect in August 2018, with the retroactive credits for the second quarter being applied in August's billing cycles. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 alters certain provisions previously applicable under the BLRA, including redefining the standard of care required by the BLRA 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.

On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented.

Proposals to Resolve Outstanding Issues

On November 16, 2017, SCE&G announced for public consideration a proposal to resolve outstanding issues relating to the Nuclear Project. Under the proposal, SCE&G electric customers were to receive a 3.5% electric rate reduction, the addition of an existing 540-MW natural gas fired power plant by SCE&G with the acquisition cost borne by SCANA shareholders, and the addition of approximately 100-MW of large scale solar energy by SCE&G. The proposal also provided for the recovery of the nuclear construction costs (net of the proceeds of the Toshiba Settlement not utilized for satisfaction of project liens) over 50 years. While SCE&G’s proposal was not formally submitted for regulatory approval at that time, discussions with key stakeholders over the ensuing weeks indicated that SCE&G's proposal would not be sufficient to resolve the outstanding issues.

On January 2, 2018, SCANA entered into the Merger Agreement with Dominion Energy, and on January 12, 2018, SCE&G and Dominion Energy filed the Joint Petition requesting SCPSC approval of the merger or a finding that either the merger is in the public interest or that there is an absence of harm arising from the merger. In this petition, the parties committed to providing an up-front, one time rate credit to SCE&G's electric customers totaling approximately $1.3 billion within 90 days of the merger's closing, providing at least a 5% reduction in customer bills (later adjusted to approximately 7% in light of the effects of the Tax Act), shortening the amortization period for costs related to the Nuclear Project to 20 years, forgoing recovery of approximately $1.7 billion in costs related to the Nuclear Project, and purchasing an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers.

On October 25, 2018, in response to the desire of various parties to the Concurrent Dockets for an alternative that would further reduce customer bills, Dominion Energy filed with the SCPSC the Alternative Customer Benefits Plan (Alternative Plan). The testimony filed by Dominion Energy in connection with the Alternative Plan indicates that customers

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would receive refunds totaling approximately $1.91 billion with approximately $1.0 billion being refunded evenly over 20 years and approximately $880 million credited to customers over approximately ten years instead of the up-front, one time rate credit of $1.3 billion originally proposed in the Joint Petition. In addition, such testimony indicates that approximately $2.3 billion in costs related to the Nuclear Project would not be recovered in connection with the Alternative Plan, instead of the $1.7 billion originally proposed. The parties to the Joint Petition estimate that these changes would result in customer bill reductions of approximately 14% (including the effects of the Tax Act). The Alternative Plan also contemplates the purchase of an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers.

The ORS has filed direct and rebuttal testimony and a pre-hearing brief related to the Concurrent Dockets. In these filings, the ORS has proposed (ORS Plan) that the SCPSC reduce SCE&G's electric rates during the 12 months following the effective date of its order by approximately $561 million compared to rates that would otherwise be in effect when the temporary rate reduction under Act 258 expires. This proposal includes reductions due to assumed merger synergies, the use of an ROE of 9.1% rather than 10.25% (which proposed ROE would be applied to a smaller rate base after all adjustments specified by the ORS), the ORS calculation of savings from the Tax Act (which exceeds SCE&G's calculation), the refund of amounts deferred as subject to refund that arise from the Tax Act and other adjustments. After 12 months (after amounts subject to refund have been returned to customers), the ORS proposes that SCE&G's electric rates be modified to an amount that would be approximately $528 million lower annually compared to rates that would otherwise be in effect when the temporary rate reduction under Act 258 expires.

On October 25, 2018, in testimony filed in connection with the Concurrent Dockets, a representative of Dominion Energy noted that (1) the ORS Plan, if adopted, would be devastating not only to the proposed merger but also to SCE&G's future and to the interests of SCE&G's customers and the state of South Carolina in reliable electric service at just and reasonable rates and (2) there is currently pending litigation in the South Carolina state courts in which the judge has indicated that he is considering issuing an order that would violate the "no change in law" provision of the Merger Agreement, and that if such an order were issued or the ORS Plan is adopted, the merger would be unable to close.

On October 26, 2018, Santee Cooper filed a pre-hearing brief with respect to the Joint Petition. In its filing, Santee Cooper requested that the SCPSC not approve a merger between SCANA and Dominion Energy as being in the public interest unless SCANA and Dominion Energy commit to creating a fund of approximately $351 million to mitigate the financial impact of the abandonment of the Nuclear Project on Santee Cooper's wholesale and retail customers. Santee Cooper proposes that the cost of creating such a fund should not be recoverable from SCE&G's customers.

On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets regarding the merits of the Joint Petition and related issues, and as noted above, pursuant to S. 954 the SCPSC is required to issue an order related to the Joint Petition no later than December 21, 2018. No assurance can be given as to the timing or outcome of efforts to consummate the Merger Agreement or to obtain approval of the Joint Petition.

On May 9, 2018, SCE&G completed its purchase of CEC, the existing 540-MW natural gas fired power plant referred to above, for approximately $180 million. As disclosed in Note 10 to the Company's and Consolidated SCE&G's Form 10-K for December 31, 2017, an impairment loss recorded in the fourth quarter of 2017 included $180 million related to SCE&G's commitment to not seek recovery from customers for the acquisition cost of this natural gas fired power plant, and accordingly, this amount was recorded as a reduction to unrecovered Nuclear Project costs within regulatory assets on the Company's and Consolidated SCE&G's consolidated balance sheets at December 31, 2017. As such, the Company's and Consolidated SCE&G's condensed consolidated balance sheet as of September 30, 2018 reflect the cost for CEC within Utility Plant in Service, and the $180 million impairment initially recorded as unrecovered Nuclear Project costs within regulatory assets is now reflected within Accumulated Depreciation and Amortization, which results in the carrying value of CEC being entirely written off. SCE&G’s commitment to not seek recovery from customers for the acquisition cost of CEC was one element of certain broader rate mitigation proposals contained within the Joint Petition and the Alternative Plan. Assuming that the SCPSC approves either of the mitigating proposals as outlined in the Joint Petition or approves the Alternative Plan, SCE&G will not seek recovery of CEC acquisition costs. 

Impairment Considerations

At September 30, 2018, SCE&G estimated that revised rates collections previously approved under the BLRA totaled approximately $445 million annually. SCE&G estimates that such revised rates collections for 2018 would be reduced by approximately $279 million if Act 258 remains in effect and is implemented through December 21, 2018, which is the expected pendency of the SCPSC proceeding with respect to the Joint Petition. New rates are expected to be ordered by the SCPSC in connection with its order on the Joint Petition, which order is to be issued no later than December 21, 2018. On a cumulative

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basis, at September 30, 2018, SCE&G estimated that revised rates collections previously approved under the BLRA totaled approximately $2.1 billion, which amount reflects the impacts of Act 258.

For each of the quarters ended June 30, 2018, September 30, 2018 and December 31, 2018, SCANA's Board of Directors declared a dividend of $0.1237 per share, which represents an approximately 80% reduction from the $0.6125 per share paid on SCANA’s common stock for the first quarter of 2018. This reduction corresponds to the portion of the dividend attributable to SCE&G's electric operations and serves to partially mitigate the liquidity impacts arising from the reduced revenues and cash flows resulting from the implementation of Act 258.

Under the current regulatory construct in South Carolina, pursuant to the BLRA or through other means, the ability of SCE&G to recover costs incurred in connection with Unit 2 and Unit 3, and a reasonable return on them, will be subject to review and approval by the SCPSC. In light of the contentious nature of activity involving the General Assembly and other officials and the Request being considered by the SCPSC that could result in the suspension of all rates currently being collected under the BLRA, as well as the return of such amounts previously collected, there is significant uncertainty as to SCE&G’s ultimate ability to recover its costs of Unit 2 and Unit 3 and a return on them from its customers. See also Claims and Litigation herein for additional discussion regarding the constitutionality of the BLRA. SCE&G continues to contest the specific challenges described above. However, based on the consideration of those challenges, and particularly in light of SCE&G's proposed solution announced on November 16, 2017 and details in the Joint Petition filed by SCE&G and Dominion Energy with the SCPSC on January 12, 2018, the Company and Consolidated SCE&G determined that a disallowance of recovery of part of the cost of the abandoned Nuclear Project is both probable and reasonably estimable under applicable accounting guidance. In addition, the Company and Consolidated SCE&G determined that full recovery of certain other related costs deferred within regulatory assets is less than probable. As a result, in 2017 the Company and Consolidated SCE&G recognized a pre-tax impairment loss totaling $1.118 billion ($690 million net of tax). Also, in the first quarter of 2018, the Company and Consolidated SCE&G recognized an additional pre-tax impairment loss of approximately $3.6 million ($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.

It is reasonably possible that a change in estimated impairment loss could occur in the near term and could be material; however, all such changes cannot be reasonably estimated. The impairment loss recorded in 2017 reflects impacts similar to those that would have resulted had the proposed solution announced on November 16, 2017 been implemented. If the merger benefits and cost recovery plan outlined in the Joint Petition are implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $1.7 billion (approximately $1.3 billion net of tax) would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $813 million recorded within regulatory assets, the write-off of unrecovered Nuclear Project costs of approximately $86 million recorded within Utility Plant, and the recording of additional liabilities for customer refunds totaling approximately $1.875 billion, net of approximately $1.065 billion, which amount represents the monetization of guaranty settlement recorded within regulatory liabilities less amounts that may be required to satisfy contractor liens.

If the Alternative Plan were implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $2.3 billion (approximately $1.7 billion net of tax) would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $1.368 billion recorded within regulatory assets, the write-off of unrecovered Nuclear Project costs of approximately $86 million recorded within Utility Plant, and the recording of additional liabilities for customer refunds of approximately $880 million. In addition, the Alternative Plan provides for the refunding of the existing regulatory liability associated with the monetization of guaranty settlement over 20 years less amounts that may be required to satisfy contractor liens.

If (i) the SCPSC does not approve the Joint Petition or the Alternative Plan and instead approves the Request by the ORS; (ii) the BLRA is found to be unconstitutional; or (iii) the General Assembly further amends or revokes the BLRA or approves other legislation with a similar effect, the Company and Consolidated SCE&G may be required to record an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $5.0 billion (approximately $3.7 billion net of tax). This additional impairment loss would result from the write-off of approximately $3.960 billion in regulatory assets (comprised of remaining unrecovered Nuclear Project costs of $4.140 billion offset by $180 million in previously impaired costs related to CEC, which would result from the proposals put forward in the Joint Petition or the Alternative Plan not being approved by the SCPSC) and the refund of revised rates collections under the BLRA described above of approximately $2.1 billion (comprised of the revised rates collections on a cumulative basis as of September 30, 2018 and reflective of the impacts of Act 258), net of approximately $1.065 billion, which amount represents the monetization of guaranty settlement recorded within regulatory liabilities less amounts that may be required to satisfy contractor liens. The

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Company and Consolidated SCE&G do not currently anticipate that any amounts collected prior to April 1, 2018, will be subject to refund (other than amounts arising from the effects of the Tax Act); however, no assurance can be given as to the outcome of this matter. See Claims and Litigation herein for additional discussion regarding the constitutionality of the BLRA.

At September 30, 2018, the Company and Consolidated SCE&G included considerations of the impact of Act 258 in the evaluation as to their ability to recover the remaining Nuclear Project costs and a reasonable return on those costs. Because Act 258 explicitly provides for an experimental rate that is temporary and does not disallow any of the costs currently deferred as a regulatory asset, and because the experimental rate is to be replaced by rates that the SCPSC is to determine and order no later than December 21, 2018, the Company and Consolidated SCE&G have concluded that additional impairment charges related to unrecovered Nuclear Project costs are not probable, and the recording of such charges would not be appropriate, at this time. However, if a disallowance were ordered or the rates under Act 258 were made other than temporary by the SCPSC in the Joint Petition proceeding, the Company and Consolidated SCE&G would reevaluate this conclusion. Were the rates under Act 258 made other than temporary following the SCPSC's final decision on the Joint Petition, and without consideration of any other factors that may be embodied in such an order, an additional pre-tax impairment charge totaling approximately $1.7 billion may be required.

In addition to the matters above, in the Joint Petition, the Company and Consolidated SCE&G proposed to remove from BLRA capital costs their investment in transmission assets that have been or will be placed in service and have not been abandoned. As of September 30, 2018, such investment in these assets total approximately $376 million (approximately $365 million within utility plant, net and approximately $11 million within regulatory assets, which amount represents certain deferred operating costs). The Company and Consolidated SCE&G believe that this investment represents assets that are or will be used to provide electric service to customers and that a recovery of and a reasonable return on the investment should be provided in future rates. During the hearing on the Concurrent Dockets, the SCPSC will consider a request by the ORS to allow the Company and Consolidated SCE&G to defer certain operating costs related to the investment and that a decision on the recovery of this investment, including operating costs deferrals, be addressed in a future rate proceeding. If the SCPSC were to disallow recovery of or a reasonable return on all or a portion of this investment, an impairment charge related to these assets totaling as much as approximately $376 million may be required.

Liquidity Considerations

              As a result of the legislative and regulatory reactions to the decision to stop construction of Unit 2 and Unit 3, downgrades by credit ratings agencies occurred.  The Company and Consolidated SCE&G have significant obligations that must be paid within the next 12 months, including long-term debt maturities and capital lease payments of $18 million for the Company (including $14 million for Consolidated SCE&G), short-term borrowings of $314 million for the Company (including $173 million for Consolidated SCE&G), interest payments of approximately $335 million for the Company (including $255 million for Consolidated SCE&G), future minimum payments for operating leases of $9 million for the Company (including $3 million for Consolidated SCE&G), and revenues collected subject to refund arising from the effects of the Tax Act of approximately $61 million for the Company and Consolidated SCE&G. Working capital requirements, such as those for fuel supply and similar obligations, also arise due to the lag between when such amounts are paid and when related collection of such costs through customer rates occurs. In addition, as described above under Impairment Considerations, SCE&G has been ordered to reduce revised rates previously approved under the BLRA by approximately $279 million in 2018. This reduction assumes that Act 258 remains in effect through December 21, 2018, which is the expected pendency of the SCPSC proceeding with respect to the Concurrent Dockets.

Also, any adverse final judgment by a court in any matter of litigation, or any levy for amounts assessed by a regulatory agency, including but not limited to matters described in Claims and Litigation below, could require the Company and/or Consolidated SCE&G to escrow funds or to post one or more bonds equal to the monetary amount of the judgment or assessment while the decision is being appealed or challenged.

              Management believes as of the date of issuance of these financial statements that it has access to available sources of cash to pay obligations when due over the next 12 months. These sources include committed, long-term lines of credit that expire in December 2020 totaling $1.8 billion for the Company (including $1.2 billion for Consolidated SCE&G). In addition, as of the date of issuance of these financial statements, SCE&G continues to collect the BLRA-related customer rates that remain after reductions ordered as a result of Act 258, as well as amounts provided for in other orders related to non-BLRA electric and gas rates. In 2018, however, certain of SCANA's credit ratings have fallen below investment grade, which has constrained its ability to issue commercial paper. The ability of Fuel Company and PSNC Energy to issue commercial paper has also been constrained.

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Regulatory and legislative proceedings described above, and/or proceedings described under Claims and Litigation below, which are outside of the Company’s and Consolidated SCE&G’s control, have resulted in the temporary suspension of a substantial portion of the approximately $445 million annually of rates that were being collected under the BLRA, and may result in the permanent suspension of all or a portion of such amounts, the return of such amounts collected through September 30, 2018, of $2.1 billion, or the requirement that SCE&G's share of payments received from the Toshiba Settlement ($1.098 billion) be placed in escrow or be refunded to customers in the near term. Neither the Company nor Consolidated SCE&G can predict if or when these matters may be resolved or what additional actions, if any, may be proposed or taken, including other legislative or regulatory actions related to the BLRA or other litigation.

Were the SCPSC to grant the relief sought by the ORS in the Request or grant similar relief resulting from legislative action, and as further discussed above in Impairment Considerations, an additional impairment loss or other charges totaling approximately $5.0 billion (approximately $3.7 billion net of tax) may be required. Such an impairment loss or other charges would further increase the Company’s and Consolidated SCE&G’s debt to total capitalization ratio and may result in the Company’s and Consolidated SCE&G’s ratio of debt to total capitalization exceeding maximum levels prescribed in their respective credit agreements. Such an event likely would limit the Company’s and Consolidated SCE&G’s ability to borrow under their commercial paper programs and credit facilities and their ability to pay future dividends or may trigger events of default under such agreements.

Known and knowable conditions and events when considered in the aggregate as of the date of issuance of these financial statements do not suggest it is probable that the Company and Consolidated SCE&G will not be able to meet obligations as they come due over the next 12 months. However, certain possible adverse future actions, including but not limited to those contemplated in the Request by the ORS regarding the disallowance of all or part of the remaining unrecovered nuclear regulatory asset, rate reductions and refunds, and including actions that may result from other legal, regulatory and governmental proceedings and investigations, could likely have a material adverse impact on the Company’s and Consolidated SCE&G’s financial condition, liquidity, results of operations and cash flows such that management’s conclusion with respect to its ability to pay obligations when due could change.

Claims and Litigation

Following the Company’s decision to stop construction of Unit 2 and Unit 3, purported derivative and class action lawsuits have been filed in multiple state circuit courts and federal district court on behalf of customers, shareholders and SCANA (in the case of the derivative shareholder actions), against SCANA, SCE&G, or both, and in certain cases some of their officers and/or directors. The plaintiffs allege various causes of action, including but not limited to waste, breach of fiduciary duty, negligence, unfair trade practices, unjust enrichment, conspiracy, fraud, constructive fraud, misrepresentation and negligent misrepresentation, promissory estoppel, constructive trust, and money had and received, among other causes of action. Plaintiffs generally seek compensatory and consequential damages and statutory treble damages and such further relief as the court deems just and proper. In addition, certain plaintiffs seek a declaration that SCE&G may not charge its customers to reimburse itself for past and continuing costs of the Nuclear Project. Certain plaintiffs also seek to freeze or appoint a receiver for certain of SCE&G’s assets, including all money SCE&G has received under the Toshiba payment guaranty and related settlement agreement and money to be collected from customers for the Nuclear Project.

On October 15, 2018, in an email to counsel of record in the customer class action, the state court judge provided instructions to counsel for the State of South Carolina and the plaintiffs to submit proposed orders to him.  Those instructions directed the attorneys to include language in the proposed orders stating, among other things, that the BLRA violates the hearing requirement of the procedural due process provisions Article I, Section 22 of the South Carolina Constitution.The proposed orders have been submitted to the judge by those attorneys, and SCANA and SCE&G have provided the judge with comments to various portions of the proposed orders.  In a later email to counsel dated October 22, 2018, the judge indicated that he was still considering his analysis of the applicable law, and he sought further input from all parties.  The judge made clear that his emails were not binding judicial orders but merely an indication of how the judge was then considering the matters he had taken under advisement. The judge has not yet entered an official, binding order, and he has not indicated when he intends to do so. The judge’s emails do not indicate what, if any, remedy is available tothe customer class action plaintiffs should he enter an order finding that the BLRA offers insufficient due process to meet the hearing requirement of Article I, Section 22 of the South Carolina Constitution.  SCANA and SCE&G will evaluate the court’s order when it is entered and, if it is adverse to SCANA and SCE&G, will determine whether to seek reconsideration or appeal.

Purported class action lawsuits have been filed on behalf of investors in federal court against SCANA and certain of its current and former executive officers and directors. The plaintiffs allege, among other things, that defendants violated Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder and RICO. The plaintiffs in each of these suits seek compensatory and consequential damages and such further relief as the court deems proper. The plaintiffs also allege, among

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other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that unfairly deprived plaintiffs of the true value of their SCANA stock, and that Dominion Energy and Sedona aided and abetted these actions. Among other remedies, the plaintiffs seek to enjoin the merger and rescind the Merger Agreement or to have the Merger Agreement amended to provide more favorable terms for plaintiffs, monetary damages, attorneys' fees and such further relief as the court deems proper.

Lawsuits seeking class action status have also been filed on behalf of investors and shareholder derivative actions have been filed in the Court of Common Pleas in the Counties of Lexington and Richland, South Carolina, against SCANA, its CEO and directors, Dominion Energy and Sedona. Following removal of certain of these class action lawsuits and shareholder derivative actions from state courts to federal court and their subsequent remand, Dominion Energy has filed appeals of the decisions to remand to the Court of Appeals, where the appeals have been consolidated and remain pending.

On July 13, 2018, SCANA’s Board of Directors elected two new, independent directors and exercised its right under South Carolina corporate law to form an SLC comprised solely of these newly elected members to investigate the Derivative Litigation and to determine SCANA’s best interests with respect to these actions. On July 24, 2018, SCANA, acting at the direction of the SLC, filed a motion to stay all federal court proceedings in the Derivative Litigation (In Re SCANA Corporation Derivative Litigation) to allow time for the SLC to conduct an independent investigation into the facts and circumstances giving rise to the Derivative Litigation, and to determine what course of action is in the best interests of SCANA and its shareholders with respect to the Derivative Litigation (e.g., prosecution of the claims in the name of SCANA, seeking dismissal of some or all of the claims, or taking other remedial actions). On October 31, 2018, the court denied the motion to stay with leave to refile after the SCPSC decision on the merger among Dominion Energy, Sedona and SCANA.

On July 17, 2018, a case filed in the District Court styled Penningtonet al.v. SCANA, Fluor Corporation and Fluor Enterprises was certified as a class action on behalf of persons who were formerly employed at the Nuclear Project. The plaintiffs allege, among other things, that the defendants violated the WARN Act in connection with the decision to stop construction on 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 the case described in the next paragraph.

On September 7, 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against SCE&G and Santee Cooper. The plaintiffs make claims for equitable indemnity, 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 Pennington case. Plaintiffs seek a damages award, including, but not limited to, defense costs, attorney fees and expenses and any other relief the court deems proper.

A complaint has been filed by Fairfield County against SCE&G making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of the implied duty of good faith and fair dealing, and unfair trade practices related to SCE&G’s termination of the FILOT agreement. Plaintiff seeks injunctive relief to prevent SCE&G from terminating the FILOT agreement; actual and consequential damages; treble damages; punitive damages; and attorneys’ fees.

The Company has also been 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.

The DOR has initiated an audit of SCE&G's sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The DOR's position is that the exemption for sales and use tax for purchases related to the Nuclear Project should not apply because Unit 2 and Unit 3 will not be placed into service and no electricity will be manufactured for sale. On June 1, 2018, SCE&G received from the DOR a notice of proposed assessment arising from that audit of approximately $410 million, plus interest. While SCE&G has filed a protest of the proposed assessment, it is reasonably possible that a loss estimated to be as much as $410 million, plus interest and penalties, could be incurred, of which SCE&G's proportionate share as a co-owner of the Nuclear Project would be 55%.

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, they cannot predict the timing or outcome of these matters or others that may arise, including any claims that may be asserted by or against Santee Cooper in addition to claims made by Santee Cooper in connection with the Joint Petition, and adverse outcomes from some of these matters would not be covered by insurance.

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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, each of the cases referred to above is in its 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 condensed 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 $13.1 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 $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 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 $84.8 million per incident, but not more than $12.6 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

On August 3, 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. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G are monitoring the final rule, but do not plan to construct new coal-fired units in the foreseeable future.     

On August 21, 2018, the EPA proposed the ACE rule which would replace the CPP. The EPA had proposed in 2017 to replace the CPP on the grounds that it exceeded the EPA’s statutory authority and in response to federal court proceedings and an Executive Order. 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

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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 had become 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.

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 $9.6 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. 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 condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At September 30, 2018, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $23.6 million and are included in regulatory assets.

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Other

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

11.    SEGMENT OF BUSINESS INFORMATION

Regulated operations measure profitability using operating income; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. The Gas Marketing segment measures profitability using net income.

The Company's Gas Distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented.

The Company
Millions of dollars	External Revenue		Intersegment Revenue			Operating Income (Loss)			Net Income
Three Months Ended September 30, 2018
Electric Operations	$	669	—			$	217		n/a
Gas Distribution	122		—			(10		)	n/a
Gas Marketing	135		$	35		n/a			$	1
All Other	—		124			—			(30		)
Adjustments/Eliminations	—		(159		)	(24		)	96
Consolidated Total	$	926	—			$	183		$	67
Nine Months Ended September 30, 2018
Electric Operations	$	1,767	$	3		$	396		n/a
Gas Distribution	631		1			107			n/a
Gas Marketing	550		95			n/a			$	21
All Other	—		347			—			(79		)
Adjustments/Eliminations	—		(446		)	(28		)	302
Consolidated Total	$	2,948	—			$	475		$	244

Three Months Ended September 30, 2017
Electric Operations	$	786	$	1		$	127		n/a
Gas Distribution	123		—			(7		)	n/a
Gas Marketing	167		35			n/a			$	1
All Other	—		90			—			(7		)
Adjustments/Eliminations	—		(126		)	2			40
Consolidated Total	$	1,076	—			$	122		$	34
Nine Months Ended September 30, 2017
Electric Operations	$	2,042	$	4		$	555		n/a
Gas Distribution	584		1			110			n/a
Gas Marketing	623		93			n/a			$	17
All Other	—		286			—			(14		)
Adjustments/Eliminations	—		(384		)	28			323
Consolidated Total	$	3,249	—			$	693		$	326

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Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income (Loss)			Comprehensive Income Available to Common Shareholder
Three Months Ended September 30, 2018
Electric Operations	$	670	$	216		n/a
Gas Distribution	69		(4		)	n/a
Adjustments/Eliminations	—		—			$	98
Consolidated Total	$	739	$	212		$	98
Nine Months Ended September 30, 2018
Electric Operations	$	1,770	$	396		n/a
Gas Distribution	304		44			n/a
Adjustments/Eliminations	—		—			$	248
Consolidated Total	$	2,074	$	440		$	248

Three Months Ended September 30, 2017
Electric Operations	$	787	$	126		n/a
Gas Distribution	69		(2		)	n/a
Adjustments/Eliminations	—		—			$	39
Consolidated Total	$	856	$	124		$	39
Nine Months Ended September 30, 2017
Electric Operations	$	2,046	$	555		n/a
Gas Distribution	285		42			n/a
Adjustments/Eliminations	—		—			$	270
Consolidated Total	$	2,331	$	597		$	270

Segment Assets	The Company				Consolidated SCE&G
	September 30,		December 31,		September 30,		December 31,
Millions of dollars	2018		2017		2018		2017
Electric Operations	$	12,046	$	11,979	$	12,046	$	11,979
Gas Distribution	3,384		3,259		909		869
Gas Marketing	204		230		n/a		n/a
All Other	1,071		1,042		n/a		n/a
Adjustments/Eliminations	2,111		2,229		3,174		3,098
Consolidated Total	$	18,816	$	18,739	$	16,129	$	15,946

12.    AFFILIATED TRANSACTIONS

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 income (for the Company) and of comprehensive income (for Consolidated SCE&G).

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from Canadys Refined Coal, LLC	$	45.2	$	47.5	$	122.5	$	144.9
Sales to Canadys Refined Coal, LLC	44.9		47.2		121.8		144.0

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Millions of Dollars	September 30, 2018		December 31, 2017
Receivable from Canadys Refined Coal, LLC	$	8.5	$	4.9
Payable to Canadys Refined Coal, LLC	8.5		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.

Consolidated SCE&G has provided $71.0 million in funding to a rabbi trust consolidated with SCANA in connection with the potential change in control arising from the Merger Agreement. This funding is recorded as long-term Other affiliate assets on the condensed consolidated balance sheet of Consolidated SCE&G.

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from SCANA Energy	$	35.0	$	35.3	$	95.0	$	93.4
Direct and Allocated Costs from SCANA Services	72.9		78.1		208.3		233.6

Millions of Dollars	September 30, 2018		December 31, 2017
Payable to SCANA Energy	$	10.6	$	10.0
Payable to SCANA Services	42.8		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.

13.          OTHER INCOME (EXPENSE), NET

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

	The Company												Consolidated SCE&G
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
Millions of dollars	2018			2017			2018			2017			2018			2017			2018			2017
Revenues from contracts with customers	$	4		—			$	14		—			$	1		—			$	4		—
Other income	8			$	28		144			$	61		5			$	21		135			$	36
Other expense	(14		)	(9		)	(34		)	(33		)	(10		)	(7		)	(22		)	(23		)
Allowance for equity funds used during construction	5			—			12			17			3			(3		)	7			13
Other income (expense), net	$	3		$	19		$	136		$	45		$	(1	)	$	11		$	124		$	26

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. Other income in 2018 includes gains from the settlement of interest rate derivatives of approximately $115 million (see Note 7). Non-service cost components of pension and other postretirement benefits are included in Other expense.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS

OF OPERATIONS

Pursuant to General Instruction H of Form 10-Q, SCE&G is permitted to omit certain information related to itself and its consolidated affiliates called for by Item 2 of Part I of Form 10-Q, and instead provide a management’s narrative analysis of its consolidated results of operation and other information described therein. Such information is presented hereunder specifically for Consolidated SCE&G but may be presented alongside information presented for the Company generally. Consolidated SCE&G makes no representation as to information relating solely to SCANA and its subsidiaries (other than Consolidated SCE&G).

RESULTS OF OPERATIONS

FOR THE THREE MONTHS AND NINE MONTHS ENDED SEPTEMBER 30, 2018

AS COMPARED TO THE CORRESPONDING PERIODS IN 2017

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANA’s and SCE&G’s Annual Report on Form 10-K for the year ended December 31, 2017. The results of operations of the Company include those of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's results of operations necessarily include those of Consolidated SCE&G.

Earnings

Earnings were as follows:

	Third Quarter				Year to Date
The Company	2018		2017		2018		2017
Earnings per share	$	0.47	$	0.24	$	1.71	$	2.28
Consolidated SCE&G
Net income (millions of dollars)	$	103.6	$	41.8	$	262.3	$	279.7

The Company's earnings per share and Consolidated SCE&G's net income reflect the impact of an electric rate reduction made effective as of the second quarter of 2018 and the effect of weather in 2018 and 2017. Such results in 2018 also reflect higher legal costs and costs incurred in connection with the Nuclear Project and the Company's announced merger with Dominion Energy. These and other results are discussed below.

Matters Impacting Future Results

The Company's decision on July 31, 2017 to stop construction of Unit 2 and Unit 3 and to pursue recovery of the cost of the abandoned Nuclear Project has had and could continue to have significant adverse impacts on the Company's and Consolidated SCE&G's future earnings, cash flows and financial position, including those related to the ultimate recovery of regulatory assets, the sustainability of tax positions, the results of litigation and the outcome of various regulatory and governmental proceedings and investigations. The Company continues to believe the decision to abandon the Nuclear Project and the costs incurred with respect to it were prudent under applicable law and has contested specific challenges to these assertions. The Company also believes that the issues related to the recovery of the cost of the abandoned Nuclear Project and related to the rates currently being collected under the BLRA for financing costs should be resolved in current proceedings before the SCPSC. However, based on various events following the abandonment, there is significant uncertainty as to SCE&G's ultimate ability to recover its costs of Unit 2 and Unit 3 and a return on them from its customers. These events include the contentious nature of reviews by legislative committees and others, the General Assembly's passage of certain legislation in 2018, including Act 258 discussed below, and the Request being considered by the SCPSC that could result in the permanent suspension of all or a portion of rates currently being collected under the BLRA, as well as the return of such amounts previously collected. There is also significant uncertainty as to the timing and the ultimate resolution of the litigation and the various other proceedings discussed herein.

In 2017, the Company and Consolidated SCE&G determined that a disallowance of recovery of part of the cost of the abandoned Nuclear Project was both probable and reasonably estimable under applicable accounting guidance and recorded a

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pre-tax impairment loss with respect to disallowance of unrecovered Nuclear Project costs and other related deferred costs totaling approximately $1.118 billion ($690 million net of tax). In the first quarter of 2018, the Company and Consolidated SCE&G recognized an additional pre-tax impairment loss totaling approximately $3.6 million ($2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel that had been acquired for use in Unit 2 and Unit 3. See additional discussion at Note 10 to the condensed consolidated financial statements.

It is reasonably possible that further changes in these estimates will occur in the near term and could be material; however, all such changes cannot be reasonably estimated. The impairment loss recorded in 2017 reflects impacts similar to those that would have resulted had the proposed solution announced on November 16, 2017 been implemented. If the merger benefits and cost recovery plan outlined in the Joint Petition is implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $1.7 billion (approximately $1.3 billion net of tax) would be expected to be recorded. If the Alternative Plan were implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $2.3 billion (approximately $1.7 billion net of tax) would be expected to be recorded.

If (i) the SCPSC does not approve the Joint Petition or the Alternative Plan and instead approves the Request by the ORS; (ii) the BLRA is found to be unconstitutional; or (iii) the General Assembly further amends or revokes the BLRA or approves other legislation with a similar effect, the Company and Consolidated SCE&G may be required to record an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $5.0 billion (approximately $3.7 billion net of tax). This additional impairment loss would result from the write-off of approximately $3.960 billion in regulatory assets (comprised of the remaining unrecovered Nuclear Project costs of $4.140 billion offset by $180 million in previously impaired costs related to CEC, which would result from the proposals put forward in the Joint Petition or Alternative Plan not being approved by the SCPSC) and the refund of revised rates collections under the BLRA described above of approximately $2.1 billion (comprised of the revised rates collections on a cumulative basis as of September 30, 2018 and reflective of the impacts of Act 258), net of approximately $1.065 billion, which amount represents the monetization of guaranty settlement recorded within regulatory liabilities less amounts that may be required to satisfy contractor liens. The Company and Consolidated SCE&G do not currently anticipate that any amounts collected prior to April 1, 2018, will be subject to refund (other than amounts arising from the effects of the Tax Act); however, no assurance can be given as to the outcome of this matter. Were the rates under Act 258 made other than temporary following the SCPSC's final decision on the Joint Petition, and without consideration of any other factors that may be embodied in such an order, an additional pre-tax impairment charge (in excess of the $1.118 billion above) totaling approximately $1.7 billion may be required. See Claims and Litigation in Note 10 to the condensed consolidated financial statements for additional discussion regarding the constitutionality of the BLRA.

In addition to the matters above, in the Joint Petition, the Company and Consolidated SCE&G proposed to remove from BLRA capital costs their investment in transmission assets that have been or will be placed in service and have not been abandoned. As of September 30, 2018, such investment in these assets total approximately $376 million (approximately $365 million within utility plant, net and approximately $11 million within regulatory assets, which amount represents certain deferred operating costs). The Company and Consolidated SCE&G believe that this investment represents assets that are or will be used to provide electric service to customers and that a recovery of and a reasonable return on the investment should be provided in future rates. During the hearing on the Concurrent Dockets, the SCPSC will consider a request by the ORS to allow the Company and Consolidated SCE&G to defer certain operating costs related to the investment and that a decision on the recovery of this investment, including operating costs deferrals, be addressed in a future rate proceeding. If the SCPSC were to disallow recovery of or a reasonable return on all or a portion of this investment, an impairment charge related to these assets totaling as much as approximately $376 million may be required.

On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA. Act 258 requires the SCPSC to order a reduction in 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%, or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On July 2 and 3, 2018, the SCPSC issued orders implementing the temporary rate reduction required by Act 258. The resulting new rates and retroactive credits required by Act 258 were put into effect in August 2018, with the retroactive credits for the second quarter being applied in August's billing cycles. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 alters certain provisions previously applicable under the BLRA, including redefining the standard of care required by the BLRA 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.

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On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented.

                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 corporate 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. As described in Note 2 to the condensed consolidated financial statements, SCE&G and PSNC Energy have responded to orders from state regulators seeking information regarding the effects the Tax Act would have on their respective operations, and state regulators have issued orders related to certain of these matters. In 2018, the Company and Consolidated SCE&G are recording estimates of revenue that will be subject to refund to customers of its regulated operations. Such amounts result in reductions to revenue and are deferred on the condensed consolidated balance sheet. Such reductions in revenue largely correspond to reductions in current period tax expense. Going forward, to the extent state regulators order reductions in customer rates, the lower tax expense resulting from the reduced federal statutory corporate tax rate will result in similar reductions to amounts collected from customers through electric and gas rates, and no significant impact on financial results is expected. However, the refund of revenue collected in 2018 will negatively impact cash flow. In addition, certain of these regulatory liabilities for excess deferred taxes will be amortized to the benefit of customers over the remaining lives of related property in accordance with the normalization provisions of the IRC and Code of Federal Regulations, thereby mitigating any significant negative cash impact due to the extended amortization period. See also Note 6 to the condensed consolidated financial statements for additional discussion related to deferred tax assets and liabilities.

These matters impacting future results are further discussed under Liquidity Considerations and Impact of Abandonment of Nuclear Project within LIQUIDITY AND CAPITAL RESOURCES, in Note 2 and Note 10 to the condensed consolidated financial statements and in Part II, Item 1A. Risk Factors.

Dividends Declared

SCANA's Board of Directors declared the following dividends on common stock during 2018:

Declaration Date	Payment Date	Record Date	Dividend Per Share
February 22, 2018	April 1, 2018	March 12, 2018	$0.6125
June 28, 2018	July 18, 2018	July 10, 2018	$0.1237
August 30, 2018	October 1, 2018	September 10, 2018	$0.1237
October 23, 2018	January 1, 2019	December 10, 2018	$0.1237

When a dividend payment date falls on a weekend or holiday, the payment is made the following business day. SCANA's Board of Directors evaluates the payment of dividends each quarter.

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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 income (including transactions with affiliates) was as follows:

	The Company								Consolidated SCE&G
	Third Quarter				Year to Date				Third Quarter				Year to Date
Millions of dollars	2018		2017		2018		2017		2018		2017		2018		2017
Operating revenues	$	669.7	$	787.3	$	1,770.2	$	2,045.9	$	669.7	$	787.3	$	1,770.2	$	2,045.9
Fuel used in electric generation	188.3		166.5		503.0		464.1		188.3		166.5		503.0		464.1
Purchased power	9.4		22.3		76.6		54.1		9.4		22.3		76.6		54.1
Other operation and maintenance	123.7		132.1		392.5		376.5		127.3		135.6		402.6		387.2
Impairment loss	—		210.0		3.6		210.0		—		210.0		3.6		210.0
Depreciation and amortization	76.3		73.8		228.0		219.9		73.6		70.8		219.7		211.0
Other taxes	55.7		56.4		170.2		166.8		55.1		55.9		168.4		165.0
Operating Income	$	216.3	$	126.2	$	396.3	$	554.5	$	216.0	$	126.2	$	396.3	$	554.5

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 develop an estimate of electric revenue and fuel costs attributable to the effects of abnormal weather. Results in both 2018 and 2017 reflect milder than normal weather in the first quarter, with 2017 being significantly milder than 2018, and warmer than normal weather in the second and third quarters, with 2018 being significantly warmer than 2017.

The Company and Consolidated SCE&G expect, if Act 258 remains in effect, that electric operating revenues will decrease by approximately $31 million each month through the remainder of 2018 when compared to operating revenues recorded in corresponding periods in 2017.

Third Quarter

• Operating revenues decreased in 2018 by $101.4 million due to the enactment and implementation of Act 258, by $16.5 million due to the recognition of estimated amounts to be refunded to customers as a result of the Tax Act, lower residential and commercial average use of $14.8 million and lower industrial usage of $2.1 million. These revenue decreases were partially offset by the effects of weather of $18.7 million, residential and commercial growth of $5.2 million and revenue recognized under the DER program of $4.2 million.

• Fuel used in electric generation and purchased power expenses increased in the aggregate in 2018 due to higher amortization of DER program costs of $4.8 million, increased sales volumes associated with residential and commercial customer growth of $1.4 million and higher sales volumes associated with the effects of weather of $5.5 million. These increases were partially offset by lower residential and commercial average use of $4.6 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.

• Other operation and maintenance expenses decreased in 2018 due to lower labor costs of $8.8 million, primarily due to Nuclear Project severance accruals in 2017, lower customer bad debt expense of $1.4 million primarily due to lower revenue resulting from the enactment and implementation of Act 258, lower injuries and damages of $1.8 million and lower non-labor generation and other electric operations costs of $3.1 million. These decreases were partially offset by wind down costs associated with the abandonment of the Nuclear Project of $3.1 million and higher legal and other costs related to the abandonment of the Nuclear Project of approximately $8.0 million.

• Impairment loss represents the estimated probable disallowance of recovery associated with the abandonment of the Nuclear Project recognized in 2017.

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

• Other taxes decreased primarily due to a 2018 true-up for property tax accruals to reflect revised lower estimates.

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Year to Date

• Operating revenues decreased in 2018 by $113.7 million pursuant to an SCPSC order whereby fuel cost recovery is offset with gains realized upon the settlement of certain interest rate derivative contracts, as further described in Other Income (Expense) below, related to fuel cost recovery. Operating revenue also decreased by $210.8 million due to the enactment and implementation of Act 258, by $56.7 million due to the recognition of estimated amounts to be refunded to customers as a result of the Tax Act, lower collections under the rate rider for pension costs of $3.2 million and lower residential and commercial average use of $37.3 million. The downward adjustment related to fuel costs 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. The lower pension rider collections had no impact on net income as they were fully offset by the recognition, within other operation and maintenance expenses, of lower pension costs. These revenue decreases were partially offset by the effects of weather of $87.9 million, residential and commercial growth of $17.7 million, industrial growth and usage of $3.2 million, revenue recognized under the DER program of $10.8 million and higher fuel cost recovery of $30.7 million.

• Fuel used in electric generation and purchased power expenses increased due to higher fuel prices of $30.7 million, amortization of DER program costs of $10.2 million, increased sales volumes associated with residential and commercial customer growth of $4.1 million, industrial growth and usage of $3.0 million, higher sales volumes associated with the effects of weather of $20.9 million and higher fuel handling expenses of $2.4 million. These increases were partially offset by lower residential and commercial average use of $9.9 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.

• Other operation and maintenance expenses increased due to wind down costs associated with the abandonment of the Nuclear Project of $10.2 million, higher legal and other costs related to the abandonment of the Nuclear Project of approximately $18.4 million and higher non-service costs of $1.9 million. These increases were partially offset by lower customer bad debt expense of $0.8 million primarily due to lower revenue resulting from the enactment and implementation of Act 258 and lower labor costs of $14.9 million, primarily due to Nuclear Project severance accruals in 2017 and lower incentive compensation costs.

• Impairment loss represents the estimated probable disallowance of recovery associated with the abandonment of the Nuclear Project recognized in 2017 and the further write down of nuclear fuel acquired for use in Unit 2 and Unit 3 to its estimated fair value in the first quarter of 2018.

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

• 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:

	Third Quarter		Year to Date
Classification	2018	2017	2018	2017
Residential	2,458	2,384	6,413	5,936
Commercial	2,178	2,159	5,752	5,663
Industrial	1,678	1,652	4,779	4,676
Other	163	163	443	444
Total Retail Sales	6,477	6,358	17,387	16,719
Wholesale	305	257	791	699
Total Sales	6,782	6,615	18,178	17,418

Third Quarter and Year to Date

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
	Third Quarter						Year to Date				Third Quarter						Year to Date
Millions of dollars	2018			2017			2018		2017		2018			2017			2018		2017
Operating revenues	$	122.2		$	123.4		$	631.9	$	585.7	$	69.5		$	68.3		$	303.6	$	285.1
Gas purchased for resale	56.3			57.8			294.1		254.1		40.8			38.5			161.4		146.5
Other operation and maintenance	41.7			39.8			126.4		125.2		17.1			16.9			52.2		52.9
Depreciation and amortization	23.5			21.4			69.5		63.3		7.6			7.4			22.7		21.6
Other taxes	11.0			10.5			35.3		32.4		7.6			7.2			23.8		21.6
Operating Income (Loss)	$	(10.3	)	$	(6.1	)	$	106.6	$	110.7	$	(3.6	)	$	(1.7	)	$	43.5	$	42.5

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 condensed consolidated financial statements. The WNA and the CUT do not affect sales volumes.

Third Quarter

• Operating revenues increased at SCE&G primarily due to increased base rates under the RSA of $1.2 million, customer growth of $1.7 million and higher gas cost recovery of $2.0 million. These increases were partially offset by a decrease of $1.4 million due to the recognition of estimated amounts to be refunded to customers as a result of the Tax Act and lower average use of $1.8 million. In addition to these factors, operating revenues at the Company decreased due to a CUT adjustment at PSNC Energy of $2.5 million, decreased gas cost recoveries of $1.1 million and $1.1 million due to deferred revenues related to the Tax Act. These decreases were partially offset by increased adjustment related to integrity management of $1.3 million, customer growth of $0.7 million and $0.7 million related to excess deferred income taxes.

• Gas purchased for resale increased at SCE&G due to firm customer growth of $0.9 million and higher gas prices of $2.0 million, partially offset by lower average use of $0.5 million. In addition to these factors, gas purchased for resale at the Company reflects decreased gas costs at PSNC Energy of $1.1 million and a CUT adjustment of $2.9 million.

• Other operation and maintenance expenses at SCE&G increased primarily due to higher labor costs partially offset by lower nonlabor operation and maintenance expenses. In addition to these factors, operation and maintenance expenses at the Company reflects increased labor costs at PSNC Energy.

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

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

Year to Date

• Operating revenues increased at SCE&G primarily due to increased base rates under the RSA of $7.9 million, customer growth of $8.2 million, higher average use of $0.7 million and higher gas cost recovery of $8.4 million. These increases were partially offset by a decrease of $7.0 million due to the recognition of estimated amounts to be refunded to customers as a result of the Tax Act. In addition to these factors, operating revenues at the Company increased due to weather at PSNC Energy of $59.7 million, customer growth of $7.0 million, increased adjustment related to integrity management of $6.3 million, and $3.7 million related to excess deferred income taxes. These increases were partially offset by a CUT adjustment of $22.0 million, decreased gas cost recoveries of $16.6 million and $9.7 million due to deferred revenues related to the Tax Act.

• Gas purchased for resale increased at SCE&G due to higher average use of $2.4 million, increased sales volumes due to weather of $13.4 million and firm customer growth of $4.1 million. These increases were partially offset by lower gas prices of $5.0 million. In addition to these factors, gas purchased for resale at the Company reflects increased sales volumes due to weather at PSNC Energy of $29.8 million, the effect of a CUT adjustment of $6.7 million, customer growth of $3.0 million and $2.6 million related to excess deferred income taxes. These increases were partially offset by decreased gas costs of $16.6 million.

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• Other operation and maintenance expenses at SCE&G decreased primarily due to lower labor costs and lower non-labor operation and maintenance expenses. In addition to these factors, operation and maintenance expenses at the Company increased due to increased labor costs at PSNC Energy, in addition to higher transportation costs.

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

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

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

	The Company				Consolidated SCE&G
	Third Quarter		Year to Date		Third Quarter		Year to Date
Classification (in thousands)	2018	2017	2018	2017	2018	2017	2018	2017
Residential	2,153	2,196	29,434	21,958	738	742	9,205	6,690
Commercial	4,670	4,537	22,088	19,113	2,391	2,381	9,544	8,783
Industrial	4,788	4,644	15,666	14,723	4,445	4,289	13,985	13,289
Transportation	14,900	14,865	40,924	38,313	1,566	1,516	4,638	4,602
Total	26,511	26,242	108,112	94,107	9,140	8,928	37,372	33,364

Third Quarter

Residential sales volumes at the Company decreased primarily due to lower average use at PSNC Energy. Commercial volumes at the Company increased primarily due to customer growth at PSNC Energy. Residential and commercial volumes at Consolidated SCE&G were relatively flat. Industrial volumes increased due to customer growth and higher average use at SCE&G. Transportation volumes increased due to customer growth.

Year to Date

Residential and commercial firm sales volumes for the Company and Consolidated SCE&G increased due to the effects of weather and customer growth. Industrial volumes increased due to customer growth and average use, partially offset by curtailments in 2018 at SCE&G, and increased due to the effects of weather at PSNC Energy. 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.

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:

	Third Quarter				Year to Date
Millions of dollars	2018		2017		2018		2017
Operating revenues	$	169.8	$	202.1	$	645.6	$	716.4
Net income	0.2		0.7		20.8		16.9

Third Quarter

Operating revenues decreased primarily due to the impact of adopting the revenue recognition guidance described in Note 3 to the condensed consolidated financial statements, whereby certain pass through charges are no longer classified as revenues. Net income decreased due to higher operating expenses which were partially offset by the effects of the Tax Act.

Year to Date

Operating revenues decreased primarily due to the impact of adopting the revenue recognition guidance described in Note 3 to the condensed consolidated financial statements, whereby certain pass through charges are no longer classified as revenues.  Net income increased primarily due to the effects of the Tax Act.

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Other Operating Expenses

Other operating expenses were as follows:

	The Company								Consolidated SCE&G
	Third Quarter				Year to Date				Third Quarter				Year to Date
Millions of dollars	2018		2017		2018		2017		2018		2017		2018		2017
Other operation and maintenance	$	200.3	$	181.1	$	610.3	$	535.1	$	144.4	$	152.5	$	454.8	$	440.1
Impairment loss	—		210.0		3.6		210.0		—		210.0		3.6		210.0
Depreciation and amortization	100.3		95.7		298.9		284.7		81.2		78.2		242.4		232.6
Other taxes	67.2		67.2		206.8		200.2		62.8		63.1		192.2		186.6

Changes in other operating expenses are largely attributable to the electric operations and gas distribution segments and are addressed in those discussions. Other operation and maintenance includes certain legal and other costs incurred in connection with the Nuclear Project and the proposed merger with Dominion Energy. Increases in such costs at the Company totaled approximately $31.5 million for the third quarter (including $8.0 million attributable to Consolidated SCE&G) and approximately $74.2 million for the year to date period (including $18.4 million attributable to Consolidated SCE&G). The increases attributable to Consolidated SCE&G are included in amounts described in electric operations.

Other Income (Expense)

Other income (expense) includes the results of certain incidental non-utility activities of regulated subsidiaries, the activities of certain non-regulated subsidiaries, the costs of certain governance activities at the parent company and AFC. AFC is a utility accounting practice under which a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the condensed consolidated balance sheet as construction work in progress) is capitalized. Each of the Company and Consolidated SCE&G includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits), both of which have the effect of increasing reported net income. Components of other income (expense) and AFC were as follows:

	The Company												Consolidated SCE&G
	Third Quarter						Year to Date						Third Quarter						Year to Date
Millions of dollars	2018			2017			2018			2017			2018			2017			2018			2017
Other income	$	12.5		$	28.4		$	158.1		$	61.0		$	5.8		$	20.8		$	138.4		$	36.1
Other expense	(14.4		)	(9.0		)	(34.6		)	(33.4		)	(9.5		)	(7.2		)	(21.2		)	(23.3		)
AFC - equity funds	5.2			(0.6		)	12.4			17.6			2.8			(3.5		)	7.0			12.7

Third Quarter

Other income at the Company and Consolidated SCE&G decreased by $10.9 million due to the accrual of carrying costs on unrecovered Nuclear Project costs in 2017 and by $4.5 million due to lower carrying cost accrual on certain deferred items. Other expense at the Company and at Consolidated SCE&G increased $3.0 million and $2.5 million, respectively, due to changes in non-service cost components of pension and other postretirement benefit expense recognized within other expense. Equity AFC increased due to a downward adjustment in 2017 to adjust to a revised (lower) AFC rate as a result of removing Nuclear Project related capital costs from the average construction work in progress balance used to determine the annual AFC rate following the abandonment decision.

Year to Date

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 $6.7 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 had no effect on net income. These increases were partially offset by $10.9 million due to the accrual of carrying costs on unrecovered Nuclear Project costs in 2017 and by $12.6 million due to lower carrying cost accrual on certain deferred items. Other expense at the Company and Consolidated SCE&G decreased $2.6 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 were more than offset by increases in nonutility expenses and losses from equity method investments. Equity AFC decreased primarily due to the abandonment of the Nuclear Project.

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Interest Expense

     Interest charges increased primarily due to the issuance of long-term debt at SCE&G in the third quarter of 2018, the accrual of interest related to uncertain tax positions and lower debt AFC due to the abandonment of the Nuclear Project. In 2017, certain of such interest accruals related to uncertain tax positions were deferred in regulatory assets, and such deferred amounts were subsequently included in an impairment loss recorded in the fourth quarter of 2017.

Income Taxes

Third Quarter

Income tax expense increased due to higher income before taxes, partially offset by a lower effective tax rate. The lower effective tax rate in 2018 was primarily due to the federal corporate tax rate changing from 35% to 21% as a result of the Tax Act.

Year to Date

Income tax expense decreased in 2018 due to lower income before taxes and a lower effective tax rate. The lower effective tax rate in 2018 was primarily due to the federal corporate tax rate changing from 35% to 21% as a result of the Tax Act.

LIQUIDITY AND CAPITAL RESOURCES

The Company and Consolidated SCE&G have experienced significant adverse events leading up to their decision to stop construction of Unit 2 and Unit 3, as well as significant adverse events since that decision was made. These difficulties and other developments occurring prior to the bankruptcy filing by WEC and WECTEC and other matters are described in Liquidity and Capital Resources and in Note 10 to the consolidated financial statements included in the Company's and Consolidated SCE&G's combined Form 10-K for the year ended December 31, 2017. Significant developments affecting liquidity after December 31, 2017 are discussed below.

Liquidity Considerations

The Company and Consolidated SCE&G have significant obligations that must be paid within the next 12 months, including long-term debt maturities and capital lease payments of $18 million for the Company (including $14 million for Consolidated SCE&G), short-term borrowings of $314 million for the Company (including $173 million for Consolidated SCE&G), interest payments of approximately $335 million for the Company (including $255 million for Consolidated SCE&G), future minimum payments for operating leases of $9 million for the Company (including $3 million for Consolidated SCE&G), and revenues collected subject to refund arising from the effects of the Tax Act of approximately $61 million for the Company and Consolidated SCE&G. Working capital requirements, such as those for fuel supply and similar obligations, also arise due to the lag between when such amounts are paid and when related collection of such costs through customer rates occurs. In addition, as described under Impairment Considerations in Note 10 to the condensed consolidated financial statements, SCE&G has been ordered to reduce revised rates previously approved under the BLRA by approximately $279 million in 2018. This reduction assumes that Act 258 remains in effect through December 21, 2018, which is the expected pendency of the SCPSC proceeding with respect to the Concurrent Dockets.

On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA. Act 258 requires the SCPSC to order a reduction in 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%, or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On July 2 and 3, 2018, the SCPSC issued orders implementing the temporary rate reduction required by Act 258. The resulting new rates and retroactive credits were put into effect in August 2018, with the retroactive credits for the second quarter being applied in August's billing cycles. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 alters certain provisions previously applicable under the BLRA, including redefining the standard of care required by the BLRA 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.

On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a

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hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented.

For each of the quarters ended June 30, 2018, September 30, 2018, and December 31, 2018, SCANA's Board of Directors declared a dividend of $0.1237 per share, which represents an approximately 80% reduction from the $0.6125 per share paid on SCANA’s common stock for the first quarter of 2018. This reduction corresponds to the portion of the dividend attributable to SCE&G's electric operations and serves to partially mitigate the liquidity impacts arising from the reduced revenues and cash flows resulting from the implementation of Act 258. The payment of future dividends will be evaluated quarterly by the Board of Directors.

              Management believes as of the date of issuance of this report that it has access to available sources of cash to pay obligations when due over the next 12 months. These sources include committed long-term lines of credit that expire in December 2020 totaling $1.8 billion for the Company (including $1.2 billion for Consolidated SCE&G). In addition, as of the date of issuance of this report, SCE&G continues to collect the BLRA-related customer rates that remain after reductions ordered as a result of Act 258, as well as amounts provided for in other orders related to non-BLRA electric and gas rates. In 2018, however, certain of SCANA's credit ratings have fallen to below investment grade, which has constrained its ability to issue commercial paper. The ability of Fuel Company and PSNC Energy to issue commercial paper has also been constrained.

Were the SCPSC to grant the relief sought by ORS in the Request or grant similar relief resulting from legislative action, as further discussed in Note 10 in the condensed consolidated financial statements, an additional impairment loss (in excess of the $1.118 billion previously taken) or other charges totaling approximately $5.0 billion (approximately $3.7 billion net of tax) may be required. Such an impairment loss or other charges would further increase the Company’s and Consolidated SCE&G’s debt to total capitalization ratio and may result in the Company’s and Consolidated SCE&G’s ratio of debt to total capitalization exceeding maximum levels prescribed in their respective credit agreements. Such an event likely would limit the Company’s and Consolidated SCE&G’s ability to borrow under their commercial paper programs and credit facilities and their ability to pay future dividends or may trigger events of default under such agreements.

In addition to the matters above, in the Joint Petition, the Company and Consolidated SCE&G proposed to remove from BLRA capital costs their investment in transmission assets that have been or will be placed in service and have not been abandoned. As of September 30, 2018, such investment in these assets total approximately $376 million (approximately $365 million within utility plant, net and approximately $11 million within regulatory assets, which amount represents certain deferred operating costs). The Company and Consolidated SCE&G believe that this investment represents assets that are or will be used to provide electric service to customers and that a recovery of and a reasonable return on the investment should be provided in future rates. During the hearing on the Concurrent Dockets, the SCPSC will consider a request by the ORS to allow the Company and Consolidated SCE&G to defer certain operating costs related to the investment and that a decision on the recovery of this investment, including operating costs deferrals, be addressed in a future rate proceeding. If the SCPSC were to disallow recovery of or a reasonable return on all or a portion of this investment, an impairment charge related to these assets totaling as much as approximately $376 million may be required.

Known and knowable conditions and events when considered in the aggregate as of the date of issuance of this report do not suggest it is probable that the Company and Consolidated SCE&G will not be able to meet obligations as they come due over the next 12 months. However, certain possible adverse future actions, including but not limited to those contemplated in the Request by the ORS regarding the disallowance of all or part of the remaining unrecovered nuclear regulatory asset, rate reductions and refunds, and including actions that may result from other legal, regulatory and governmental proceedings and investigations, could likely have a material adverse impact on the Company’s and Consolidated SCE&G’s financial condition, liquidity, results of operations and cash flows such that management’s conclusion with respect to its ability to pay obligations when due could change.

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Impact of Abandonment of Nuclear Project

Regulatory proceedings being considered by the SCPSC include the Request filed by the ORS which, if granted, would require SCE&G to (1) immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA, and (2) make credits to future bills or refunds to customers for prior revised rates collections in the event that the BLRA is found to be unconstitutional or the South Carolina General Assembly further amends or revokes it. SCE&G estimates that revised rates collections, including collections related to transmission assets which have been or are expected to be placed into service and prior to implementation of Act 258, total approximately $445 million annually, and such amounts accumulated as of September 30, 2018 total approximately $2.1 billion, which amount reflects the impacts of Act 258. In an amendment to the Request, the ORS has asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. SCE&G's 55% share of such amounts totals $1.098 billion. See Claims and Litigation in Note 10 to the condensed consolidated financial statements for additional discussion of the constitutionality of the BLRA.

Parties who have intervened in the Request or who filed a letter in support of the Request, as amended, include the state's Governor, Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, Santee Cooper, the SCEUC, certain large industrial customers, and several environmental groups. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets, including the Request, regarding the merits of the Joint Petition and related issues. This schedule was established in response to legislation described above. SCE&G intends to continue vigorously contesting the Request but cannot give any assurance as to the timing or outcome of this matter. Any adverse action by the SCPSC, such as that sought by the ORS in the Request, could have a material adverse impact on the Company's and Consolidated SCE&G's results of operations, cash flows and financial condition.

Should the SCPSC or a court direct that proceeds arising from the Toshiba Settlement be refunded to customers in the near-term, or direct that such funds be escrowed or otherwise made unavailable to SCE&G, it is anticipated that SCE&G would issue commercial paper, draw on its credit facilities or issue long-term debt or the Company would issue equity to fund such requirement if such sources are available. However, were the SCPSC to rule in favor of the ORS in response to the Request that SCE&G further suspend collections from customers of amounts previously authorized under the BLRA, or were other actions of the SCPSC or others taken in order to significantly restrict SCE&G’s access to revenues or impose additional adverse refund obligations on SCE&G, the Company’s and Consolidated SCE&G's assessments regarding the recoverability of all or a portion of the remaining balance of unrecovered Nuclear Project costs (see Note 2 and Note 10 to the condensed consolidated financial statements) would be adversely impacted and additional impairment losses would likely be recorded. Further, the recognition of significant additional impairment losses with respect to unrecovered Nuclear Project costs could increase the Company’s and Consolidated SCE&G’s debt to total capitalization to a level which may limit their ability to borrow under their commercial paper programs or under their credit facilities and could constitute a default under these credit facilities. Borrowing costs for long-term debt issuances and access to capital markets could also be negatively impacted.

For additional background on the Nuclear Project and further details on the matters described above, see Note 10 to the condensed consolidated financial statements under Abandoned Nuclear Project - Toshiba Settlement and Subsequent Monetization and Regulatory, Political and Legal Developments.

Adverse developments following the decision to stop construction of Unit 2 and Unit 3, and a deterioration in the regulatory and legislative environment in 2017 and 2018 have caused credit ratings agencies to place SCANA and SCE&G’s credit ratings on negative outlook or evolving status. On January 3, 2018, after SCANA announced a proposed merger with Dominion Energy, each of the three agencies affirmed or reported no change to their respective credit ratings, and one agency revised its rating outlook for SCANA and its rated operating companies from negative to evolving. However, on January 31, 2018, the South Carolina House of Representatives overwhelmingly approved a bill (similar provisions from which later would become Act 258) designed to temporarily repeal rates SCE&G collects under the BLRA. As a result, on February 5, 2018, one agency downgraded its ratings for SCANA and SCE&G and attributed the downgrade to the passage of this bill and the politically charged environment that is expected to weigh heavily on any decisions by the SCPSC related to SCE&G's electric rates. After Act 258 became law, on July 2 and 3, 2018, the agencies affirmed their ratings; however, one agency changed its outlook from review to negative. On August 8 and 9, 2018, two agencies downgraded their respective ratings for SCANA, SCE&G and PSNC Energy, citing the August 5, 2018, denial by the District Court of SCE&G's motion for a preliminary injunction to prohibit the implementation of Act 258.

As of September 30, 2018, the issuer ratings for SCANA are below investment grade by two agencies and at investment grade by one agency; the senior unsecured debt ratings for SCANA are below investment grade by all three agencies; the issuer ratings for SCE&G are at investment grade by two agencies and below investment grade by one agency;

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the senior secured debt ratings for SCE&G remain above investment grade by all three agencies; the issuer ratings for PSNC Energy are at investment grade by one agency and below investment grade by one agency (one agency does not provide an issuer rating); and the senior unsecured debt ratings for PSNC Energy are above investment grade by one agency and at investment grade by two agencies. In addition, all ratings for SCANA, SCE&G and PSNC Energy have either a negative or evolving outlook, indicating that the ratings are being scrutinized for possible rating actions either currently or dependent on the outcome of uncertain future events.

Any adverse final judgment by a court in any matter of litigation, or any levy for amounts assessed by a regulatory agency, including but not limited to matters described in Part II, Item 1. Legal Proceedings, could require the Company and/or Consolidated SCE&G to escrow funds or to post one or more bonds equal to the monetary amount of the judgment or assessment while the decision is being appealed or challenged.

Any actions taken by or anticipated to be taken by regulators, legislators or a court in any matter of litigation that are viewed as adverse, including a further change to or repeal of the BLRA (or adverse finding as to its constitutionality) or a requirement that SCE&G make additional credits to future bills or refunds to customers or any requirement that SCE&G make such credits or refunds in the absence of the merger being consummated, or deterioration of the rated companies’ commonly monitored financial credit metrics or any additional adverse developments with respect to the Nuclear Project, could further negatively affect their debt ratings. If these rating agencies were to further lower any of these ratings, borrowing costs on new issuances of long-term debt and commercial paper would increase, which could adversely impact financial results, and refinancing opportunities would be limited or eliminated to the extent that the potential pool of investors and funding sources decreased. In addition, further ratings downgrades may result in lower collateral thresholds being applied to the Company's and Consolidated SCE&G's commodity derivatives, or the removal of such thresholds altogether. This action would have the effect of requiring the Company to post additional collateral for commodity derivative instruments with unfavorable fair values. Ratings downgrades have also resulted in prepayments and demands from vendors for letters of credit, cash deposits, or other forms of credit support under certain gas supply and other agreements. SCANA has obtained a letter of credit of $30.4 million in favor of a natural gas distributor, which is in addition to a $3 million letter of credit that previously existed. In March 2018, SCE&G borrowed $100 million under a credit agreement to fund a deposit with one of its natural gas transporters. In September 2018, this deposit was replaced with a surety bond and SCE&G repaid its borrowing under the credit agreement. Also in September 2018, SCANA borrowed $40 million under a credit agreement to provide additional liquidity as a result of commercial paper borrowings being constricted. These actions have reduced amounts available under the credit facilities (see Note 5 to the condensed consolidated financial statements). Further ratings downgrades could result in requirements for additional deposits or the provision of additional credit support in order to conduct business under these agreements.

Significant Tax Deductions and Credits

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. (See also Note 6 to the condensed consolidated financial statements.) 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. Following that claim and a related carry back of tax net operating losses, on July 2, 2018, the Company received a refund of federal taxes previously paid totaling approximately $206 million.

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 until December 31, 2017, at which time these deferrals were considered to be impaired. These claims have 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 have needed to raise in the financial markets. 

The research and experimentation claims made to date are under examination and are considered controversial by the IRS. Tax deductions which have been claimed in connection with the determination to abandon the construction of Unit 2 and Unit 3 are also considered controversial.  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. Additionally, in such circumstances, the Company and Consolidated SCE&G may need to access

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the capital markets to fund those tax and interest payments, which could in turn adversely impact their ability to access those markets for other purposes.

Other Liquidity Requirements and Restrictions

The terms of the Merger Agreement place limits on the Company and its subsidiaries as to certain investing and financing transactions. While the Merger Agreement permits the Company and its subsidiaries to refinance and issue certain long-term debt, make capital expenditures at certain levels, consummate certain planned investments, and make regular quarterly dividend payments to its shareholders at certain levels, transactions above these levels would require consent from Dominion Energy, which consent cannot be unreasonably withheld. Permitted transactions include, but are not limited to, the refinancing of long-term debt maturing in 2018 at Consolidated SCE&G which was completed in the third quarter of 2018, the new issuance of $100 million of long-term debt at PSNC Energy which was completed in June 2018, the purchase of an existing 540-MW gas fired power plant which was completed in May 2018, and the payment by SCANA of regular quarterly dividends to its shareholders subject to certain limits. In addition, SCANA’s Supplementary Key Executive Severance Benefits Plan provides certain payments to qualified senior executive officers in connection with a change in control. In 2018, the Company has set aside in a grantor trust (subject to the claims of creditors in certain instances) approximately $112 million to be used to pay benefits pursuant to this and certain other severance, deferred compensation, incentive and retirement plans. Under the terms of the grantor trust, if a change in control occurs, a successor company cannot obtain access to the funds held in trust other than to pay benefits under the aforementioned plans and according to the terms of the trust.

The Company expects to meet contractual cash obligations in 2018 and 2019 through internally generated funds and additional short- and long-term borrowings. Subject to the outcome of the regulatory, legislative and legal proceedings discussed above, the Company expects that, barring a future impairment of the capital markets or its access to such markets, it has or can obtain adequate sources of financing to meet its projected cash requirements over the next 12 months. As noted above, adverse developments in regulatory, legislative or legal proceedings could alter these conclusions. The Company's ratio of earnings to fixed charges for the nine and 12 months ended September 30, 2018 was 2.06 and 0.08, respectively. Consolidated SCE&G's ratio of earnings to fixed charges for the nine and 12 months ended September 30, 2018 was 2.39 and (0.31), respectively. These ratios reflect impairment losses recorded in 2017 and 2018 related to the Nuclear Project, which are discussed in Note 10 to the condensed consolidated financial statements and in SCANA's and SCE&G's combined Form 10-K for the year ended December 31, 2017. Also, these ratios reflect the 2018 temporary reduction of retail electric rates required by Act 258. See Note 2 and Note 10 to the condensed consolidated financial statements.

 SCANA's ability to pay dividends on its common stock may be limited by existing covenants that limit the right of its subsidiaries to pay dividends on their common stock. Further, SCANA has agreed to obtain the consent of Dominion Energy, which consent cannot be unreasonably withheld, prior to making dividend payments to shareholders greater than $0.6125 per share for any quarter while the Merger Agreement is pending. For each of the quarters ended June 30, 2018, September 30, 2018, and December 31, 2018, SCANA's Board of Directors declared a dividend of $0.1237 per share, which represents an approximately 80% reduction from the dividend paid on common stock for the quarter ended March 31, 2018. The reduction corresponds to the portion of the dividend attributable to SCE&G's electric operations and serves to partially mitigate the liquidity impacts arising from the reduced revenues resulting from the implementation of Act 258. Any determination to pay dividends to holders of SCANA common stock in the future, as well as the amount of any dividend, are subject to approval by the board of directors, and will depend upon many factors that the board of directors deems relevant. Any further or sustained reduction in SCANA's payment of dividends in the future may result in a decline in the value of its common stock. Such a decline in value could limit SCANA's ability to raise equity capital.

Cash requirements for SCANA’s regulated subsidiaries arise primarily from their operational needs, funding their construction programs and payment of dividends to SCANA. The ability of the regulated subsidiaries to replace existing plant investment, to expand to meet future demand for electricity and gas and to install equipment necessary to comply with environmental regulations, will depend on their ability to attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their ongoing construction programs, rate increases will be sought. The future financial position and results of operations of regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief.

Rating agencies consider qualitative and quantitative factors when assessing SCANA and its rated operating companies’ credit ratings, including the legislative and regulatory environment, capital structure and the ability to meet liquidity requirements. As previously noted, adverse developments with respect to recovery of Nuclear Project costs have negatively affected the Company’s and Consolidated SCE&G's debt ratings. Further adverse developments, changes in the

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legislative and regulatory environment or deterioration of SCANA's or its rated operating companies' commonly monitored financial credit metrics could cause the Company and Consolidated SCE&G to pay higher interest rates on their long- and short-term indebtedness, could limit the Company's and Consolidated SCE&G's access to capital markets and liquidity, and could trigger more stringent collateral requirements on interest rate and commodity hedges and under gas supply agreements and other contracts.

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 ongoing proceedings involving the ORS and Act 258, as well as the pending 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.

Cash provided from operating activities in 2017 and 2018 reflect significant tax benefits (reductions in income tax payments and tax refunds) arising from the deductions previously described under Significant Tax Deductions and Credits. The Company's decision in 2017 to stop construction of Unit 2 and Unit 3 and to abandon the Nuclear Project resulted in a significant tax deduction and an associated NOL for tax purposes. The Company obtained a refund of taxes paid in certain prior years as a result of the carryback of the NOL and expects to benefit from the carryforward of the NOL in future years. These cash flows are expected to fund operations and may be used to reduce short-term borrowings.

Enactment of the Tax Act resulted in the remeasurement of deferred income tax assets and liabilities and the recognition as regulatory liabilities of certain excess deferred income taxes (see Note 2 and Note 6 to the condensed consolidated financial statements). Certain of these regulatory liabilities will be amortized to the benefit of customers over the remaining lives of related property in accordance with the normalization provisions of the IRC and Code of Federal Regulations, thereby mitigating any significant negative cash impact. However, since most of the Company’s and Consolidated SCE&G's businesses are rate regulated, lower income taxes payable in future years due to the Tax Act will also result in lower collections from customers in rates.

Cash flows from investing activities in both periods were primarily related to capital expenditures, and in 2018 include the acquisition of CEC for approximately $180 million. In 2018, investing inflows included proceeds received upon the settlement of certain interest rate swaps.

Cash flows from financing activities in both periods included dividend payments, changes in commercial paper balances and proceeds from the issuance of long-term debt. In 2018, such cash flows included repayments of long-term debt, as well as proceeds from and repayments of draws on long-term credit facilities.

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 at their face value. Funds to pay the notes were primarily borrowings from the utility money pool and a $20 million equity contribution from SCANA.

In June 2018, PSNC Energy issued $100 million of 4.33% senior notes due June 15, 2028. Proceeds from this sale were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.

In June 2017, PSNC Energy issued $150 million of 4.18% senior notes due June 30, 2047. Proceeds from this sale were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.

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OTHER MATTERS

SCANA shareholders approved the Merger Agreement at a special meeting on July 31, 2018. Certain regulatory approvals must be obtained and other conditions must be met before the merger may be consummated.

For information related to environmental matters, nuclear generation, and claims and litigation, see Note 10 of the condensed consolidated financial statements. For information related to the Company's and Consolidated SCE&G's unrecognized tax benefits, see Note 6 of the condensed consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

SCANA:

Interest Rate Risk - Interest rates on all outstanding long-term debt are fixed either through the issuance of fixed rate debt or by interest rate derivatives. The Company is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near future.

For further discussion of changes in long-term debt and interest rate derivatives, including changes in the Company's market risk exposures relative to interest rate risk, see the Liquidity and Capital Resources section in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes 2, 5, 7 and 8 of the condensed consolidated financial statements.

Commodity price risk - The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 7 and 8 of the condensed consolidated financial statements. The following tables provide information about the Company’s financial instruments, which are limited to financial positions of SCANA Energy 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 for these or similar instruments.

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Expected Maturity	2018	2019	2020	2021
Futures - Long
Settlement Price (a)	3.06	2.93	2.82	—
Contract Amount (b)	18.8	50.0	5.6	—
Fair Value (b)	19.3	50.2	5.5	—
Options - Purchased Call (Long)
Strike Price (a)	1.89	2.54	—	—
Contract Amount (b)	7.2	14.8	—	—
Fair Value (b)	0.6	1.3	—	—
Options - Sold Call (Short)
Strike Price (a)	—	0.21	—	—
Contract Amount (b)	—	0.2	—	—
Fair Value (b)	—	0.2	—	—
Swaps - Commodity
Pay fixed/receive variable (b)	2.4	7.1	3.7	0.8
Average pay rate (a)	3.2099	2.9257	2.8451	2.7195
Average received rate (a)	3.0523	2.8341	2.6617	2.7065
Fair value (b)	2.3	6.9	3.5	0.8
Pay variable/receive fixed (b)	8.5	26.1	4.5	—
Average pay rate (a)	3.0542	2.8455	2.6860	—
Average received rate (a)	3.0120	2.8833	2.8351	—
Fair value (b)	8.4	26.5	4.7	—
Swaps - Basis
Pay variable/receive variable (b)	13.0	15.2	—	—
Average pay rate (a)	2.9931	3.0010	—	—
Average received rate (a)	2.9761	2.9997	—	—
Fair value (b)	13.0	15.2	—	—
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of September 30, 2018, management for each of the Registrants has evaluated, with the participation of the CEO and CFO, (a) the effectiveness of the design and operation of disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) and (b) any change in internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act).  Based on this evaluation, the CEO and CFO concluded that, as of September 30, 2018, these disclosure controls and procedures were effective. There has been no change in internal control over financial reporting during the quarter ended September 30, 2018 that has materially affected or is reasonably likely to materially affect internal control over financial reporting for either of the Registrants.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

SCANA and SCE&G:

The following describes certain legal proceedings that originated or have been terminated during the three months ended September 30, 2018 or for which developments have occurred during the period. The Company and Consolidated SCE&G intend to vigorously contest the lawsuits, claims and audit positions or assessments which have been filed or initiated against them. For developments related to these or other proceedings subsequent to September 30, 2018, if any, see Note 2 and Note 10 to the condensed consolidated financial statements in Part I, Item 1. Financial Statements. No reference to, or disclosure of, any proceeding, item or matter described below shall be construed as an admission or indication that such proceeding, item or matter is material or that such proceeding, item or matter is required to be referred to or disclosed in this Form 10-Q.

Ratepayer and RICO Class Actions

In May 2018, certain purported ratepayer class actions were consolidated. These include actions which in previous Exchange Act filings were defined as the Cleckley Lawsuit, the Lightsey Lawsuit, and an action filed by plaintiff Edwinda Goodman. The consolidated complaint is 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 (the "SCE&G Ratepayer Case") and was filed in the State Court of Common Pleas in Hampton County (the "Hampton County Court"). 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 seek a declaratory judgment that SCE&G may not charge its customers for any past or continuing costs of the Nuclear Project. In addition, the plaintiffs also seek to have the defendants’ assets frozen and all monies recovered from Toshiba and other sources be placed in a constructive trust for the benefit of ratepayers. The plaintiffs seek specific performance of the alleged implied contract to construct the now abandoned project, as well as compensatory, punitive and statutory treble damages, attorneys’ fees, and any other relief the court deems proper. On September 20, 2018, the court certified this case as a class action.

On September 7, 2017, a purported class action was filed against Santee Cooper, SCE&G, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. by plaintiff Jessica Cook, on behalf of herself and all others similarly situated (the "Santee Cooper Ratepayer Case") in the Hampton County Court. The plaintiff makes substantially similar allegations as the SCE&G Ratepayer Case. The plaintiff seeks a declaratory judgment that defendants may not charge the purported class for reimbursement for past or future costs of the Nuclear Project, as well as other compensatory and statutory treble damages, attorneys’ fees, and any other relief the court deems proper. On March 27, 2018, the plaintiff and additional named plaintiffs filed an amended complaint including as additional named defendants current and former directors of Santee Cooper and SCANA. On June 25, 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina, which notice was pending at September 30, 2018. Various motions remain pending before the Hampton County Court at September 30, 2018.

On January 31, 2018, a purported class action was filed by Timothy Glibowski, on behalf of himself and all others similarly situated, in the District Court (the "Glibowski Lawsuit"). The action, as subsequently amended on April 23, 2018, is against SCANA, SCE&G, Kevin Marsh, Jimmy Addison, Stephen Byrne, Martin Phalen, Mark Cannon, Russell Harris, Ronald T. Lindsay, James Micali, and Lonnie Carter. The plaintiff alleges, among other things, that the Company, SCE&G and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO 18 U.S.C. §1961 et seq., and conspired to violate RICO 18 U.S.C. §1962(c) by fraudulently inflating utility bills to generate unlawful proceeds. Plaintiff seeks treble damages, attorneys’ fees, and any other relief the court deems proper.

State Court Shareholder Derivative Actions

On September 26, 2017, a purported shareholder derivative action was filed against defendants Kevin Marsh, Gregory Aliff, James Bennett, John Cecil, Sharon Decker, Maybank Hagood, Lynne Miller, James Roquemore, Maceo Sloan, Alfredo Trujillo, Jimmy Addison, Stephen Byrne, and nominal defendant SCANA by plaintiff John Crangle, purportedly on behalf of SCANA, in the State Court of Common Pleas in Richland County, South Carolina (the "Richland County Court") (the "Crangle Lawsuit"). The plaintiff alleges, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the Nuclear Project, and that the defendants Marsh, Addison, and Byrne were unjustly enriched by bonuses they were paid in connection with the project. The plaintiff seeks compensatory and consequential damages, attorneys’ fees, and any other relief the court deems proper. On January 8, 2018, the court notified the parties that the Crangle Lawsuit

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and the Todd Lawsuit (as hereinafter defined) would be transferred to the Business Court Pilot Program in Richland County. On March 5, 2018, Defendants' Motion to Stay these shareholder derivative actions pending the resolution of the ongoing related regulatory proceedings, ratepayer class actions, securities class actions, and government investigations was denied. On September 6, 2018, the court denied Defendants' motions to dismiss based on rules 23(b)(1) and 12(b)(6), and stated it would hold in abeyance Defendants' motions to dismiss based on Rule 12(b)(8) in favor of the pending federal derivative action for decision at a later date. On September 18, 2018, the Crangle Lawsuit and the Todd Lawsuit were consolidated.

On October 30, 2017, a purported shareholder derivative action was filed by plaintiff R. Wayne Todd, purportedly on behalf of SCANA, in Richland County Court (the “Todd Lawsuit”). The defendants named in the Todd Lawsuit are identical to those of the Crangle Lawsuit. The plaintiff also makes substantially similar allegations as those alleged in the Crangle Lawsuit, and alleges that the defendants Marsh, Addison, and Byrne were unjustly enriched by bonuses they were paid in connection with the Nuclear Project. The plaintiff seeks compensatory and consequential damages, punitive damages, attorneys’ fees, and any other relief the court deems proper. On September 6, 2018, the court denied Defendants' motions to dismiss based on rules 23(b)(1) and 12(b)(6), and stated it would hold in abeyance Defendants' motions to dismiss based on Rule 12(b)(8) in favor of the pending federal derivative action for decision at a later date. On September 18, 2018, the Crangle Lawsuit and the Todd Lawsuit were consolidated.

On December 13, 2017, a purported shareholder derivative action was filed against Kevin Marsh, Jimmy Addison, Stephen Byrne, Maybank Hagood, Lynne Miller, James Bennett, Maceo Sloan, Sharon Decker, James Roquemore, Alfredo Trujillo, John F.A.V. Cecil, Gregory Aliff, James Micali, Harold Stowe, and nominal defendant SCANA by plaintiff Firemen's Retirement System of St. Louis, purportedly on behalf of SCANA, in the Richland County Court. The plaintiff makes substantially similar allegations as those alleged in the Crangle and Todd Lawsuits. On January 12, 2018, the suit was amended to add Dominion Energy and Sedona as defendants and to assert putative class action claims alleging, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that unfairly deprived plaintiffs of the true value of their SCANA stock, and that Dominion Energy and Sedona aided and abetted these actions. On February 21, 2018, Dominion Energy removed the case to the District Court. On June 27, 2018, the case was remanded back to the Richland County Court. On July 11, 2018, Plaintiff filed a Notice of Voluntary Dismissal without Prejudice, effectively ending this case.

On January 23, 2018, a purported class action was filed against SCANA, Dominion Energy, Sedona, Jimmy Addison, Gregory Aliff, James Bennett, John Cecil, Sharon Decker, Maybank Hagood, Lynne Miller, James Roquemore, Maceo Sloan, and Alfredo Trujillo, by plaintiff City of Warren Police and Fire Retirement System (the "City of Warren Lawsuit") in the State Court of Common Pleas in Lexington County, South Carolina (the "Lexington County Court"). 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 and Sedona aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the proposed merger, as well as unspecified monetary damages, attorneys’ fees, costs and any other relief the court deems proper. On February 21, 2018, Dominion Energy removed the case to the District Court, and filed its Motion to Dismiss on March 9, 2018. On June 27, 2018, the case was remanded back to the Lexington County Court. Dominion Energy and Sedona appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with a appeal from the Metzler Lawsuit (as hereinafter defined) and remains pending at September 30, 2018. Motions to stay and to consolidate this case with the Metzler Lawsuit were being held in abeyance at September 30, 2018.

On February 8, 2018, a purported class action was filed against Gregory Aliff, James Bennett, John Cecil, Sharon Decker, Maybank Hagood, Lynne Miller, James Roquemore, Maceo Sloan, Alfredo Trujillo, Dominion Energy, and Sedona by plaintiffs Metzler Asset Management GmbH and Joseph Heinz in the Richland County Court (the "Metzler Lawsuit"). The plaintiffs allege, 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 and Sedona aided and abetted these actions. Among other remedies, the plaintiffs seek to enjoin and/or rescind the proposed merger, as well as unspecified monetary damages, attorneys’ fees, and any other relief the court deems proper. On February 21, 2018, Dominion Energy removed the case to the District Court, and filed its Motion to Dismiss on March 9, 2018. On August 1, 2018, the case was remanded back to the Richland County Court. Dominion Energy and Sedona appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with a appeal from the City of Warren Lawsuit and remains pending at September 30, 2018. Motions to stay and to consolidate this case with the City of Warren Lawsuit were being held in abeyance at September 30, 2018.

Federal Court Shareholder Derivative Actions

On November 21, 2017, a purported shareholder derivative action was filed against Kevin Marsh, Gregory Aliff, James Bennett, John Cecil, Sharon Decker, Maybank Hagood, Lynn Miller, James Roquemore, Maceo Sloan, Aldredo Trujillo,

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Jimmy Addison, Stephen Byrne, and SCANA by plaintiff Colleen Witmer, purportedly on behalf of SCANA in the District Court (the "Witmer Lawsuit"). The plaintiff alleges, 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 the company, and that the individual defendants were unjustly enriched in their compensation. The plaintiff seeks compensatory and consequential damages, disgorgement of compensation, punitive damages, attorneys’ fees, and any other relief the court deems proper. On January 23, 2018, the District Court granted consolidation of the Wickstrom Lawsuit (as hereinafter defined), and the Witmer Lawsuit, and granted plaintiffs’ requests for appointment of lead counsel. The consolidated case is captioned In re SCANA Corporation Derivative Litigation. On January 30, 2018, the plaintiffs filed their consolidated amended complaint. On June 27, 2018, the court denied defendants' motions to dismiss. On July 24, 2018, SCANA filed a Motion to Stay All Proceedings Pending Investigation by a Special Litigation Committee, which motion remained pending at September 30, 2018.

On November 22, 2017, a purported shareholder derivative action was filed against Kevin Marsh, Gregory Aliff, James Bennett, John Cecil, Sharon Decker, Maybank Hagood, Lynn Miller, James Roquemore, Maceo Sloan, Aldredo Trujillo, and SCANA by plaintiff Richard Wickstrom, purportedly on behalf of SCANA in the District Court (the "Wickstrom Lawsuit"). The plaintiff alleges, among other things, that the defendants violated their fiduciary duties to shareholders by affirmatively making and allowing material misstatements to be made to shareholders regarding the Nuclear Project. The plaintiff seeks compensatory and consequential damages, disgorgement of Marsh’s compensation, attorneys’ fees, and any other relief the court deems proper. As noted, on January 23, 2018, this case was consolidated and is captioned In re SCANA Corporation Derivative Litigation.

Federal Court 10b-5 and Merger Actions

On September 27, 2017, a purported class action was filed against SCANA, Kevin B. Marsh, Jimmy E. Addison, and Stephen A. Byrne by plaintiff Robert L. Norman, on behalf of himself and all others similarly situated, in the District Court (the "Norman Lawsuit"). The plaintiff alleges, among other things, that the defendants violated §10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and that the individual named defendants are liable under §20(a) of the Exchange Act. The plaintiff seeks compensatory and consequential damages, attorneys’ fees, and any other relief the court deems proper. On January 23, 2018, the District Court granted consolidation of the Norman Lawsuit, the Evans Lawsuit, the Fox Lawsuit, and the West Palm Beach Lawsuit, (as such terms are hereinafter defined), and granted plaintiffs’ requests for appointment of lead counsel. The consolidated case is captioned In re SCANA Corporation Securities Litigation.The plaintiffs filed a consolidated amended complaint on March 30, 2018. At September 30, 2018, the defendants' motions to dismiss were pending.

On October 5, 2017, a purported class action was filed against SCANA, Kevin B. Marsh, and Jimmy E. Addison by plaintiff Kenneth Evans on behalf of himself and all others similarly situated in the District Court (the "Evans Lawsuit"). The plaintiff makes substantially similar allegations as those alleged in the Norman Lawsuit, and seeks substantially similar relief. As noted, on January 23, 2018, this case was consolidated and is captioned In re SCANA Corporation Securities Litigation.

On November 10, 2017, a purported class action was filed against SCANA, Kevin Marsh, Jimmy Addison, and Steve Byrne by plaintiff Marsha Fox on behalf of herself and all others similarly situated in the District Court (the "Fox Lawsuit"). The plaintiff makes substantially similar allegations as those alleged in the Norman Lawsuit, and seeks substantially similar relief. As noted, on January 23, 2018, this case was consolidated and is captioned In re SCANA Corporation Securities Litigation.

On November 17, 2017, a purported class action was filed against SCANA, Kevin B. Marsh, Jimmy E. Addison, and Steve B. Byrne by plaintiff West Palm Beach Firefighters’ Pension Fund on behalf of itself and all others similarly situated in the District Court (the "West Palm Beach Lawsuit"). The plaintiff makes substantially similar allegations as those alleged in the Norman Lawsuit, and seeks substantially similar relief. As noted, on January 23, 2018, this case was consolidated and is captioned In re SCANA Corporation Securities Litigation.

On March 15, 2018, a purported class action was filed against SCANA, Dominion Energy, Sedona, Jimmy E. Addison, Gregory E. Aliff, James A. Bennett, John F.A.V. Cecil, Sharon A. Decker, D. Maybank Hagood, Lynne M. Miller, James W. Roquemore, Maceo K. Sloan, and Alfredo Trujillo by plaintiff Mary Turner, on behalf of herself and all others similarly situated in the District Court. The plaintiff alleged, among other things, that the defendants violated provisions of Section 14(a) of the Exchange Act and SEC Rule 14a-9 by allowing or causing misleading proxy statements to be issued. The plaintiffs alternatively sought to enjoin the merger, monetary damages, attorneys’ fees, and any other relief the court deemed proper. This lawsuit was settled in September 2018 for an amount that was less than $100,000, and the plaintiff released all of her claims with respect to material facts and omissions that were brought or could have been brought in the lawsuit.

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FILOT Litigation

On November 29, 2017, Fairfield County filed a Complaint and a Motion for Temporary Injunction against SCE&G in the State Court of Common Pleas in Fairfield County, making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of the implied duty of good faith and fair dealing, and unfair trade practices related to SCE&G’s termination of the FILOT agreement between SCE&G and Fairfield County, related to Unit 2 and Unit 3. Plaintiff sought a temporary and permanent injunction to prevent SCE&G from terminating the FILOT; actual and consequential damages; treble damages; punitive damages; and attorneys’ fees. Plaintiff sought a hearing within ten days on their motion for temporary injunction. The court heard arguments on December 15, 2017 on the motion for temporary injunction, and asked the parties to submit supplemental briefing and proposed orders by December 20, 2017. Plaintiff voluntarily withdrew the Motion for Temporary Injunction on December 20, 2017. On April 12, 2018, the court denied SCE&G's Motion to Transfer Venue. At September 30, 2018, the defendant's motion to dismiss was pending.

Regulatory and Governmental Proceedings and Investigations

On January 26, 2018, the DOR notified SCANA that it was initiating an audit of SCE&G's sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The Company and Consolidated SCE&G understand that the DOR's position is that the exemption for sales and use tax for purchases related to the Nuclear Project should not apply because Unit 2 and Unit 3 will not be placed into service and no electricity will be manufactured for sale. On April 6, 2018, SCE&G responded to the DOR in a letter setting out certain reasons why SCE&G believes the exemptions apply and the audit is improper. On June 1, 2018, SCE&G received from the DOR a notice of proposed assessment arising from that audit of approximately $410 million plus $10.9 million in interest. At September 30, 2018, SCE&G intended to file a protest of the proposed assessment. The Company and Consolidated SCE&G intend to vigorously contest the DOR's position.

Employment Class Action and Indemnification

On July 17, 2018, a case filed in the District Court styled Penningtonet al.v. SCANA, Fluor Corporation and Fluor Enterprises was certified as a class action on behalf of persons who were formerly employed at the Nuclear Project. The plaintiffs allege, among other things, that the defendants 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 the case described in the next paragraph.

On September 7, 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against SCE&G and Santee Cooper. The plaintiffs make claims for equitable indemnity, 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 Pennington case. Plaintiffs seek recovery of damages for defense costs, attorneys' fees and expenses and any other relief the court deems proper.

Act 258 and S. 954

On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented.

While the Company and Consolidated SCE&G intend to vigorously contest the lawsuits, claims and audit positions or assessments which have been filed or initiated against them, they cannot predict the timing or outcome of these matters or other claims allegations or assessments which may arise, including any claims that may be asserted by or against Santee Cooper.

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ITEM 1A. RISK FACTORS

The risk factors from the Registrants' combined Annual Report on Form 10-K for the year ended December 31, 2017, and Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, have been updated and are restated below in their entirety.

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

The completion of the merger is subject to the receipt of consents, approvals and/or findings from governmental entities, which may impose conditions that could have an adverse effect on Dominion Energy or SCANA or could cause either Dominion Energy or SCANA to terminate the merger. The completion of the merger is also subject to there having not been certain substantive changes in certain South Carolina laws that have or would reasonably be expected to have an adverse effect on SCANA or its subsidiaries or changes in law that impose any condition that would reasonably be expected to result in specified changes to the Joint Petition. Additionally, any such changes in certain South Carolina law could affect the considerations which were relied upon by SCANA and/or Dominion Energy prior to the signing of the Merger Agreement.

Dominion Energy and SCANA are not required to complete the merger until after the requisite authorizations, approvals, consents and/or permits are received from the FERC, NRC, SCPSC, NCUC and GPSC. Such approvals have been received from the FERC, NRC and GPSC. Any of the remaining relevant governmental entities may oppose the merger, fail to approve the merger, fail to make required findings in favor of the merger, or impose certain requirements or obligations as conditions for their consent, approval or findings or in connection with their review. Regulatory approvals of the merger or findings with respect to the merger may not be obtained on a timely basis or at all, and such approvals or findings may include conditions that could have an adverse effect on the Company or Consolidated SCE&G, and/or result in the termination of the merger. No assurance can be given that the necessary approvals or findings will be obtained or that any required conditions will not have an adverse effect on Dominion Energy following the merger. Notwithstanding the approval of the Merger Agreement by SCANA shareholders at a special meeting on July 31, 2018, Dominion Energy or SCANA may make decisions after the special meeting to waive a condition or approve certain actions required to obtain regulatory approvals or findings without seeking further approval of the SCANA shareholders.

Subject to the terms and conditions set forth in the Merger Agreement, the Merger Agreement requires Dominion Energy to accept conditions from regulators that could adversely impact Dominion Energy after the merger without either of Dominion Energy or SCANA having the right to refuse to close the merger on the basis of those regulatory conditions, except that Dominion Energy is generally not required, and SCANA is generally not permitted without Dominion Energy’s prior approval, to take any action or accept any condition that would be burdensome.

In addition, the Merger Agreement provides that Dominion Energy (but not SCANA) will have the right to refuse to complete the merger if, since the date of the Merger Agreement, any governmental entity shall have enacted any order, or there shall have been any change in law (including the BLRA and the other laws governing South Carolina public utilities), which imposes any material change to the terms, conditions or undertakings set forth in the Joint Petition, or any significant changes to the economic value of the Joint Petition, in each case as determined by Dominion Energy in good faith. The Merger Agreement further provides that Dominion Energy (but not SCANA) will have the right to refuse to complete the merger if there shall have occurred any substantive change in the BLRA or other laws governing South Carolina public utilities which has or would reasonably be expected to have an adverse effect on SCANA or any of its subsidiaries. One such law (Act 258) could affect the economic value of the Joint Petition. Act 258 also makes substantive changes to the BLRA and orders the SCPSC to temporarily reduce collections from rates previously approved by the SCPSC under the BLRA. SCE&G has filed a lawsuit in the District Court challenging the constitutionality of Act 258. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented.

Certain lawsuits and regulatory actions have been filed against SCANA and SCE&G, and several motions are currently pending, in connection with the abandonment of the Nuclear Project. If the relief requested in these matters (including a request for declaratory judgment that the BLRA is unconstitutional) is granted, Dominion Energy might not be obligated to complete the merger. Further, in testimony filed in connection with the Concurrent Dockets, a representative of Dominion Energy noted that there is currently pending litigation in the South Carolina state courts where the judge has indicated that he is considering issuing an order that would violate the "no change in law" provision of the Merger Agreement, and that if such an order were issued, the merger would be unable to close. See Claims and Litigation in Note 10 to the condensed consolidated

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financial statements in Part I, Item 1. Financial Statements for additional discussion regarding the constitutionality of the BLRA.

No assurance can be given that these risks will not materialize and either adversely impact Dominion Energy after the completion of the merger or, if the merger is terminated because the required authorizations, approvals, consents and/or permits are not obtained or received or Dominion Energy so elects because such conditions rise to the thresholds described above, adversely impact the results of operations, cash flows and financial conditions of the Company and Consolidated SCE&G.

Failure to complete the merger could negatively impact the stock price and the future business and financial results of SCANA.

If the merger is not completed, the ongoing business of the Company and Consolidated SCE&G may be adversely affected and the Company and Consolidated SCE&G could be subject to several risks, including the following:

• the price of SCANA common stock may decline to the extent that the current market price reflects an expectation by the market that the merger will be completed;

• obligations to pay certain costs relating to the merger, such as legal, accounting and financial advisory fees, among others;  

• the disruption of the Company’s and Consolidated SCE&G’s ongoing business or inconsistencies in its services, standards, controls, procedures and policies due to management’s focus on the merger, any of which could adversely affect the ability of the Company and Consolidated SCE&G to maintain relationships with customers, regulators, vendors and employees, or could otherwise adversely affect the business and financial results of the Company or Consolidated SCE&G, without realizing any of the benefits of having the merger completed;

• the potential negative impact on the Company and Consolidated SCE&G of ultimately resolving the rate and regulatory issues, including pending investigations and legal challenges, relating to the abandonment of the Nuclear Project in a manner satisfactory to SCANA on account of SCANA working with Dominion Energy to pursue the resolution of these issues as contemplated by the Merger Agreement rather than pursuing its regulatory and legal options for resolving these issues independently of considerations and obligations related to the merger; and

• the loss of other opportunities that could be beneficial to the Company and Consolidated SCE&G that could have been pursued during the pendency of the merger, without realizing any of the benefits of having the merger completed.

In addition to the above risks, SCANA may be required, under certain circumstances, to pay to Dominion Energy a termination fee of $240 million.

If the merger is not completed, no assurance can be given that these risks will not materialize and will not materially adversely affect SCANA's business, financial results and stock price.

The Merger Agreement contains provisions that limit SCANA’s ability to pursue alternatives to the merger, which could discourage a potential competing acquirer of SCANA or could result in any competing proposal being at a lower price than it might otherwise be.

The Merger Agreement contains provisions that, subject to certain exceptions, restrict SCANA’s ability to initiate, solicit, knowingly encourage, facilitate or discuss competing third-party proposals to acquire all or a significant part of SCANA, or provide information to a third party that could reasonably be expected to lead to such a proposal. In addition, Dominion Energy generally has an opportunity to offer to modify the terms of the merger in response to any superior acquisition proposal that may be made before the SCANA board of directors is permitted to withdraw or qualify its recommendation. In some circumstances on termination of the Merger Agreement, SCANA may be required to pay to Dominion Energy a termination fee of $240 million.

These provisions, which the SCANA board regards as customary for transactions of this type, could discourage a potential competing acquirer that might have an interest in acquiring all or a significant part of SCANA from considering or proposing that acquisition, even if it were prepared to pay consideration with a higher per share cash or market value than the merger consideration, or might result in a potential competing acquirer proposing to pay a lower price than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable by SCANA in certain circumstances.

The pendency of the merger could adversely affect the business and operations of SCANA.

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In connection with the pending merger, some current or prospective customers or vendors of SCANA’s utilities may delay or defer decisions regarding their existing or proposed relationships with those utilities, which could negatively impact the operations, revenues, earnings, cash flows and expenses of the Company and Consolidated SCE&G, regardless of whether the merger is completed. Similarly, current and prospective employees of SCANA and its utilities may experience uncertainty about their future roles following the merger, which may adversely affect the ability of SCANA and its utilities to attract and retain key personnel during the pendency of the merger. In addition, due to operating covenants in the Merger Agreement or as a result of the regulatory and political uncertainties otherwise described herein, during the pendency of or following the merger, SCANA and its utilities may be unable to pursue strategic transactions, undertake significant capital projects, undertake certain significant financing or other specified transactions or pursue actions that are not in the ordinary course of business, even if such actions would prove beneficial.

Following the merger, Dominion Energy may be unable to successfully integrate the Company’s and Consolidated SCE&G’s businesses.

Dominion Energy and SCANA currently operate as independent public companies. After the merger, Dominion Energy will be required to devote significant management attention and resources to integrating the Company’s and Consolidated SCE&G’sbusiness. Potential difficulties Dominion Energy may encounter in the integration process include the following:

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

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

• the inability to attract and retain key employees;

• potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the merger;

• difficulties in managing political and regulatory conditions related to SCANA’s utility businesses after the merger;

• the cost recovery plan outlined in the Joint Petition includes a moratorium on filing requests for adjustments in SCANA’s base electric rates until 2021 if the merger is approved by the SCPSC, which would limit Dominion Energy’s ability to recover increases in non-fuel related costs of electric operations for SCE&G’s customers;

• the stipulation agreement filed with the NCUC 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 Dominion Energy management’s attention caused by completing the merger and integrating SCANA’s utility businesses.

For these reasons, it is possible that the integration process following the merger could result in the distraction of Dominion Energy’s management, the disruption of Dominion Energy’s ongoing business or inconsistencies in its services, standards, controls, procedures and policies, any of which could adversely affect the ability of Dominion Energy to maintain or establish relationships with current and prospective customers, vendors and employees or could otherwise adversely affect the business and financial results of Dominion Energy.

Dominion Energy, the Company and Consolidated SCE&G have been and may continue to be adversely affected by negative publicity related to the merger and in connection with other related matters, including the abandonment of the Nuclear Project.

Political and public sentiment in connection with the merger and in connection with other matters, including the abandonment of the Nuclear Project, have resulted in and may continue to result in a significant amount of adverse press coverage and other adverse public statements affecting Dominion Energy and 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 further investigations by regulators, legislators and law enforcement officials or in legal claims. 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 Dominion Energy’s, 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 Dominion Energy, 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

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publicity, and the demands of responding to and addressing it, may have an adverse effect on Dominion Energy’s, the Company’s and Consolidated SCE&G’s respective businesses, financial condition, results of operations and prospects.

Pending litigation against SCANA and Dominion Energy could result in an injunction preventing the completion of the merger or requiring the Merger Agreement to be amended, or may require the payment of monetary damages or may adversely affect the combined company’s business, financial condition or results of operations following the merger.

Following the announcement of the merger, multiple lawsuits were filed asserting claims relating to the merger. Purported class actions on behalf of SCANA shareholders have been filed in the Court of Common Pleas of the Counties of Lexington and Richland, South Carolina, respectively, and in the District Court against SCANA, the members of the SCANA board of directors, Dominion Energy and Sedona, and certain current and former officers of SCANA, alleging breaches of various fiduciary duties by the members of the SCANA board of directors in connection with the merger and alleging that SCANA, Dominion Energy and Sedona aided and abetted such alleged breaches. Plaintiffs also allege that SCANA, SCE&G and individual defendants violated or conspired to violate RICO. Among other remedies, the plaintiffs seek to enjoin the merger and rescind the Merger Agreement or to have the Merger Agreement amended to provide more favorable terms for plaintiffs, monetary damages, attorney's fees and such further relief as the court deems proper or, in certain cases, seeking compensatory and consequential damages.

While the defendants believe that dismissal is warranted, the outcome of any such litigation is inherently uncertain. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect the combined company’s business, financial condition or results of operations.

There is uncertainty as to whether the Company and Consolidated SCE&G will be able to recover costs expended for the Nuclear Project, and a reasonable return on those costs, under the abandonment provisions of the BLRA or through other means. In 2017 the Company and Consolidated SCE&G recognized a significant estimated impairment loss with respect to such investment and related costs. In the event the Company and Consolidated SCE&G were to determine that all or an additional portion of their remaining unrecovered Nuclear Project and related costs are probable of being disallowed and that significant additional impairment losses must be recognized, further material adverse impacts on their results of operations, cash flows and financial condition would occur.

During the term of the Interim Assessment Agreement, SCE&G and Santee Cooper evaluated the various elements of the Nuclear Project, including forecasted costs and completion dates, while construction continued, and SCE&G and Santee Cooper continued to make payments for such work. Based on this evaluation, and in light of Santee Cooper's decision to suspend construction, on July 31, 2017, the Company determined to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs incurred in connection with such construction under the abandonment provisions of the BLRA or through other means. On July 31, 2017, SCE&G gave WEC a five-day notice of termination of the Interim Assessment Agreement, and notified WEC of its determination to stop construction of Unit 2 and Unit 3.

On August 1, 2017, SCE&G senior management provided an allowable ex parte briefing to the SCPSC regarding the Nuclear Project and this decision, and SCE&G also filed a petition with the SCPSC which included its plan of abandonment and certain proposed actions which would mitigate related customer rate increases, including a proposal to return to customers the net value of the proceeds received by SCE&G under or arising from the Toshiba Settlement.

The BLRA provides that, in the event of abandonment prior to plant completion, costs incurred, including AFC, and a return on those costs may be recoverable through rates, if the SCPSC determines that the decision to abandon the Nuclear Project was prudent. Through its August 1, 2017 petition, SCE&G had sought recovery of such costs expended on the construction of the project, including certain costs incurred subsequent to SCE&G's last revised rates update, and a reasonable return on those costs, and certain other costs under the abandonment provisions of the BLRA. Subsequently, SCE&G’s management met with various stakeholders and members of the South Carolina General Assembly, including legislative leaders, to discuss the abandonment of the Nuclear Project and to hear their concerns. In response to those concerns, and to allow for adequate time for governmental officials to conduct their reviews, SCE&G voluntarily withdrew its August 1, 2017 petition from the SCPSC on August 15, 2017.

In August 2017, special committees of the South Carolina General Assembly, both in the House of Representatives and in the Senate, began conducting public hearings regarding the decision to abandon the Nuclear Project. Members of SCE&G's senior management, along with representatives from Santee Cooper, the ORS and other interested parties, testified before these committees. Several legislative proposals adverse to the Company and Consolidated SCE&G resulted from the work of these committees, two of which became law in 2018 and are described below.

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In September 2017, the Company was served with a subpoena issued by the United States Attorney’s Office for the District of South Carolina seeking documents relating to the Nuclear Project. The subpoena requires the Company to produce a broad range of documents related to the project. Also, SLED is conducting a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. In October 2017, the staff of the SEC's Division of Enforcement also issued a subpoena for documents related to an investigation they are conducting related to the Nuclear Project. These investigations are ongoing, and the Company and Consolidated SCE&G intend to fully cooperate with them. No assurance can be given as to the timing or outcome of these matters. Also 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 one or more 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.

On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, and in reliance on the opinion from the Office of Attorney General, the ORS filed the Request seeking an order from the SCPSC directing SCE&G to immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS that should have been disclosed and that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections. On October 17, 2017, the ORS filed a motion with the SCPSC to amend the Request, in which motion the ORS asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. See Claims and Litigation in Note 10 to the condensed consolidated financial statements and herein for additional discussion regarding the constitutionality of the BLRA.

On December 20, 2017, the SCPSC denied a motion by SCE&G to dismiss the Request and the SCPSC requested that the ORS carry out an inspection, audit and examination of SCE&G's revenue requirements to assist the SCPSC in determining whether SCE&G's present schedule of rates is fair and reasonable. Parties which have intervened in the Request or which filed a letter in support of it include the state's Governor, Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, Santee Cooper, the SCEUC, certain large industrial customers, and several environmental groups. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets regarding the merits of the Joint Petition and related issues. This schedule was established in response to legislation (Act 258 and S. 954) described below. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the timing or outcome of this matter.

On September 27, 2017, certain scheduled payments under the Toshiba Settlement were purchased by Citibank, including amounts related to certain liens that SCE&G was contesting but for which SCE&G may ultimately have been liable. This transaction, together with an October 2017 payment received from Toshiba, resulted in the receipt of $1.997 billion (approximately $1.098 billion for SCE&G's 55% share). A regulatory liability has been recorded on the condensed consolidated balance sheets to reflect the amount related to the Toshiba Settlement that will be utilized to benefit SCE&G's customers in a manner to be determined by the SCPSC. It is possible that the outcome of regulatory or legal proceedings could result in requiring SCE&G's share of these proceeds to be placed in escrow pending their final disposition, or could require these proceeds to be refunded to customers in the near-term or otherwise make these funds unavailable to SCE&G. If any of these circumstances were to arise, it is anticipated that SCE&G may issue commercial paper, draw on its credit facilities or issue long-term debt to fund such requirement. However, such sources may not be available. Any such requirement would significantly harm the Company's and Consolidated SCE&G's results of operations, cash flows and financial condition. In addition, 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.

On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA related to the Nuclear Project. Act 258 requires the SCPSC to order a reduction in 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%, or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On July 2 and 3, 2018, the SCPSC issued orders implementing the temporary rate reduction required by Act 258, and the resulting new rates and retroactive credits required by Act 258 were put into effect in August 2018. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 alters various procedures

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previously applicable under the BLRA, including redefining the standard of care required by the BLRA 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.

On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented.

In 2017, SCE&G recorded a pre-tax impairment loss of $1.118 billion related to unrecovered nuclear project costs and other related costs. In the first quarter of 2018, SCE&G recorded an additional pre-tax impairment loss of $3.6 million related to the fair value of nuclear fuel. These impairment losses have had the effect of increasing the Company's and Consolidated SCE&G's ratio of debt to total capitalization. If the SCPSC were to rule in favor of the ORS in response to the Request that SCE&G suspend collections from customers of amounts previously authorized under the BLRA, or were other actions of the SCPSC or others taken in order to significantly restrict SCE&G’s access to revenues or impose additional adverse refund obligations on SCE&G, the Company’s and Consolidated SCE&G's assessments regarding the recoverability of all or a portion of the remaining balance of unrecovered Nuclear Project costs would be adversely impacted. Resulting additional pre-tax impairment losses and other charges could total approximately $5.0 billion. Also, the recognition of significant additional impairment losses with respect to unrecovered Nuclear Project or other related costs could further increase the Company’s and Consolidated SCE&G’s ratio of debt to total capitalization to a level which could constitute a default under their credit facilities. If such a default occurred, the Company and Consolidated SCE&G would be unable to borrow under their commercial paper programs or, absent a waiver from lenders, under their credit facilities. Borrowing costs for long-term debt issuances and access to capital markets could also be negatively impacted.

In addition to the matters above, in the Joint Petition, the Company and Consolidated SCE&G proposed to remove from BLRA capital costs their investment in transmission assets that have been or will be placed in service and have not been abandoned. As of September 30, 2018, such investment in these assets total approximately $376 million (approximately $365 million within utility plant, net and approximately $11 million within regulatory assets, which amount represents certain deferred operating costs). The Company and Consolidated SCE&G believe that this investment represents assets that are or will be used to provide electric service to customers and that a recovery of and a reasonable return on the investment should be provided in future rates. During the hearing on the Concurrent Dockets, the SCPSC will consider a request by the ORS to allow the Company and Consolidated SCE&G to defer certain operating costs related to the investment and that a decision on the recovery of this investment, including operating costs deferrals, be addressed in a future rate proceeding. If the SCPSC were to disallow recovery of or a reasonable return on all or a portion of this investment, an impairment charge related to these assets totaling as much as approximately $376 million may be required.

The ability of SCE&G to recover its costs related to the construction and subsequent abandonment of the Nuclear Project, and a reasonable return on them, through rates will be subject to review and approval by the SCPSC. An application under the abandonment provisions of the BLRA, and the regulatory process contemplated thereby, have never been pursued or legally challenged. As a result, and in light of recently enacted legislation such as Act 258 and S. 954, the contentious nature of activities involving the General Assembly and other officials, and the Request being considered by the SCPSC, it is uncertain whether SCE&G will be able to successfully recover the costs of the abandoned units, and a reasonable return on them. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets regarding the merits of the Joint Petition and related issues. In any case, appeals of any ruling by the SCPSC in a contested matter which is not resolved through settlement by all involved parties could be protracted. Further, should the regulatory construct in South Carolina change in such a manner that recovery is sought through other legal proceedings or through regulatory proceedings outside the provisions of the BLRA, such as in a general rate case, other uncertainties may arise, such as those highlighted with respect to the Merger Agreement.

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Further downgrades in the credit ratings of SCANA or any of SCANA’s subsidiaries, including SCE&G, could negatively affect our ability to access capital and to operate our businesses, thereby adversely affecting results of operations, cash flows and financial condition.

Various rating agencies currently rate SCE&G’s senior secured debt and the senior unsecured debt of PSNC Energy as investment grade, and each of the rating agencies currently rate SCANA’s senior unsecured debt as below investment grade. In addition, rating agencies maintain ratings on the short- and long-term debt of SCANA, SCE&G and PSNC Energy and the short-term debt of Fuel Company (which ratings are based upon the guarantee of SCE&G). Rating agencies consider qualitative and quantitative factors when assessing SCANA and its rated operating companies’ credit ratings, including regulatory environment, capital structure and the ability to meet liquidity requirements.

In the first quarter of 2017, the rating agencies placed SCANA and SCE&G’s credit ratings on negative outlook or watch status due to adverse developments relating to the WEC bankruptcy. In the third quarter of 2017, two agencies lowered their ratings for SCANA and its rated subsidiaries, citing a decline in the regulatory environment as a principal reason for the downgrades, and both agencies maintained their negative outlook. On January 3, 2018, after SCANA announced a proposed merger with Dominion Energy, each of the three agencies affirmed or reported no change to their respective credit ratings, and one agency revised its rating outlook for SCANA and its rated operating companies from negative to evolving. However, on January 31, 2018, the South Carolina House of Representatives overwhelmingly approved a bill (which later would become Act 258) designed to temporarily repeal rates SCE&G collects under the BLRA. As a result, on February 5, 2018, one agency downgraded its ratings for SCANA and SCE&G, and attributed the downgrade to the passage of this bill and the politically charged environment that is expected to weigh heavily on any decisions by the SCPSC related to SCE&G's electric rates. After Act 258 became law, on July 2 and 3, 2018, the agencies affirmed their ratings; however, one agency changed its outlook from review to negative. On August 8 and 9, 2018, two agencies downgraded their respective ratings for SCANA, SCE&G and PSNC Energy, citing the August 5, 2018, denial by the District Court of SCE&G's motion for a preliminary injunction to prevent the implementation of Act 258. As a result, all of the ratings for SCANA, SCE&G and PSNC Energy have either a negative or evolving outlook, indicating that the ratings are being scrutinized for possible rating actions either currently or dependent on the outcome of uncertain future events.

Any actions taken by or anticipated to be taken by regulators, legislators or a court in any matter of litigation that are viewed as adverse, including a further change to or repeal of the BLRA (or adverse finding as to its constitutionality) or a requirement that SCE&G make additional credits to future bills or refunds to customers or any requirement that SCE&G make such credits or refunds in the absence of the merger being consummated, or deterioration of our rated companies’ commonly monitored financial credit metrics and additional adverse developments with respect to the Nuclear Project, could further negatively affect their debt ratings. If these rating agencies were to further lower any of these ratings, borrowing costs on new issuances of long-term debt and commercial paper would increase, which could adversely impact financial results, and refinancing opportunities would be limited or eliminated to the extent that the potential pool of investors and funding sources decreased. Any further lowering of these ratings could also trigger higher interest costs as well as more stringent collateral requirements or additional deposits or credit support on interest rate and commodity hedges and under gas supply agreements and a reduction in the availability of suppliers.

The Company and Consolidated SCE&G are defendants in numerous legal proceedings and the subject of ongoing governmental investigations, examinations and other inquiries stemming from the decision to abandon the Nuclear Project. The outcome of each of these matters is uncertain, and any resolution adverse to the Company and Consolidated SCE&G could adversely affect results of operations, cash flows and financial condition.

Following the Company’s decision to abandon construction of Unit 2 and Unit 3, purported derivative and class action lawsuits have been filed in multiple state circuit courts and federal district court on behalf of customers, shareholders and SCANA (in the case of the derivative shareholder actions), against SCANA, SCE&G, or both, and in certain cases some of their officers and/or directors. The plaintiffs allege various causes of action, including waste, breach of fiduciary duty, negligence, unfair trade practices, unjust enrichment, conspiracy, fraud, constructive fraud, misrepresentation and negligent misrepresentation, promissory estoppel, constructive trust, and money had and received, among other causes of action. Plaintiffs generally seek compensatory, consequential and statutory treble damages and such further relief as the court deems just and proper. In addition, certain plaintiffs seek a declaration that SCE&G may not charge its customers to reimburse itself for past and continuing costs of the Nuclear Project. Certain plaintiffs also seek to freeze or appoint a receiver for certain of SCE&G’s assets, namely all money SCE&G has received under the Toshiba payment guaranty and related settlement agreement for the Nuclear Project.

On October 15, 2018, in an email to counsel of record in the customer class action, the state court judge provided instructions to counsel for the State of South Carolina and the plaintiffs to submit proposed orders to him.  Those instructions

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directed the attorneys to include language in the proposed orders stating, among other things, that the BLRA violates the hearing requirement of the procedural due process provisions Article I, Section 22 of the South Carolina Constitution.The proposed orders have been submitted to the judge by those attorneys, and SCANA and SCE&G have provided the judge with comments to various portions of the proposed orders.  In a later email to counsel dated October 22, 2018, the judge indicated that he was still considering his analysis of the applicable law, and he sought further input from all parties.  The judge made clear that his emails were not binding judicial orders but merely an indication of how the judge was then considering the matters he had taken under advisement. The judge has not yet entered an official, binding order, and he has not indicated when he intends to do so. The judge’s emails do not indicate what, if any, remedy is available tothe customer class action plaintiffs should he enter an order finding that the BLRA offers insufficient due process to meet the hearing requirement of Article I, Section 22 of the South Carolina Constitution.  SCANA and SCE&G will evaluate the court’s order when it is entered and, if it is adverse to SCANA and SCE&G, will determine whether to seek reconsideration or appeal.

Purported class action lawsuits have been filed on behalf of investors in federal court against SCANA and certain of its current and former executive officers and directors. The plaintiffs allege, among other things, that defendants violated Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder and RICO. The plaintiffs in each of these suits seek compensatory and consequential damages and such further relief as the court deems proper. The plaintiffs also allege, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that unfairly deprived plaintiffs of the true value of their SCANA stock, and that Dominion Energy and Sedona aided and abetted these actions. Among other remedies, the plaintiffs seek to enjoin the merger and rescind the Merger Agreement or to have the Merger Agreement amended to provide more favorable terms for plaintiffs, monetary damages, attorneys' fees and such further relief as the court deems proper.

Lawsuits seeking class action status have also been filed on behalf of investors and shareholder derivative actions have been filed in the Court of Common Pleas in the Counties of Lexington and Richland, South Carolina, against SCANA, its CEO and directors, Dominion Energy and Sedona. Following removal of certain of these class action lawsuits and shareholder derivative actions from state courts to federal court and their subsequent remand, Dominion Energy has filed appeals of the decisions to remand to the Court of Appeals, where the appeals have been consolidated and remain pending.

On July 13, 2018, SCANA’s Board of Directors elected two new, independent directors and exercised its right under South Carolina corporate law to form an SLC comprised solely of these newly elected members to investigate the Derivative Litigation and to determine SCANA’s best interests with respect to these actions. On July 24, 2018, SCANA, acting at the direction of the SLC, filed a motion to stay all federal court proceedings in the Derivative Litigation (In Re SCANA Corporation Derivative Litigation) to allow time for the SLC to conduct an independent investigation into the facts and circumstances giving rise to the Derivative Litigation, and to determine what course of action is in the best interests of SCANA and its shareholders with respect to the Derivative Litigation (e.g., prosecution of the claims in the name of SCANA, seeking dismissal of some or all of the claims, or taking other remedial actions). On October 31, 2018, the court denied the motion to stay with leave to refile after the SCPSC decision on the merger among Dominion Energy, Sedona and SCANA.

On July 17, 2018, a case filed in the District Court styled Penningtonet al.v. SCANA, Fluor Corporation and Fluor Enterprises was certified as a class action on behalf of persons who were formerly employed at the Nuclear Project. The plaintiffs allege, among other things, that the defendants violated the WARN Act in connection with the decision to stop construction on 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 the case described in the next paragraph.

On September 7, 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against SCE&G and Santee Cooper. The plaintiffs make claims for equitable indemnity, 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 Pennington case. Plaintiffs seek recovery of damages for defense costs, attorneys' fees and expenses and any other relief the court deems proper.

A complaint has been filed by Fairfield County against SCE&G making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of the implied duty of good faith and fair dealing, and unfair trade practices related to SCE&G’s termination of the FILOT agreement. Plaintiff seeks injunctive relief to prevent SCE&G from terminating the FILOT agreement; actual and consequential damages; treble damages; punitive damages; and attorneys’ fees.

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The Company has also been 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.

The DOR has initiated an audit of SCE&G's sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The DOR's position is that the exemption for sales and use tax for purchases related to the Nuclear Project should not apply because Unit 2 and Unit 3 will not be placed into service and no electricity will be manufactured for sale. On June 1, 2018, SCE&G received from the DOR a notice of proposed assessment arising from that audit of approximately $410 million, plus interest. SCE&G has filed a protest of the proposed assessment.

While the Company and Consolidated SCE&G intend to vigorously contest the lawsuits, claims, and audit positions or assessments which have been filed or initiated against them, they cannot predict the timing or outcome of these matters or other claims, allegations or assessments which may arise, including any claims that may be asserted by or against Santee Cooper in addition to claims made by Santee Cooper in connection with the Joint Petition, and it is possible that adverse outcomes from some of these matters would not be covered by insurance. A resolution adverse to the Company and Consolidated SCE&G could adversely affect results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G are 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 and which may be considered controversial by the taxing authorities.  The outcome of those uncertainties could adversely impact cash flows, results of operations and financial condition.

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 have 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 have needed to raise in the financial markets. 

The claims made to date are under examination and are considered controversial by the IRS. 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. Additionally, in such circumstances, the Company and Consolidated SCE&G may need to access the capital markets to fund those tax and interest payments, which could in turn adversely impact their ability to access capital markets for other purposes.

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.

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. On August 3, 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. No new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G do not plan to construct new coal-fired units in the foreseeable future. In addition, 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. On October 10, 2017, the Administrator of the EPA signed a notice proposing to

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repeal the rule on the grounds that it exceeds the EPA's statutory authority. 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. In April 2012, the EPA issued the finalized MATS for power plants that requires reduced emissions from new and existing coal and oil-fired electric utility steam generating facilities. The EPA's rule for cooling water intake structures to meet the best technology available became effective in October 2014, and the EPA also issued a final rule in December 2014 regarding the handling of coal ash and other combustion by-products produced by power plant operations. Furthermore, the EPA finalized new standards under the CWA governing effluent limitation guidelines for electric generating units in September 2015. The rule setting forth these new standards has been stayed administratively, and 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 these 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 even 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.

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. The integration of those resources at high penetration levels may be challenging.

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. For example, in effecting compliance with MATS, SCE&G has retired three of its oldest and smallest coal-fired units and converted three others such that they are gas-fired.

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, thereby adversely impacting results of operations, cash flows and financial condition.

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. In addition, the abandonment of the Nuclear Project may heighten the Company's and Consolidated SCE&G's future exposure to volatility in prices of non-nuclear commodities such as natural gas. 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, but purchased power and fuel 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.

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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.

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, thereby adversely impacting results of operations, cash flows and financial condition.

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.

The Company and Consolidated SCE&G are subject to extensive rate regulation which could adversely affect operations. Large capital projects (including the abandonment of Unit 2 and Unit 3 as previously described), results of DSM Programs, results of DER programs, and/or increases in operating costs may lead to requests for regulatory relief and any related administrative or legislative action, decision, regulation or law affecting rates, such as rate increases, which may be denied, in whole or part, by rate regulators. Rate increases may also result in reductions in customer usage of electricity or gas, legislative action and lawsuits. Additionally, in 2018 certain state legislative proposals became law (Act 258 and S. 954) which could lead to adverse impacts on SCE&G’s rate recovery with respect to the Nuclear Project. Furthermore, there can be no assurance that other legislation which might further modify or repeal the BLRA in a manner which would adversely impact SCE&G’s rate recovery, including its reasonable return on costs, with respect to its abandonment of Unit 2 and Unit 3 will not be proposed and passed. Any such action, particularly Act 258 remaining in effect, could also result in a failure to consummate the merger.

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. The ability of SCE&G to recover the cost of the Nuclear Project, including abandonment costs, and a reasonable return on those costs, is subject to rate regulation by the SCPSC. 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

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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, 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.

Our ability to charge customer rates that will allow us to maintain reasonable rates of return is dependent upon regulatory determinations, and there can be no assurance that we will be able to implement rate adjustments when sought.

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. These risks could adversely affect the valuation of our common stock and the Company’s and Consolidated SCE&G’s access to capital.

The Company and Consolidated SCE&G are committed to comply with all laws and regulations, to assure reliability of provided services, to focus on the safety of employees, customers and the public, to ensure environmental compliance, to maintain the physical and cyber security of their operations and assets, to maintain the privacy of information related to our customers and employees, and to maintain effective communications with the public and key stakeholder groups, particularly during emergencies and times of crisis. 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. The Company and Consolidated SCE&G also are committed to operational excellence, to quality customer service, and, through our Code of Conduct and Ethics, 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 valuation of SCANA’s stock, adversely affect the Company’s and Consolidated SCE&G’s access to capital, and result in further regulatory oversight. Insurance may not be available or adequate to respond to these events.

A failure of the Company and Consolidated SCE&G to maintain the physical and cyber security of its operations may result in the failure of operations, damage to equipment, or loss of information, and could result in a significant adverse impact to the Company's and Consolidated SCE&G's financial condition, results of operations and cash flows.

The Company and Consolidated SCE&G depend on maintaining the physical and cyber security of their operations and assets.  As much of our business is part of the nation's critical infrastructure, the loss or physical impairment of the assets associated with that portion of our businesses could have serious adverse impacts on the customers and communities that we serve.  Virtually all of the Company's and Consolidated SCE&G's operations are dependent in some manner upon our cyber systems, which encompass electric and gas operations, nuclear and fossil fuel generating plants, human resource and customer systems and databases, information system networks, and systems containing confidential corporate information. Cyber systems, such as those of the Company and Consolidated SCE&G, are often targets of malicious cyber attacks. A successful physical or cyber attack could lead to outages, failure of operations of all or portions of our businesses, damage to key components and equipment, and exposure of confidential customer, vendor, shareholder, employee, or corporate information. The Company and Consolidated SCE&G may not be readily able to recover from such events. In addition, the failure to secure our operations from such physical and cyber events may cause us reputational damage. Litigation, penalties and claims from a number of parties, including customers, regulators and shareholders, may ensue. Insurance may not be

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adequate to mitigate the adverse impacts of these events. As a result, the Company's and Consolidated SCE&G's financial condition, results of operations, and cash flows may be adversely affected.

The Company and Consolidated SCE&G are vulnerable to interest rate increases, which would increase our borrowing costs, and we may not have access to capital at favorable rates, if at all. Additionally, potential disruptions in the capital and credit markets may further adversely affect the availability and cost of short-term funds for liquidity requirements and our ability to meet long-term commitments; each could in turn adversely affect our results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G rely on the capital markets, particularly for publicly offered debt and equity, as well as the banking and commercial paper markets, to meet our financial commitments and short-term liquidity needs if internal funds are not available from operations. Changes in interest rates affect the cost of borrowing. The Company’s and Consolidated SCE&G’s business plans, which include significant investments in energy generation and other internal infrastructure projects, reflect the expectation that we will have access to the capital markets on satisfactory terms to fund commitments. Moreover, the ability to maintain short-term liquidity by utilizing commercial paper programs is dependent upon maintaining satisfactory short-term debt ratings and the existence of a market for our commercial paper generally.

The Company’s and Consolidated SCE&G’s ability to draw on our respective bank revolving credit facilities is dependent on the ability of the banks that are parties to the facilities to meet their funding commitments and on our ability to timely renew such facilities. Those banks may not be able to meet their funding commitments to the Company or Consolidated SCE&G if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from us and other borrowers within a short period of time. Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our businesses. Any disruption could require the Company and Consolidated SCE&G to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures or other discretionary uses of cash or reducing or eliminating dividend payments. Disruptions in capital and credit markets also could result in higher interest rates on debt securities, limited or no access to the commercial paper market, increased costs associated with commercial paper borrowing or limitations on the maturities of commercial paper that can be sold (if at all), increased costs under bank credit facilities and reduced availability thereof, and increased costs for certain variable interest rate debt securities of the Company and Consolidated SCE&G.

Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy also adversely affect the value of the investments held within SCANA’s pension trust. A significant long-term decline in the value of these investments may require us to make or increase contributions to the trust to meet future funding requirements. In addition, a significant decline in the market value of the investments may adversely impact the Company’s and Consolidated SCE&G’s results of operations, cash flows and financial condition, including its shareholders’ equity.

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.

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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 timeframes, 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.

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. These risks could increase our costs or otherwise constrain our business, thereby adversely impacting our results of operations, cash flows and financial condition.

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 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 and financial aspects of decommissioning nuclear plants at the end of their operating lives.

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 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.

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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 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 Company and Consolidated SCE&G sales and will slow growth, potentially causing higher rates to customers.

The Company and Consolidated SCE&G are subject to risks associated with changes in business and economic climate which could adversely affect revenues, results of operations, cash flows and financial condition and could limit access to capital.

Sales, sales growth and customer usage patterns are dependent upon the economic climate in the service territories of the Company and Consolidated SCE&G, which may be affected by regional, national or even international economic factors. Adverse events, economic or otherwise, may also affect the operations of suppliers and key customers. Such events may result in the loss of suppliers or customers, in higher costs charged by suppliers, in changes to customer usage patterns and in the failure of customers to make timely payments to us. Such events also could adversely impact the results of operations through the recording of a goodwill or other asset impairment. Also, in connection with the pending merger, some customers or vendors of the Company and Consolidated SCE&G may delay or defer decisions, which could negatively impact the revenues, earnings, cash flows and expenses of the Company and Consolidated SCE&G regardless of whether the merger is completed. The success of local and state governments in attracting new industry to our service territories is important to our sales and growth in sales, as are stable levels of taxation (including property, income or other taxes) which may be affected by local, state, or federal budget deficits, adverse economic climates generally, legislative actions (including tax reform), or regulatory actions. Industrial and commercial customer growth also potentially is affected by the availability of "clean" energy options in our service territory. Budget cutbacks also adversely affect funding levels of federal and state support agencies and non-profit organizations that assist low income customers with bill payments.

In addition, conservation and demand side management efforts and/or technological advances, including storage technology, may cause or enable customers to significantly reduce their usage of the Company’s and SCE&G’s products and adversely affect sales, sales growth, and customer usage patterns. For instance, improvements in energy storage technology, if realized, could have dramatic impacts on the viability of and growth in distributed generation.

Factors that generally could affect our ability to access capital, in addition to issues arising from the Nuclear Project and our credit ratings, include economic conditions and our capital structure. Much of our business is capital intensive, and achievement of our capital plan and long-term growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms that are attractive. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition and future results of operations could be adversely impacted.

Problems with operations could cause us to curtail or limit our ability to serve customers or cause us to incur substantial costs, thereby adversely impacting revenues, results of operations, cash flows and financial condition.

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

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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.

SCANA’s ability to pay dividends and to make payments on SCANA’s debt securities may be limited by covenants in certain financial instruments (including the Merger Agreement) and by the financial results and condition of its subsidiaries, thereby adversely impacting the valuation of our common stock and our access to capital.

We are a holding company that conducts substantially all of our operations through our subsidiaries. Our assets consist primarily of investments in subsidiaries. Therefore, our ability to meet our obligations for payment of interest and principal on outstanding debt and to pay dividends to shareholders and corporate expenses depends on many factors, including the earnings, cash flows, liquidity and results of operations, historical and anticipated financial condition, capital requirements, market conditions, growth strategy and the availability of growth opportunities of our subsidiaries, and the ability of our subsidiaries, principally Consolidated SCE&G, PSNC Energy and SCANA Energy, to pay dividends or to repay funds to us. Our ability to pay dividends on our common stock may also be limited by existing or future covenants limiting the right of our subsidiaries to pay dividends on their common stock. Further, SCANA has agreed to obtain the consent of Dominion Energy, which consent cannot be unreasonably withheld, prior to making dividend payments to shareholders greater than $0.6125 per share for any quarter while the Merger Agreement is pending.

For each of the quarters ended June 30, 2018, September 30, 2018, and December 31, 2018, our board of directors declared a dividend that is reduced by approximately 80% from the dividend paid to our shareholders for the quarter ended March 31, 2018. The reduction corresponds to the portion of dividend attributable to SCE&G's electric operations and serves to partially mitigate the liquidity impacts arising from the reduced revenues resulting from the implementation of Act 258. Any determination to pay dividends to holders of our common stock in the future, as well as the amount of any dividend, are subject to approval by our board of directors, and will depend upon many factors, including those described above and other factors that our board of directors deems relevant. Any further or sustained reduction in our payment of dividends in the future may result in a decline in the value of our common stock. Such a decline in value could limit our ability to raise debt and equity capital.

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 margins and adversely affecting results of operations, cash flows and financial condition.

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 abandonment of the Nuclear Project and the pending merger.

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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 proposed merger, also weigh significantly on the 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 are expected to continue to increase at unpredictable rates. Such increases, unless satisfactorily managed by the Company and Consolidated SCE&G, could adversely affect results of operations.

The Company and Consolidated SCE&G are subject to the risk that strategic decisions made by us either do not result in a return of or on invested capital or might negatively impact our competitive position, which can adversely impact our results of operations, cash flows, financial condition, and access to capital.

From time to time, the Company and Consolidated SCE&G make strategic decisions that may impact our direction with regard to business opportunities, the services and technologies offered to customers or that are used to serve customers, and the generating plants and other infrastructure that form the basis of much of our business. These strategic decisions may not result in a return of or on our invested capital, and the effects of these strategic decisions may have long-term implications that are not likely to be known to us in the short-term. Changing political climates and public attitudes, including customers' concerns regarding rate increases, such as the current environment relating to proposed recovery of costs, and a reasonable return on those costs, under the abandonment provisions of the BLRA or through other means, may adversely affect the ongoing acceptability of strategic decisions that have been made (and, in some cases, previously supported by legislation or approved by regulators), to the detriment of the Company or Consolidated SCE&G (e.g., further revision or repeal of the BLRA). In addition, operating covenants in the Merger Agreement require the consent of Dominion Energy prior to SCANA taking certain actions, which consent cannot be unreasonably withheld, during the pendency of the merger. As a result, the Company and Consolidated SCE&G may be unable to pursue strategic transactions, undertake significant capital projects, undertake certain significant financing or other specified transactions or pursue actions that are not in the ordinary course of business even if such actions would prove beneficial. Further, the Company's and Consolidated SCE&G's management and employees may be focused on completion of the merger, which could lead to the disruption of ongoing business or inconsistencies in service, standards, controls, procedures and policies, any of which could adversely affect the ability of the Company and Consolidated SCE&G to maintain relationships with customers, regulators, vendors and employees, or could otherwise adversely affect their business and financial results, without realizing any of the benefits of having the merger completed. Over time, these strategic decisions or changing attitudes toward such decisions, which could be adverse to the Company’s or Consolidated SCE&G’s interests, may have a negative effect on our results of operations, cash flows and financial condition, as well as limit our ability to access capital.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

SCANA:

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 Securities Exchange Act of 1934, as amended (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:

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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
July 1 - 31	9,544	$	39.53	9,544
August 1 - 31	—	—		—
September 1 - 30	—	—		—
Total	9,544			9,544	*

*The preceding 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 and has no stated maximum number of shares that may be purchased and no stated expiration date.

ITEM 5. OTHER INFORMATION

SCANA and SCE&G:

SCANA and SCE&G post information from time to time regarding developments relating to SCE&G’s Nuclear Project and other matters of interest to investors on SCANA’s website at www.scana.com (which is not intended to be an active hyperlink; the information on SCANA’s website is not a part of this report or any other report or document that SCANA or SCE&G files with or furnishes to the SEC).  On SCANA’s homepage, there is a yellow box containing links to the Nuclear and Other Investor Information sections of the website.  The Nuclear section contains a yellow box with a link to project news and updates. The Other Investor Information section of the website contains a link to recent investor-related information that cannot be found at other areas of the website.  Some of the information that will be posted from time to time, including the quarterly reports that SCE&G submits to the SCPSC and the ORS in connection with the Nuclear Project, may be deemed to be material information that has not otherwise become public. Investors, media and other interested persons are encouraged to review this information and can sign up, under the Investor Relations section of the website, for an email alert when there is a new posting in the Nuclear and Other Investor Information yellow box.

ITEM 6. EXHIBITS

SCANA and SCE&G:

Exhibits filed or furnished with this Quarterly Report on Form 10-Q are listed in the following Exhibit Index.

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.

89

EXHIBIT INDEX

	Applicable to Form 10-Q of
Exhibit No.	SCANA	SCE&G	Description
3.01	X		Restated Articles of Incorporation of SCANA, as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
3.02	X		Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-A to Registration Statement No. 33-62421 and incorporated by reference herein)
3.03	X		Articles of Amendment effective April 25, 2011 (Filed as Exhibit 4.03 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.04		X	Restated Articles of Incorporation of SCE&G, as adopted on December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File Number 000-53860) and incorporated by reference herein)
3.05	X		By-Laws of SCANA as amended and restated as of December 30, 2016 (Filed as Exhibit 3.05 to Form 10-K for the period ended December 31, 2016 (File No. 001-08809) and incorporated by reference herein)
3.06		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)
12.01	X	X	Statement Re Computation of Ratios (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.

90

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  The signature of each registrant shall be deemed to relate only to matters having reference to such registrant and any subsidiaries thereof.

SCANA CORPORATION

SOUTH CAROLINA ELECTRIC & GAS COMPANY

(Registrants)

	By:	/s/James E. Swan, IV
Date: November 2, 2018		James E. Swan, IV
		Vice President and Controller
		(Principal accounting officer)

91

EX-12.01

Exhibit 12.01

COMPUTATION OF RATIOS

September 30, 2018

RATIO OF EARNINGS TO FIXED CHARGES

SCANA:	Nine Months Ended September 30, 2018		Twelve Months Ended September 30, 2018		Years ended December 31,
Dollars in Millions					2017		2016			2015		2014			2013
Fixed Charges as defined:
Interest on debt		$298.2		$392.4		$377.6		$356.8			$327.8		$318.2			$305.9
Amortization of debt premium, discount and expense (net)	3.1		4.1		4.0		4.5			4.7		9.7			5.3
Interest component on rentals	2.4		3.2		3.3		3.5			3.7		4.1			4.9
Total Fixed Charges (A)		$303.7		$399.7		$384.9		$364.8			$336.2		$332.0			$316.1
Earnings as defined:
Pretax income (loss) from continuing operations		$318.7	($380.6)		($230.7)		$865.6			$1,138.4			$786.0			$693.8
Total fixed charges above	303.7		399.7		384.9		364.8			336.2		332.0			316.1
Pretax equity in (earnings) losses of investees	3.6		10.9		8.9		(0.7		)	0.8		(1.4		)	(3.2		)
Cash distributions from equity investees	—		0.0		2.7		3.7			4.0		7.4			9.6
Total Earnings (B)	$626.0		$30.0		$165.8		$1,233.4			$1,479.4		$1,124.0			$1,016.3
Ratio of Earnings to Fixed Charges (B/A)	2.06		0.08		0.43		3.38			4.40		3.39			3.22
Amount of Earnings Deficiency Below Fixed Charges			$369.7		$219.1

SCE&G:	Nine Months Ended September 30, 2018		Twelve Months Ended September 30, 2018			Years ended December 31,
Dollars in Millions						2017			2016		2015		2014		2013
Fixed Charges as defined:
Interest on debt		$236.7		$310.8			$300.2			$284.6		$258.4		$237.6		$226.4
Amortization of debt premium, discount and expense (net)	2.2		3.0			2.9			3.5		3.7		4.4		4.2
Interest component on rentals	2.6		3.4			3.8			4.0		4.1		4.0		4.5
Total Fixed Charges (A)		$241.5		$317.2			$306.9			$292.1		$266.2		$246.0		$235.1
Earnings as defined:
Pretax income (loss) from continuing operations		$332.2		($419.3	)		($342.6	)		$774.1		$711.0		$676.0		$579.7
Total fixed charges above	241.5		317.2			306.9			292.1		266.2		246.0		235.1
Pretax equity in losses of investees	4.2		5.1			4.6			3.1		5.0		5.3		3.5
Total Earnings (B)		$577.9		($97.0	)	($31.1)				$1069.3		$982.2		$927.3		$818.3
Ratio of Earnings to Fixed Charges (B/A)	2.39		(0.31)			(0.10)			3.66		3.69		3.77		3.48
Amount of Earnings Deficiency Below Fixed Charges			$414.2			$338.0

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Jimmy E. Addison, certify that:

1. I have reviewed this quarterly report on Form 10-Q 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 function):

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

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

Date: November 2, 2018
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Chief Executive Officer and President

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Iris N. Griffin, certify that:

1. I have reviewed this quarterly report on Form 10-Q 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 function):

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

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

Date: November 2, 2018
	/s/Iris N. Griffin
	Iris N. Griffin
	Senior Vice President and Chief Financial Officer

EX-31.03

Exhibit 31.03

CERTIFICATION

I, Jimmy E. Addison, certify that:

1. I have reviewed this quarterly report on Form 10-Q 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 function):

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

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

Date: November 2, 2018
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Chief Executive Officer

EX-31.04

Exhibit 31.04

CERTIFICATION

I, Iris N. Griffin, certify that:

1. I have reviewed this quarterly report on Form 10-Q 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 function):

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

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

Date: November 2, 2018
	/s/Iris N. Griffin
	Iris N. Griffin
	Senior Vice President and 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 Quarterly Report of SCANA Corporation (the “Company”) on Form 10-Q for the quarter ended September 30, 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.

Date: November 2, 2018
/s/Jimmy E. Addison	/s/Iris N. Griffin
Jimmy E. Addison	Iris N. Griffin
Chief Executive Officer and President	Senior Vice President and 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 Quarterly Report of South Carolina Electric & Gas Company (the “Company”) on Form 10-Q for the quarter ended September 30, 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.

Date: November 2, 2018
/s/Jimmy E. Addison	/s/Iris N. Griffin
Jimmy E. Addison	Iris N. Griffin
Chief Executive Officer	Senior Vice President and Chief Financial Officer

XML

Document and Entity Information Document - shares	9 Months Ended
	Sep. 30, 2018	Oct. 26, 2018
Entity Information [Line Items]
Entity Registrant Name	SCANA Corporation
Entity Central Index Key	0000754737
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		142,619,243
SCEG
Entity 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-Q
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,296,147

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Assets
Utility Plant In Service	$ 15,012	$ 14,370
Accumulated Depreciation and Amortization	(5,059)	(4,611)
Construction Work in Progress	537	471
Nuclear Fuel, Net of Accumulated Amortization	182	208
Goodwill, Net of Writedown of $230	210	210
Utility Plant, Net	10,882	10,648
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	269	270
Assets held in trust, net-nuclear decommissioning	139	136
Other investments	135	68
Nonutility Property and Investments, Net	543	474
Current Assets:
Cash and cash equivalents	462	409
Receivables, net of allowance for uncollectible accounts	474	665
Other	75	105
Income Taxes receivable	0	198
Inventories (at average cost):
Fuel	123	143
Materials and supplies	166	161
Prepaid Expense	108	99
Other current assets	12	17
Total Current Assets	1,420	1,851
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	5,739	5,580
Other	232	186
Other affiliate		0
Total Deferred Debits and Other Assets	5,971	5,766
Total	18,816	18,739
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,389	2,390
Retained Earnings, Unappropriated	3,036	2,915
Accumulated Other Comprehensive Income (Loss), Net of Tax	(34)	(50)
Stockholders' Equity Attributable to Parent	5,391	5,255
Long-term Debt, Excluding Current Maturities	6,735	5,906
Total Capitalization	12,126	11,161
Current Liabilities:
Short-term borrowings	314	350
Current portion of long-term debt	18	727
Accounts payable	263	438
Customer deposits and customer prepayments	146	112
Customer Refund Liability, Current	61
Taxes accrued	179	214
Interest accrued	90	87
Dividends declared	18	86
Derivative financial instruments	3	6
Other	72	93
Total Current Liabilities	1,164	2,113
Deferred Credits and Other Liabilities:
Deferred Income Tax Liabilities, Net	1,355	1,261
Asset retirement obligations	579	568
Pension and other postretirement benefits	347	360
Unrecognized Tax Benefits	19	19
Regulatory Liabilities	3,040	3,059
Other	186	198
Total Deferred Credits and Other Liabilities	5,526	5,465
Commitments and Contingencies
Total	18,816	18,739
Derivative financial instruments	0	54
SCEG
Assets
Utility Plant In Service	12,716	12,161
Accumulated Depreciation and Amortization	(4,541)	(4,124)
Construction Work in Progress	333	375
Nuclear Fuel, Net of Accumulated Amortization	182	208
Utility Plant, Net	8,690	8,620
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	73	71
Assets held in trust, net-nuclear decommissioning	139	136
Other investments	1	2
Nonutility Property and Investments, Net	213	209
Current Assets:
Cash and cash equivalents	439	395
Receivables, net of allowance for uncollectible accounts	357	390
Other	54	85
Income Taxes receivable	0	198
Due from Affiliate, Current	186	32
Inventories (at average cost):
Fuel	64	90
Materials and supplies	155	149
Prepaid Expense	95	82
Derivative Asset, Current	0	54
Other current assets	2	2
Total Current Assets	1,352	1,477
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	5,623	5,476
Other	180	164
Other affiliate	71
Total Deferred Debits and Other Assets	5,874	5,640
Total	16,129	15,946
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,860	2,860
Retained Earnings, Unappropriated	2,146	1,982
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)	(4)
Stockholders' Equity Attributable to Parent	5,003	4,838
Stockholders' Equity Attributable to Noncontrolling Interest	169	142
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	5,172	4,980
Long-term Debt, Excluding Current Maturities	5,132	4,441
Total Capitalization	10,304	9,421
Current Liabilities:
Short-term borrowings	173	252
Current portion of long-term debt	14	723
Accounts payable	136	251
Due to Affiliate, Current	259	102
Customer deposits and customer prepayments	117	70
Customer Refund Liability, Current	61
Taxes accrued	169	208
Interest accrued	64	67
Dividends declared	9	82
Derivative financial instruments	1	2
Other	34	47
Total Current Liabilities	1,037	1,804
Deferred Credits and Other Liabilities:
Deferred Income Tax Liabilities, Net	1,266	1,173
Asset retirement obligations	539	529
Pension and other postretirement benefits	207	217
Unrecognized Tax Benefits	19	19
Regulatory Liabilities	2,635	2,667
Other	104	97
Other -affiliate	18	19
Total Deferred Credits and Other Liabilities	4,788	4,721
Total	$ 16,129	$ 15,946

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Common Stock, Shares, Outstanding	143.0	143.0
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 140	$ 133
Public Utilities, Property, Plant and Equipment, Net	10,882	10,648
Allowance for Doubtful Accounts Receivable, Current	4	6
Write-down, Goodwill	230	230
Assets, Current	1,420	1,851
Regulated Entity, Other Assets, Noncurrent	$ 5,971	$ 5,766
SCEG
Common Stock, Shares, Outstanding	40.3	40.3
Public Utilities, Property, Plant and Equipment, Net	$ 8,690	$ 8,620
Allowance for Doubtful Accounts Receivable, Current	3	4
Assets, Current	1,352	1,477
Regulated Entity, Other Assets, Noncurrent	5,874	5,640
SCEG | Variable Interest Entity, Primary Beneficiary [Member]
Public Utilities, Property, Plant and Equipment, Net	676	711
Assets, Current	74	191
Regulated Entity, Other Assets, Noncurrent	$ 34	$ 50

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating Revenues:
Electric Regulated Revenue	$ 669.0	$ 786.0	$ 1,767.0	$ 2,042.0
Regulated Operating Revenue, Gas	122.0	123.0	631.0	584.0
Gas-nonregulated	135.0	167.0	550.0	623.0
Regulated and Unregulated Operating Revenue	926.0	1,076.0	2,948.0	3,249.0
Operating Expenses
Fuel used in electric generation	188.0	167.0	503.0	464.0
Purchased power	10.0	22.0	77.0	54.0
Utilities Operating Expense, Gas and Petroleum Purchased	177.0	211.0	774.0	808.0
Other operation and maintenance	201.0	181.0	610.0	535.0
Utilities Operating Expense, Impairments	0.0	210.0	4.0	210.0
Depreciation and amortization	100.0	96.0	299.0	285.0
Other taxes	67.0	67.0	206.0	200.0
Total Operating Expenses	743.0	954.0	2,473.0	2,556.0
Operating Income	183.0	122.0	475.0	693.0
Other Nonoperating Income (Expense)	3.0	19.0	136.0	45.0
Other Income (Expense):
Other income	8.0	28.0	144.0	61.0
Other expense	(14.0)	(9.0)	(34.0)	(33.0)
Interest Expense	(99.0)	(95.0)	(292.0)	(270.0)
Allowance for equity funds used during construction			12.0	17.0
Income Before Income Tax Expense	87.0	46.0	319.0	468.0
Income Tax Expense	20.0	12.0	75.0	142.0
Net Income (Loss) Available to Common Stockholders, Basic	$ 67.0	$ 34.0	$ 244.0	$ 326.0
Earnings Per Share, Basic and Diluted	$ 0.47	$ 0.24	$ 1.71	$ 2.28
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	$ 0.0	$ 0.0
Other Comprehensive Income (Loss), Net of Tax	$ 5.0	$ 3.0	$ 16.0	$ 0.0
Per Common Share Data
Weighted Average Number of Shares Outstanding, Basic and Diluted	143	143	143	143
Weighted Average Common Shares Outstanding (millions)
Common Stock, Dividends, Per Share, Declared	$ 0.1237	$ 0.6125	$ 0.8599	$ 1.838
SCEG
Operating Revenues:
Electric Regulated Revenue	$ 669.0	$ 786.0	$ 1,767.0	$ 2,042.0
Electric Domestic Regulated Revenues - Affiliate	1.0	1.0	3.0	4.0
Regulated Operating Revenue, Gas	69.0	69.0	303.0	284.0
Regulated Operating Revenue Gas, Affiliate		0.0	1.0	1.0
Regulated Operating Revenue	739.0	856.0	2,074.0	2,331.0
Operating Expenses
Fuel used in electric generation	153.0	132.0	408.0	370.0
Fuel used in electric generation, affiliate	35.0	35.0	95.0	94.0
Purchased power	10.0	22.0	77.0	54.0
Utilities Operating Expense, Gas and Petroleum Purchased	41.0	39.0	161.0	147.0
Other operation and maintenance	105.0	109.0	320.0	305.0
Other operation and maintenance, affiliate	39.0	44.0	135.0	135.0
Utilities Operating Expense, Impairments		210.0	4.0	210.0
Depreciation and amortization	81.0	78.0	242.0	232.0
Other taxes	61.0	62.0	188.0	183.0
Other taxes, affiliate	2.0	1.0	4.0	4.0
Total Operating Expenses	527.0	732.0	1,634.0	1,734.0
Operating Income	212.0	124.0	440.0	597.0
Other Nonoperating Income (Expense)	(1.0)	11.0	124.0	26.0
Other Income (Expense):
Other income	5.0	21.0	135.0	36.0
Other expense	(10.0)	(7.0)	(22.0)	(23.0)
Interest Expense	(79.0)	(76.0)	(232.0)	(214.0)
Allowance for equity funds used during construction			7.0	13.0
Income Before Income Tax Expense	132.0	59.0	332.0	409.0
Income Tax Expense	29.0	17.0	70.0	129.0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	103.0	42.0	262.0	280.0
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	1.0		1.0
Other Comprehensive Income (Loss), Net of Tax	104.0	42.0	263.0	280.0
Net Income (Loss) Attributable to Noncontrolling Interest	6.0	3.0	15.0	10.0
Earnings Available to Common Shareholder	$ 98.0	$ 39.0	$ 248.0	$ 270.0
Weighted Average Common Shares Outstanding (millions)
Common Stock, Dividends, Per Share, Declared	$ 17,000,000	$ 81,000,000

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Allowance for Funds Used During Construction, Capitalized Interest	$ 3	$ 2	$ 9	$ 16
SCEG
Allowance for Funds Used During Construction, Capitalized Interest	$ 2	$ 2	$ 7	$ 15

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	$ 0	$ 0
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	67	34	$ 244	$ 326
Other Comprehensive Income (Loss)
Unrealized gains (losses) on cash flow hedging activities arising during period	1	0	(5)	5
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	4	2	14	(1)
Other Comprehensive Income (Loss)	5	3	16	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, before Reclassification Adjustment, after Tax	1	1	2	1
Comprehensive income available to common shareholder	72	37	260	326
SCEG
Net Income (Loss) Attributable to Parent	98	39	248	270
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	1		1
Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss)	104	42	263	280
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	103	42	262	280
Genco
Other Comprehensive Income (Loss)
Less comprehensive income attributable to noncontrolling interest	6	3	15	10
SCE&G (including Fuel Company)
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	97	39
Other Comprehensive Income (Loss)
Comprehensive income available to common shareholder	97	39	247	270
Commodity Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	0	2	(2)
Interest Rate Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	3	2	7	6
Cash Flow Hedging [Member] | Interest Expense [Member] | Interest Rate Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (3)	$ (2)	$ (7)	$ (6)

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ 0	$ 0	$ (3)	$ (3)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	1	1	3	3
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax	1	1	(1)	$ (1)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	0	$ 0
SCEG
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	$ 1		$ 1

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash Flows From Operating Activities:
Net Income (Loss) Available to Common Stockholders, Basic	$ 244	$ 326
Adjustments to reconcile net income to net cash provided from operating activities:
Asset Impairment Charges	4	210
Deferred Income Tax Expense (Benefit)	89	(395)
Depreciation and amortization	327	302
Amortization of nuclear fuel	41	31
Allowance for equity funds used during construction	(12)	(17)
Carrying cost recovery	(4)	(27)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	207	79
Increase (Decrease) Income Taxes Receivable	198	136
Increase (Decrease) in Inventories	(40)	(58)
increase (Decrease) in Prepaid Expense	(5)	(6)
Increase (Decrease) in Other Regulatory Assets	(10)	(48)
Increase (Decrease) in Regulatory liabilities	(95)	(3)
Increase (Decrease ) in Accounts payable	(53)	(22)
Customer Refundable Fees, Revenue Recognized	61
Unrecognized tax benefits, increase (decrease)	0	183
Increase (Decrease) in Taxes accrued	(35)	325
Increase (Decrease) in Derivative Assets and Liabilities	(2)	(3)
Changes in other assets	(69)	(37)
Changes in other liabilities	12	(49)
Net Cash Provided From Operating Activities	858	927
Cash Flows From Investing Activities:
Property additions and construction expenditures	(743)	(1,095)
Proceeds from Sale of Other Receivables		1,013
Proceeds from investments (including derivative collateral posted)	87	116
Purchase of investments (including derivative collateral posted)	(144)	(115)
Payments for (Proceeds from) Hedge, Financing Activities	115
Net Cash Used For Investing Activities	(685)	(81)
Proceeds from Issuance of Long-term Debt	935	150
Cash Flows From Financing Activities:
Repayments of Long-term Debt	(828)	(16)
Dividends	(191)	(258)
Short-term borrowings, net	(36)	81
Net Cash (Used For) Provided From Financing Activities	(120)	(43)
Net Increase (Decrease) in Cash and Cash Equivalents	53	803
Cash and Cash Equivalents, January 1	409	208
Cash and Cash Equivalents, September 30	462	1,011
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	270	247
Income Taxes Paid		1
Proceeds from Income Tax Refunds	206	123
Noncash Investing and Financing Activities:
Accrued construction expenditures	49	44
Capital Lease Obligations Incurred	9	6
SCEG
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	262	280
Adjustments to reconcile net income to net cash provided from operating activities:
Asset Impairment Charges	4	210
Deferred Income Tax Expense (Benefit)	93	(434)
Depreciation and amortization	259	238
Amortization of nuclear fuel	41	31
Allowance for equity funds used during construction	(7)	(13)
Carrying cost recovery	(4)	(27)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	49	(27)
Increase (Decrease) Income Taxes Receivable	198	53
Increase (Decrease) in Due from Affiliates, Current	(4)	8
Increase (Decrease) in Inventories	(15)	(34)
increase (Decrease) in Prepaid Expense	(13)	(10)
Increase (Decrease) in Other Regulatory Assets	2	(40)
Increase (Decrease) in Regulatory liabilities	(102)	(1)
Increase (Decrease ) in Accounts payable	(10)	31
Customer Refundable Fees, Revenue Recognized	61
Unrecognized tax benefits, increase (decrease)	0	166
Increase (Decrease) in Due to Affiliate, Current	0	(28)
Increase (Decrease) in Taxes accrued	(39)	468
Changes in other assets	(44)	(29)
Changes in other liabilities	38	(14)
Net Cash Provided From Operating Activities	769	828
Cash Flows From Investing Activities:
Property additions and construction expenditures	(538)	(882)
Proceeds from Sale of Other Receivables		1,013
Proceeds from investments (including derivative collateral posted)	35	96
Purchase of investments (including derivative collateral posted)	(21)	(98)
Payments to Acquire Interest in Subsidiaries and Affiliates	(113)
Payments for (Proceeds from) Hedge, Financing Activities	115
Proceeds from Contributions from Affiliates	42
Investment In Affiliate	(150)
Net Cash Used For Investing Activities	(630)	129
Proceeds from Issuance of Long-term Debt		0
Cash Flows From Financing Activities:
Repayments of Long-term Debt	(824)	(11)
Dividends	(164)	(238)
Short-term borrowings-affiliate,net	157	2
Proceeds from Contributions from Parent	20
Short-term borrowings, net	(79)	141
Proceeds from Issuance of Debt	795
Net Cash (Used For) Provided From Financing Activities	(95)	(106)
Net Increase (Decrease) in Cash and Cash Equivalents	44	851
Cash and Cash Equivalents, January 1	395	164
Cash and Cash Equivalents, September 30	439	1,015
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	211	195
Income Taxes Paid	3	3
Proceeds from Income Tax Refunds	216	143
Noncash Investing and Financing Activities:
Accrued construction expenditures	25	21
Capital Lease Obligations Incurred	$ 7	$ 6

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Interest Paid, Capitalized, Investing Activities	$ 9	$ 16
SCEG
Interest Paid, Capitalized, Investing Activities	$ 7	$ 15

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CONSOLIDATED STATEMENTS OF COMMON EQUITY - USD ($) shares in Millions, $ in Millions	Total	AOCI Attributable to Parent [Member]	SCEG	SCEG excluding VIEs [Member]	SCEG and GENCO [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' Equity before Treasury Stock	$ 2,402
Treasury Stock, Value	(12)
Retained Earnings, Appropriated	3,384			$ 2,481
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(36)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	(13)
Accumulated Other Comprehensive Income (Loss)	(49)			(3)
Stockholders' Equity Attributable to Noncontrolling Interest					$ 134
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			$ 5,472
Stockholders' Equity Attributable to Parent	$ 5,725
Common Stock, Value, Outstanding				$ 2,860
Shares, Outstanding	143			40
Net Income (Loss) Available to Common Stockholders, Basic	$ 171			$ 109
Net Income (Loss) Attributable to Noncontrolling Interest					3
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			112
Dividends			(79)	(77)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(2)
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	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(2)
Other Comprehensive Income (Loss)	(2)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	169
Treasury Stock Purchased	(1)
Dividends, Common Stock	(87)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(2)
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	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	$ (2)
Common Stock, Dividends, Per Share, Declared	$ 1.838
Net Income (Loss) Available to Common Stockholders, Basic	$ 326
Net Income (Loss) Attributable to Noncontrolling Interest			10
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			280
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(5)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(1)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	4
Other Comprehensive Income (Loss)	0		280
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	326			270
Dividends, Common Stock			(240)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(5)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(1)
Stockholders' Equity before Treasury Stock	2,402
Treasury Stock, Value	(13)
Retained Earnings, Appropriated	3,468			2,513
AOCI before Tax, Attributable to Parent		$ (2)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(38)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	(13)
Accumulated Other Comprehensive Income (Loss)	(51)			(3)
Stockholders' Equity Attributable to Noncontrolling Interest					135
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			5,505
Stockholders' Equity Attributable to Parent	$ 5,806
Common Stock, Value, Outstanding				$ 2,860
Shares, Outstanding	143			40
AOCI before Tax, Attributable to Parent		(2)
Net Income (Loss) Available to Common Stockholders, Basic	$ 121			$ 122
Net Income (Loss) Attributable to Noncontrolling Interest					4
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			126
Dividends			(81)	(78)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(3)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(3)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(1)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	2
Other Comprehensive Income (Loss)	(1)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	120
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax	0
Dividends, Common Stock	(88)
Proceeds from Contribution from Parent, net of return of Proceeds				2,860
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(3)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(3)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(1)
Stockholders' Equity before Treasury Stock	2,402
Treasury Stock, Value	(13)
Retained Earnings, Appropriated	3,501			2,557
AOCI before Tax, Attributable to Parent	(2)	(3)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(39)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	(13)
Accumulated Other Comprehensive Income (Loss)	(52)			$ (3)
Stockholders' Equity Attributable to Noncontrolling Interest					136
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			$ 5,550
Stockholders' Equity Attributable to Parent	$ 5,838
Shares, Outstanding	143			40
AOCI before Tax, Attributable to Parent	$ (2)	(3)
Common Stock, Dividends, Per Share, Declared	$ 0.6125		$ 81,000,000
Net Income (Loss) Available to Common Stockholders, Basic	$ 34			$ 39
Net Income (Loss) Attributable to Noncontrolling Interest			$ 3		3
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			42
Dividends			(80)	(78)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(2)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	1
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	2
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	2
Other Comprehensive Income (Loss)	3		42
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	37			39
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax	1
Dividends, Common Stock	(88)
Proceeds from Contribution from Parent, net of return of Proceeds				2,860
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(2)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	1
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	2
Stockholders' Equity before Treasury Stock	2,402
Treasury Stock, Value	(13)
Retained Earnings, Appropriated	3,447			2,518
AOCI before Tax, Attributable to Parent	(3)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(37)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	(12)
Accumulated Other Comprehensive Income (Loss)	(49)			$ (3)
Stockholders' Equity Attributable to Noncontrolling Interest					137
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			5,512
Stockholders' Equity Attributable to Parent	$ 5,787
Shares, Outstanding	143			40
AOCI before Tax, Attributable to Parent	$ (3)
Stockholders' Equity before Treasury Stock	2,402
Treasury Stock, Value	(12)
Retained Earnings, Appropriated	2,915		1,982	$ 1,982
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(37)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	(13)
Accumulated Other Comprehensive Income (Loss)	(50)			(4)
Stockholders' Equity Attributable to Noncontrolling Interest			142		142
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			4,980
Stockholders' Equity Attributable to Parent	5,255		4,838
Common Stock, Value, Outstanding	$ 2,390		2,860	$ 2,860
Shares, Outstanding	143			40
Common Stock, Dividends, Per Share, Declared	$ 0.6125
Net Income (Loss) Available to Common Stockholders, Basic	$ 169			$ 124
Net Income (Loss) Attributable to Noncontrolling Interest					4
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			128
Dividends			(74)	(72)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(2)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	3
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	7
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	4
Other Comprehensive Income (Loss)	8
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	177
Treasury Stock Purchased	(1)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax	1
Dividends, Common Stock	(87)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(2)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	3
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	7
Proceeds from Contributions from Parent			20
Proceeds from Contributions from Parent	$ 20
Common Stock, Dividends, Per Share, Declared	$ 0.8599
Net Income (Loss) Available to Common Stockholders, Basic	$ 244
Net Income (Loss) Attributable to Noncontrolling Interest			15
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			262
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	5
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	14
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	9
Other Comprehensive Income (Loss)	16		263
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	260			247
Dividends, Common Stock			(91)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	5
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	14
Retained Earnings, Appropriated	2,997			2,034
AOCI before Tax, Attributable to Parent	(5)	3
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(30)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	(12)
Accumulated Other Comprehensive Income (Loss)	(42)			(4)
Stockholders' Equity Attributable to Noncontrolling Interest					144
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			5,034
Stockholders' Equity Attributable to Parent	5,344
Common Stock, Value, Outstanding				$ 2,860
Shares, Outstanding				40
AOCI before Tax, Attributable to Parent	(5)	3
Net Income (Loss) Available to Common Stockholders, Basic	8			$ 26
Net Income (Loss) Attributable to Noncontrolling Interest					5
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			31
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	1
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	3
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	2
Other Comprehensive Income (Loss)	3
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	11
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax	0
Dividends, Common Stock	(18)
Proceeds from Contribution from Parent, net of return of Proceeds	20
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	1
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	3
Stockholders' Equity before Treasury Stock	2,402
Treasury Stock, Value	(13)
Retained Earnings, Appropriated	2,987			2,060
AOCI before Tax, Attributable to Parent	(2)	1
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(27)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	(12)
Accumulated Other Comprehensive Income (Loss)	(39)			(4)
Stockholders' Equity Attributable to Noncontrolling Interest					169
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			$ 5,085
Stockholders' Equity Attributable to Parent	$ 5,337
Common Stock, Value, Outstanding				$ 2,860
Shares, Outstanding	143			40
AOCI before Tax, Attributable to Parent	$ (2)	1
Common Stock, Dividends, Per Share, Declared	$ 0.1237		$ 17,000,000
Net Income (Loss) Available to Common Stockholders, Basic	$ 67			$ 97
Net Income (Loss) Attributable to Noncontrolling Interest			$ 6		6
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			103		104
Dividends			(17)	(11)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(6)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	1
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	1
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	4
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	3
Other Comprehensive Income (Loss)	5		104
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	72			97
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax	1		1
Dividends, Common Stock	(18)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(6)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	1
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	1
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	4
Stockholders' Equity before Treasury Stock	2,402
Treasury Stock, Value	(13)
Retained Earnings, Appropriated	3,036		2,146	2,146
AOCI before Tax, Attributable to Parent	(4)	1
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(23)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	(11)
Accumulated Other Comprehensive Income (Loss)	(34)			(3)
Stockholders' Equity Attributable to Noncontrolling Interest			169		$ 169
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			5,172
Stockholders' Equity Attributable to Parent	5,391		5,003
Common Stock, Value, Outstanding	$ 2,389		$ 2,860	$ 2,860
Shares, Outstanding	143			40
AOCI before Tax, Attributable to Parent	$ (4)	$ 1

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2018

Significant Accounting Policies

Significant Accounting Policies [Text Block]

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation and Variable Interest Entities

     The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed 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 condensed 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 $495 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.

Income Statement 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 11) are presented within Operating Income, and other activities are presented within Other Income (Expense).

Asset Management and Supply Service Agreement

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, 45% and 39% of PSNC Energy’s natural gas inventory at September 30, 2018 and December 31, 2017, respectively, with a carrying value of $14.3 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 expires on March 31, 2019.

Earnings Per Share

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

Reclassifications

In the statement of operations, amounts reported for 2017 under the captions “Other income,” “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net.” Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated.

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.

• In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company adopted this guidance on January 1, 2018.

• Effective January 1, 2018, the Company and Consolidated SCE&G adopted new accounting guidance for revenue arising from contracts with customers. This guidance 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 are 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.

• Effective January 1, 2018, the Company and Consolidated SCE&G adopted accounting guidance that changed the required presentation of net periodic pension and postretirement benefit costs. As a result, net periodic pension and postretirement benefit costs have been separated into their 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 during the period. Non-service cost components are now excluded from operating income. This guidance has been applied on a retrospective basis for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017.

Increase (Decrease) Millions of dollars	The Company						Consolidated SCE&G
September 30, 2017	Three Months Ended			Nine Months Ended			Three Months Ended			Nine Months Ended
Other operation and maintenance	$	(2	)	$	(8	)	$	(1	)	$	(6	)
Total Operating Expenses	(2		)	(8		)	(1		)	(6		)
Operating Income	2			8			1			6
Other Income (Expense), Net	(2		)	(8		)	(1		)	(6		)

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, and the adoption of this guidance did not result in a material impact on the Company’s and Consolidated SCE&G’s respective financial statements. 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 accounting guidance related to the recognition, measurement and presentation of leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further,

depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. In the first quarter of 2018, FASB amended this accounting guidance to clarify that land easements are within the scope of the new guidance and to provide an optional transition practical expedient, that the Company and Consolidated SCE&G intend to adopt, that allows adopters to not evaluate under the new guidance existing or expired land easements that were not previously accounted for as leases. FASB also approved a new transition option in the first quarter of 2018, that the Company and Consolidated SCE&G intend to adopt, that will allow the new standard to be adopted without revising comparative period reporting or disclosures. The new guidance is effective for years beginning in 2019, and the Company and Consolidated SCE&G do not anticipate that its adoption will have a material impact on their respective financial statements other than increasing amounts reported for assets and liabilities on the balance sheet and changing the location on their respective statements of operations where certain expenses are recorded. No impact on net income is expected. The identification and analysis of leasing and related contracts to which the guidance will apply continues. In addition, the Company and Consolidated SCE&G are implementing a third party software tool to assist with initial adoption and ongoing compliance. System configuration has been completed and data input for financing leases is underway.

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. 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 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 expect to 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 expect to adopt this guidance when required in the first quarter of 2019 and do not expect it to have any impact 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.

SCEG

Significant Accounting Policies

Significant Accounting Policies [Text Block]

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation and Variable Interest Entities

     The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed 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 condensed 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 $495 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.

Income Statement 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 11) are presented within Operating Income, and other activities are presented within Other Income (Expense).

Asset Management and Supply Service Agreement

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, 45% and 39% of PSNC Energy’s natural gas inventory at September 30, 2018 and December 31, 2017, respectively, with a carrying value of $14.3 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 expires on March 31, 2019.

Earnings Per Share

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

Reclassifications

In the statement of operations, amounts reported for 2017 under the captions “Other income,” “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net.” Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated.

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.

• In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company adopted this guidance on January 1, 2018.

• Effective January 1, 2018, the Company and Consolidated SCE&G adopted new accounting guidance for revenue arising from contracts with customers. This guidance 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 are 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.

• Effective January 1, 2018, the Company and Consolidated SCE&G adopted accounting guidance that changed the required presentation of net periodic pension and postretirement benefit costs. As a result, net periodic pension and postretirement benefit costs have been separated into their 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 during the period. Non-service cost components are now excluded from operating income. This guidance has been applied on a retrospective basis for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017.

Increase (Decrease) Millions of dollars	The Company						Consolidated SCE&G
September 30, 2017	Three Months Ended			Nine Months Ended			Three Months Ended			Nine Months Ended
Other operation and maintenance	$	(2	)	$	(8	)	$	(1	)	$	(6	)
Total Operating Expenses	(2		)	(8		)	(1		)	(6		)
Operating Income	2			8			1			6
Other Income (Expense), Net	(2		)	(8		)	(1		)	(6		)

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, and the adoption of this guidance did not result in a material impact on the Company’s and Consolidated SCE&G’s respective financial statements. 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 accounting guidance related to the recognition, measurement and presentation of leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further,

depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. In the first quarter of 2018, FASB amended this accounting guidance to clarify that land easements are within the scope of the new guidance and to provide an optional transition practical expedient, that the Company and Consolidated SCE&G intend to adopt, that allows adopters to not evaluate under the new guidance existing or expired land easements that were not previously accounted for as leases. FASB also approved a new transition option in the first quarter of 2018, that the Company and Consolidated SCE&G intend to adopt, that will allow the new standard to be adopted without revising comparative period reporting or disclosures. The new guidance is effective for years beginning in 2019, and the Company and Consolidated SCE&G do not anticipate that its adoption will have a material impact on their respective financial statements other than increasing amounts reported for assets and liabilities on the balance sheet and changing the location on their respective statements of operations where certain expenses are recorded. No impact on net income is expected. The identification and analysis of leasing and related contracts to which the guidance will apply continues. In addition, the Company and Consolidated SCE&G are implementing a third party software tool to assist with initial adoption and ongoing compliance. System configuration has been completed and data input for financing leases is underway.

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. 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 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 expect to 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 expect to adopt this guidance when required in the first quarter of 2019 and do not expect it to have any impact 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.

XML

RATE AND OTHER REGULATORY MATTERS

9 Months Ended

Sep. 30, 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 the NCUC have sought information from utilities under their respective jurisdictions that would disclose the impact of the Tax Act on their individual company's operations and would propose procedures for changing customer rates to reflect those impacts. In addition, the SCPSC and NCUC have issued orders that require SCE&G and PSNC Energy to track and defer such impacts arising from customer rates in 2018 as subject to refund. See Gas - SCE&G below for a discussion of related SCPSC action. For electric rates, SCE&G expects the SCPSC will take further action on this matter in 2018 but cannot determine what form that action will take. PSNC Energy has been ordered by the NCUC to (1) propose adjustments to customer rates to reflect the reduction in the federal corporate tax rate, which adjustments, if approved by the NCUC, are expected to be made effective on or before January 1, 2019; (2) continue to defer as a regulatory liability such amounts arising from customer rates in 2018; and (3) continue to defer as a regulatory liability amounts arising from excess deferred income taxes, as further described below. The NCUC order requires the regulatory liability related to items (2) and (3) 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 income tax rate reflected in various riders for PSNC Energy will be addressed in its next annual rider proceedings.

As of September 30, 2018, SCE&G has recorded approximately $60.9 million as Revenue subject to refund and approximately $3.8 million as Regulatory liabilities on the condensed consolidated balance sheet for the Company and Consolidated SCE&G, and PSNC Energy has recorded approximately $10.1 million of such deferrals within Regulatory liabilities on the condensed consolidated balance sheet for the Company. These amounts include the accrual of estimated carrying costs. 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 regulations and will be amortized over the remaining lives of related property, and certain of these amounts will be amortized to the benefit of customers over a prescribed period as instructed by regulators.

Electric - BLRA and Joint Petition

On January 12, 2018, SCE&G and Dominion Energy filed with the SCPSC the Joint Petition for review and approval of a proposed business combination whereby SCANA would become a wholly-owned subsidiary of Dominion Energy. In the Joint Petition, approval of a customer benefits plan and a cost recovery plan for the Nuclear Project is also sought. Key provisions of this Joint Petition are summarized at Note 10. In September and October 2018, the SCPSC received public testimony on the Joint Petition and other Concurrent Dockets. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets regarding the merits of the Joint Petition and related issues. As noted below, the SCPSC is required by law to issue its order related to the Joint Petition no later than December 21, 2018.

On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA. Act 258 requires the SCPSC to order a reduction in 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%, or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On July 2 and 3, 2018, the SCPSC issued orders implementing the rate reduction required by Act 258. The rates and retroactive credits required by Act 258 were put into effect in August 2018, with the retroactive credits for the second quarter being applied in August's billing cycles. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 also alters certain provisions previously applicable under the BLRA, including redefining the standard of care required by the BLRA 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.

On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented.

Electric - Cost of Fuel

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 SCE&G’s increase to certain environmental, avoided capacity and DER 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 the gains realized from the settlement of certain interest rate derivatives in early 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.

In August 2018, the SCPSC initiated its 2019 annual review of base rates for fuel costs. A public hearing on this matter is scheduled to begin April 3, 2019.

Electric - Other

On April 25, 2018, the SCPSC approved SCE&G's request to recover approximately $33.0 million of costs and net lost revenues associated with DSM Programs, along with an incentive to invest in such programs. Changes in rates became effective beginning with the first billing cycle of May 2018.

Gas - SCE&G

On October 10, 2018, the SCPSC approved an overall decrease of approximately $19.7 million, or 4.61%, to SCE&G's natural gas rates under the terms of the RSA including 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. This rate adjustment and rider will become effective with the first billing cycle of November 2018.

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. SCE&G’s annual PGA hearing for the 12-month period ending July 31, 2018, is scheduled for November 8, 2018.

Gas - PSNC Energy

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. In 2018, the NCUC has approved those applications for the incremental annual revenue requirements, as follows:

Rates Effective	Incremental Increase
March 1, 2018	$14.7 million
September 1, 2018	$1.1 million

On October 4, 2018, Dominion Energy and SCANA filed a stipulation agreement with the Public Staff of the NCUC and an intervenor in the proposed merger between the two companies.  Among other things, in the event the merger closes, the stipulation agreement provides for (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. The NCUC conducted a hearing on the proposed merger in October 2018. The Company cannot predict the timing or the outcome of this matter.

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
Millions of dollars	September 30, 2018		December 31, 2017		September 30, 2018		December 31, 2017
Regulatory Assets:
Unrecovered Nuclear Project costs	$	4,140	$	3,976	$	4,140	$	3,976
AROs and related funding	448		434		423		410
Deferred employee benefit plan costs	282		305		254		273
Deferred losses on interest rate derivatives	446		456		446		456
Other unrecovered plant	96		105		96		105
DSM Programs	57		59		57		59
Pipeline integrity management costs	67		51		9		8
Environmental remediation costs	28		30		24		25
Deferred storm damage costs	29		24		29		24
Deferred transmission operating costs	11		—		11		—
Other	135		140		134		140
Total Regulatory Assets	$	5,739	$	5,580	$	5,623	$	5,476

Regulatory Liabilities:
Monetization of guaranty settlement	$	1,098	$	1,095	$	1,098	$	1,095
Accumulated deferred income taxes	1,075		1,076		916		914
Asset removal costs	775		757		539		527
Deferred gains on interest rate derivatives	77		131		77		131
Other	15		—		5		—
Total Regulatory Liabilities	$	3,040	$	3,059	$	2,635	$	2,667

Regulatory assets for unrecovered Nuclear Project costs have been recorded based on such amounts 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, but are not limited to, certain costs which have not been specifically approved for recovery by one of these regulatory agencies, including unrecovered nuclear project costs and deferred transmission operating costs that are the subject of regulatory proceedings as further discussed above and in Note 10. 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 as a result of the decision to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs under the abandonment provisions of the BLRA or through other regulatory means, net of an estimated impairment loss and net of the cost of certain assets that have been or will be placed in service. See also Note 10.

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 107 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. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065.

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 currently being recovered over approximately five years through an approved rate rider. 

Pipeline integrity management costs represent operating costs incurred 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 September 30, 2018 costs of $44.9 million have been deferred pending future approval of rate recovery. SCE&G amortizes $1.9 million of such costs 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 17 years, and PSNC Energy's remediation costs of $4.2 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 includes deferred depreciation and property taxes associated with certain transmission assets for which SCE&G expects recovery from customers through future rates. See also Note 10.

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. The SCPSC is expected to determine how SCE&G's customers will realize the value of these proceeds in connection with its consideration of the Request by the ORS and the Joint Petition (see above and Note 10).

Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act (certain of which are protected under normalization regulations and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over a prescribed period 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.

SCEG

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 the NCUC have sought information from utilities under their respective jurisdictions that would disclose the impact of the Tax Act on their individual company's operations and would propose procedures for changing customer rates to reflect those impacts. In addition, the SCPSC and NCUC have issued orders that require SCE&G and PSNC Energy to track and defer such impacts arising from customer rates in 2018 as subject to refund. See Gas - SCE&G below for a discussion of related SCPSC action. For electric rates, SCE&G expects the SCPSC will take further action on this matter in 2018 but cannot determine what form that action will take. PSNC Energy has been ordered by the NCUC to (1) propose adjustments to customer rates to reflect the reduction in the federal corporate tax rate, which adjustments, if approved by the NCUC, are expected to be made effective on or before January 1, 2019; (2) continue to defer as a regulatory liability such amounts arising from customer rates in 2018; and (3) continue to defer as a regulatory liability amounts arising from excess deferred income taxes, as further described below. The NCUC order requires the regulatory liability related to items (2) and (3) 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 income tax rate reflected in various riders for PSNC Energy will be addressed in its next annual rider proceedings.

As of September 30, 2018, SCE&G has recorded approximately $60.9 million as Revenue subject to refund and approximately $3.8 million as Regulatory liabilities on the condensed consolidated balance sheet for the Company and Consolidated SCE&G, and PSNC Energy has recorded approximately $10.1 million of such deferrals within Regulatory liabilities on the condensed consolidated balance sheet for the Company. These amounts include the accrual of estimated carrying costs. 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 regulations and will be amortized over the remaining lives of related property, and certain of these amounts will be amortized to the benefit of customers over a prescribed period as instructed by regulators.

Electric - BLRA and Joint Petition

On January 12, 2018, SCE&G and Dominion Energy filed with the SCPSC the Joint Petition for review and approval of a proposed business combination whereby SCANA would become a wholly-owned subsidiary of Dominion Energy. In the Joint Petition, approval of a customer benefits plan and a cost recovery plan for the Nuclear Project is also sought. Key provisions of this Joint Petition are summarized at Note 10. In September and October 2018, the SCPSC received public testimony on the Joint Petition and other Concurrent Dockets. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets regarding the merits of the Joint Petition and related issues. As noted below, the SCPSC is required by law to issue its order related to the Joint Petition no later than December 21, 2018.

On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA. Act 258 requires the SCPSC to order a reduction in 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%, or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On July 2 and 3, 2018, the SCPSC issued orders implementing the rate reduction required by Act 258. The rates and retroactive credits required by Act 258 were put into effect in August 2018, with the retroactive credits for the second quarter being applied in August's billing cycles. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 also alters certain provisions previously applicable under the BLRA, including redefining the standard of care required by the BLRA 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.

On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented.

Electric - Cost of Fuel

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 SCE&G’s increase to certain environmental, avoided capacity and DER 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 the gains realized from the settlement of certain interest rate derivatives in early 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.

In August 2018, the SCPSC initiated its 2019 annual review of base rates for fuel costs. A public hearing on this matter is scheduled to begin April 3, 2019.

Electric - Other

On April 25, 2018, the SCPSC approved SCE&G's request to recover approximately $33.0 million of costs and net lost revenues associated with DSM Programs, along with an incentive to invest in such programs. Changes in rates became effective beginning with the first billing cycle of May 2018.

Gas - SCE&G

On October 10, 2018, the SCPSC approved an overall decrease of approximately $19.7 million, or 4.61%, to SCE&G's natural gas rates under the terms of the RSA including 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. This rate adjustment and rider will become effective with the first billing cycle of November 2018.

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. SCE&G’s annual PGA hearing for the 12-month period ending July 31, 2018, is scheduled for November 8, 2018.

Gas - PSNC Energy

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. In 2018, the NCUC has approved those applications for the incremental annual revenue requirements, as follows:

Rates Effective	Incremental Increase
March 1, 2018	$14.7 million
September 1, 2018	$1.1 million

On October 4, 2018, Dominion Energy and SCANA filed a stipulation agreement with the Public Staff of the NCUC and an intervenor in the proposed merger between the two companies.  Among other things, in the event the merger closes, the stipulation agreement provides for (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. The NCUC conducted a hearing on the proposed merger in October 2018. The Company cannot predict the timing or the outcome of this matter.

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
Millions of dollars	September 30, 2018		December 31, 2017		September 30, 2018		December 31, 2017
Regulatory Assets:
Unrecovered Nuclear Project costs	$	4,140	$	3,976	$	4,140	$	3,976
AROs and related funding	448		434		423		410
Deferred employee benefit plan costs	282		305		254		273
Deferred losses on interest rate derivatives	446		456		446		456
Other unrecovered plant	96		105		96		105
DSM Programs	57		59		57		59
Pipeline integrity management costs	67		51		9		8
Environmental remediation costs	28		30		24		25
Deferred storm damage costs	29		24		29		24
Deferred transmission operating costs	11		—		11		—
Other	135		140		134		140
Total Regulatory Assets	$	5,739	$	5,580	$	5,623	$	5,476

Regulatory Liabilities:
Monetization of guaranty settlement	$	1,098	$	1,095	$	1,098	$	1,095
Accumulated deferred income taxes	1,075		1,076		916		914
Asset removal costs	775		757		539		527
Deferred gains on interest rate derivatives	77		131		77		131
Other	15		—		5		—
Total Regulatory Liabilities	$	3,040	$	3,059	$	2,635	$	2,667

Regulatory assets for unrecovered Nuclear Project costs have been recorded based on such amounts 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, but are not limited to, certain costs which have not been specifically approved for recovery by one of these regulatory agencies, including unrecovered nuclear project costs and deferred transmission operating costs that are the subject of regulatory proceedings as further discussed above and in Note 10. 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 as a result of the decision to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs under the abandonment provisions of the BLRA or through other regulatory means, net of an estimated impairment loss and net of the cost of certain assets that have been or will be placed in service. See also Note 10.

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 107 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. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065.

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 currently being recovered over approximately five years through an approved rate rider. 

Pipeline integrity management costs represent operating costs incurred 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 September 30, 2018 costs of $44.9 million have been deferred pending future approval of rate recovery. SCE&G amortizes $1.9 million of such costs 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 17 years, and PSNC Energy's remediation costs of $4.2 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 includes deferred depreciation and property taxes associated with certain transmission assets for which SCE&G expects recovery from customers through future rates. See also Note 10.

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. The SCPSC is expected to determine how SCE&G's customers will realize the value of these proceeds in connection with its consideration of the Request by the ORS and the Joint Petition (see above and Note 10).

Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act (certain of which are protected under normalization regulations and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over a prescribed period 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.

XML

REVENUE RECOGNITION Notes

9 Months Ended

Sep. 30, 2018

Entity Information [Line Items]

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 12). Such revenues are outside the scope of revenues from contracts with customers.

Non-operating revenues are further described in Note 12. 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, such as 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				Gas-nonregulated
Millions of dollars	Electric		Gas-regulated		Gas-regulated		Total  Gas-regulated
Three months ended September 30, 2018
Customer class:
Residential	$	310	$	25	$	27	$	52	$	22
Commercial	231		19		19		38		14
Industrial	95		19		—		19		93
Other	31		6		7		13		6
Revenues from contracts with customers	667		69		53		122		135
Other operating revenues	3		—		—		—		—
Total Operating Revenues	$	670	$	69	$	53	$	122	$	135
Nine months ended September 30, 2018
Customer class:
Residential	$	805	$	145	$	210	$	355	$	158
Commercial	571		80		85		165		64
Industrial	286		64		10		74		304
Other	99		13		22		35		24
Revenues from contracts with customers	1,761		302		327		629		550
Other operating revenues	9		1		1		2		—
Total Operating Revenues	$	1,770	$	303	$	328	$	631	$	550

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 condensed 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	(1.1		)
Impairment	—
September 30, 2018	$	15.2

SCEG

Entity Information [Line Items]

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 12). Such revenues are outside the scope of revenues from contracts with customers.

Non-operating revenues are further described in Note 12. 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, such as 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				Gas-nonregulated
Millions of dollars	Electric		Gas-regulated		Gas-regulated		Total  Gas-regulated
Three months ended September 30, 2018
Customer class:
Residential	$	310	$	25	$	27	$	52	$	22
Commercial	231		19		19		38		14
Industrial	95		19		—		19		93
Other	31		6		7		13		6
Revenues from contracts with customers	667		69		53		122		135
Other operating revenues	3		—		—		—		—
Total Operating Revenues	$	670	$	69	$	53	$	122	$	135
Nine months ended September 30, 2018
Customer class:
Residential	$	805	$	145	$	210	$	355	$	158
Commercial	571		80		85		165		64
Industrial	286		64		10		74		304
Other	99		13		22		35		24
Revenues from contracts with customers	1,761		302		327		629		550
Other operating revenues	9		1		1		2		—
Total Operating Revenues	$	1,770	$	303	$	328	$	631	$	550

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 condensed 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	(1.1		)
Impairment	—
September 30, 2018	$	15.2

XML

COMMON EQUITY

9 Months Ended

Sep. 30, 2018

Common Equity Note [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

COMMON EQUITY

SCANA shareholders approved the Merger Agreement at a special meeting on July 31, 2018. Certain regulatory approvals must be obtained and other conditions must be met before the merger may be consummated.

SCANA had 200 million shares of common stock authorized as of September 30, 2018 and December 31, 2017.

Authorized shares of SCE&G common stock were 50 million as of September 30, 2018 and December 31, 2017. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were issued and outstanding as of September 30, 2018 and December 31, 2017. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA.

In June 2018, SCANA made an equity contribution to GENCO of $20 million.

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. SCANA has agreed to obtain the consent of Dominion Energy, which consent cannot be unreasonably withheld, prior to making dividend payments to shareholders greater than $0.6125 per share for any quarter while the Merger Agreement is pending.

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 September 30, 2018 and 2017, retained earnings of approximately $99.9 million and $83.9 million, respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

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 September 30, 2018, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million.

SCEG

Common Equity Note [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

Authorized shares of SCE&G common stock were 50 million as of September 30, 2018 and December 31, 2017. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were issued and outstanding as of September 30, 2018 and December 31, 2017. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA.

In June 2018, SCANA made an equity contribution to GENCO of $20 million.

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. SCANA has agreed to obtain the consent of Dominion Energy, which consent cannot be unreasonably withheld, prior to making dividend payments to shareholders greater than $0.6125 per share for any quarter while the Merger Agreement is pending.

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 September 30, 2018 and 2017, retained earnings of approximately $99.9 million and $83.9 million, respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

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 September 30, 2018, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million.

XML

LONG-TERM AND SHORT-TERM DEBT

9 Months Ended

Sep. 30, 2018

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In June 2018, GENCO redeemed at maturity $160 million of 6.06% secured notes. The repayment was funded using a combination of utility 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 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.

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

Liquidity

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. Committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Committed LOC, outstanding LOC advances, commercial paper, and LOC-supported letter of credit obligations were as follows: 

September 30, 2018 (Millions of dollars)	Total		SCANA			Consolidated SCE&G			PSNC  Energy
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
LOC advances	40.0		40.0			—			—
Weighted average interest rate			3.78		%	—			—
Outstanding commercial paper (270 or fewer days)	314.2		3.7			173.2			137.3
Weighted average interest rate			3.20		%	3.21		%	3.13		%
Letters of credit supported by LOC	37.6		37.3			0.3			—
Available	$	1,608.2	$	319.0		$	1,226.5		$	62.7

December 31, 2017 (Millions of dollars)	Total		SCANA		Consolidated SCE&G			PSNC  Energy
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

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.

In September 2018, SCANA borrowed $40 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at September 30, 2018 was 3.78%, and this draw is classified as long-term debt. Proceeds from the draw were deposited with two natural gas suppliers to provide contractually required credit support, and this deposit is reflected within other assets on the condensed consolidated balance sheet.

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 ongoing proceedings involving the ORS and Act 258, as well as the pending 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.

Proceeds received under or arising from the monetization of the Toshiba Settlement in 2017 have been utilized to repay maturing commercial paper balances, which short-term borrowings had been incurred primarily for the construction of Unit 2 and Unit 3 prior to the decision to stop their construction (see Note 10). Should the SCPSC or a court direct that these proceeds be refunded to customers in the near-term, or direct that such funds be escrowed or otherwise made unavailable to SCE&G, it is anticipated that SCE&G would issue commercial paper, draw on its credit facilities or issue long-term debt or the Company would issue equity to fund such requirement. However, if the SCPSC were to rule in favor of the ORS in response to the Request that SCE&G suspend collections from customers of amounts previously authorized under the BLRA, if the temporary rate reduction arising from the implementation of Act 258 were to remain in effect following the order of the SCPSC arising from the Joint Petition, or were other actions of the SCPSC or others taken in order to significantly restrict SCE&G’s access to revenues or impose additional adverse refund obligations on SCE&G, the Company’s and Consolidated SCE&G's assessments regarding the recoverability of all or a portion of the remaining balance of unrecovered Nuclear Project costs would be adversely impacted (see Note 2 and Note 10). Further, the recognition of significant additional impairment losses with respect to unrecovered Nuclear Project costs could increase the Company’s and Consolidated SCE&G’s debt to total capitalization to a level which may limit their ability to borrow under their commercial paper programs or under their credit facilities. Borrowing costs for long-term debt issuances could also be impacted.

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. These 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 three and nine months ended September 30, 2018, Consolidated SCE&G recorded interest income from money pool transactions of $1.1 million and $2.5 million, respectively, and for the same periods Consolidated SCE&G recorded interest expense from money pool transactions of $1.1 million and $2.5 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 $195 million and investments due from an affiliate of $177 million at September 30, 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 condensed consolidated balance sheet, Consolidated SCE&G includes money pool borrowings within Affiliated payables and money pool investments within Affiliated companies receivables.

SCEG

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In June 2018, GENCO redeemed at maturity $160 million of 6.06% secured notes. The repayment was funded using a combination of utility 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 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.

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

Liquidity

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. Committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Committed LOC, outstanding LOC advances, commercial paper, and LOC-supported letter of credit obligations were as follows: 

September 30, 2018 (Millions of dollars)	Total		SCANA			Consolidated SCE&G			PSNC  Energy
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
LOC advances	40.0		40.0			—			—
Weighted average interest rate			3.78		%	—			—
Outstanding commercial paper (270 or fewer days)	314.2		3.7			173.2			137.3
Weighted average interest rate			3.20		%	3.21		%	3.13		%
Letters of credit supported by LOC	37.6		37.3			0.3			—
Available	$	1,608.2	$	319.0		$	1,226.5		$	62.7

December 31, 2017 (Millions of dollars)	Total		SCANA		Consolidated SCE&G			PSNC  Energy
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

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.

In September 2018, SCANA borrowed $40 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at September 30, 2018 was 3.78%, and this draw is classified as long-term debt. Proceeds from the draw were deposited with two natural gas suppliers to provide contractually required credit support, and this deposit is reflected within other assets on the condensed consolidated balance sheet.

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 ongoing proceedings involving the ORS and Act 258, as well as the pending 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.

Proceeds received under or arising from the monetization of the Toshiba Settlement in 2017 have been utilized to repay maturing commercial paper balances, which short-term borrowings had been incurred primarily for the construction of Unit 2 and Unit 3 prior to the decision to stop their construction (see Note 10). Should the SCPSC or a court direct that these proceeds be refunded to customers in the near-term, or direct that such funds be escrowed or otherwise made unavailable to SCE&G, it is anticipated that SCE&G would issue commercial paper, draw on its credit facilities or issue long-term debt or the Company would issue equity to fund such requirement. However, if the SCPSC were to rule in favor of the ORS in response to the Request that SCE&G suspend collections from customers of amounts previously authorized under the BLRA, if the temporary rate reduction arising from the implementation of Act 258 were to remain in effect following the order of the SCPSC arising from the Joint Petition, or were other actions of the SCPSC or others taken in order to significantly restrict SCE&G’s access to revenues or impose additional adverse refund obligations on SCE&G, the Company’s and Consolidated SCE&G's assessments regarding the recoverability of all or a portion of the remaining balance of unrecovered Nuclear Project costs would be adversely impacted (see Note 2 and Note 10). Further, the recognition of significant additional impairment losses with respect to unrecovered Nuclear Project costs could increase the Company’s and Consolidated SCE&G’s debt to total capitalization to a level which may limit their ability to borrow under their commercial paper programs or under their credit facilities. Borrowing costs for long-term debt issuances could also be impacted.

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. These 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 three and nine months ended September 30, 2018, Consolidated SCE&G recorded interest income from money pool transactions of $1.1 million and $2.5 million, respectively, and for the same periods Consolidated SCE&G recorded interest expense from money pool transactions of $1.1 million and $2.5 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 $195 million and investments due from an affiliate of $177 million at September 30, 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 condensed 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

9 Months Ended

Sep. 30, 2018

income tax [Line Items]

Income Tax Disclosure [Text Block]

6.    INCOME TAXES

The Company files consolidated federal income tax returns which include Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns.

The Company’s federal returns through 2007 are closed by statute. In addition, federal returns for 2008 and 2009 are closed except to the extent of the examination of amended return claims discussed below. Federal returns for years 2010 through 2017 are currently being examined as noted 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.

During 2013 and 2014, the Company amended certain of its income tax returns for 2008 through 2012 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, 2017 and 2018, 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, 2016 and 2017 income tax returns. 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 2008-2012 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 are 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 are recorded as unrecognized tax benefits in the financial statements. Also, 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, would instead be expected to be deductible in 2017 under IRC Section 165. The abandonment loss deduction is also considered an uncertain tax position; however, under relevant accounting guidance, no estimated unrecognized tax benefits were recorded as of September 30, 2018. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, credits, and certain unrecognized state tax benefits.

As of September 30, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $98 million ($19 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, $98 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. These unrecognized tax benefits are not expected to increase significantly within the next 12 months. It is also 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 September 30, 2018 (see Note 10).

In connection with the research and experimentation deduction and credit claims reflected on the 2015, 2016 and 2017 income tax returns and under the provisions of an SCPSC order, the Company and Consolidated SCE&G recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, with the expectation that these deferred costs and related interest thereon would be recoverable through customer rates in future years. However, an impairment loss with respect to such deferred regulatory asset was recorded in 2017 (see Note 10).

Also under the provisions of an SCPSC order, estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 and 2016 income tax returns was deferred as a regulatory asset and was expected to be recoverable through customer rates in future years. An impairment loss with respect to these deferred amounts was also recorded as of December 31, 2017 (see Note 10). Otherwise, 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. Related to the unrecognized tax benefits noted above, the Company and Consolidated SCE&G accrued interest expense of $6.8 million and interest income of $1.4 million during 2018. Amounts recorded for such interest income and interest expense were mostly deferred within regulatory assets during 2017, and such deferred amounts were subsequently included within the impairment loss recorded by the Company and Consolidated SCE&G in 2017. Penalties were not material in either period presented.

In December of 2017, the Tax Act was enacted to lower the federal statutory corporate tax rate from 35% to 21%. The rate change resulted in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory corporate tax rate as of December 31, 2017. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in deferred income tax balances within regulatory liabilities. As of September 30, 2018, the amortization of amounts arising from remeasurement have not significantly affected the Company’s or Consolidated SCE&G’s effective tax rate for 2018 due to such amortization being deferred pending implementation of decisions by regulators prescribing how the benefits of such excess deferred tax amounts will be realized by customers. The Company filed a superseding 2017 consolidated income tax return on October 10, 2018. Adjustments to deferred income taxes resulting from the completion and filing of this return will be recorded in the fourth quarter of 2018 but are not expected to have a material impact on the Company’s or Consolidated SCE&G's financial position, results of operations, or cash flows.

The State of North Carolina lowered its corporate income tax rate to 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.

SCEG

income tax [Line Items]

Income Tax Disclosure [Text Block]

6.    INCOME TAXES

The Company files consolidated federal income tax returns which include Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns.

The Company’s federal returns through 2007 are closed by statute. In addition, federal returns for 2008 and 2009 are closed except to the extent of the examination of amended return claims discussed below. Federal returns for years 2010 through 2017 are currently being examined as noted 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.

During 2013 and 2014, the Company amended certain of its income tax returns for 2008 through 2012 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, 2017 and 2018, 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, 2016 and 2017 income tax returns. 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 2008-2012 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 are 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 are recorded as unrecognized tax benefits in the financial statements. Also, 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, would instead be expected to be deductible in 2017 under IRC Section 165. The abandonment loss deduction is also considered an uncertain tax position; however, under relevant accounting guidance, no estimated unrecognized tax benefits were recorded as of September 30, 2018. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, credits, and certain unrecognized state tax benefits.

As of September 30, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $98 million ($19 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, $98 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. These unrecognized tax benefits are not expected to increase significantly within the next 12 months. It is also 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 September 30, 2018 (see Note 10).

In connection with the research and experimentation deduction and credit claims reflected on the 2015, 2016 and 2017 income tax returns and under the provisions of an SCPSC order, the Company and Consolidated SCE&G recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, with the expectation that these deferred costs and related interest thereon would be recoverable through customer rates in future years. However, an impairment loss with respect to such deferred regulatory asset was recorded in 2017 (see Note 10).

Also under the provisions of an SCPSC order, estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 and 2016 income tax returns was deferred as a regulatory asset and was expected to be recoverable through customer rates in future years. An impairment loss with respect to these deferred amounts was also recorded as of December 31, 2017 (see Note 10). Otherwise, 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. Related to the unrecognized tax benefits noted above, the Company and Consolidated SCE&G accrued interest expense of $6.8 million and interest income of $1.4 million during 2018. Amounts recorded for such interest income and interest expense were mostly deferred within regulatory assets during 2017, and such deferred amounts were subsequently included within the impairment loss recorded by the Company and Consolidated SCE&G in 2017. Penalties were not material in either period presented.

In December of 2017, the Tax Act was enacted to lower the federal statutory corporate tax rate from 35% to 21%. The rate change resulted in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory corporate tax rate as of December 31, 2017. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in deferred income tax balances within regulatory liabilities. As of September 30, 2018, the amortization of amounts arising from remeasurement have not significantly affected the Company’s or Consolidated SCE&G’s effective tax rate for 2018 due to such amortization being deferred pending implementation of decisions by regulators prescribing how the benefits of such excess deferred tax amounts will be realized by customers. The Company filed a superseding 2017 consolidated income tax return on October 10, 2018. Adjustments to deferred income taxes resulting from the completion and filing of this return will be recorded in the fourth quarter of 2018 but are not expected to have a material impact on the Company’s or Consolidated SCE&G's financial position, results of operations, or cash flows.

The State of North Carolina lowered its corporate income tax rate to 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.

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DERIVATIVE FINANCIAL INSTRUMENTS

9 Months Ended

Sep. 30, 2018

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

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.  SCANA’s Board of Directors has 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 is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Board of Directors with regard to the management of risk and brings 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 that are designated as cash flow hedges may be 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 have not been 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 12 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 Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Gas Marketing	Total
As of September 30, 2018
Commodity contracts	7,050,000	16,856,000	23,906,000
Energy management contracts (a)	—	40,949,232	40,949,232
Total (a)	7,050,000	57,805,232	64,855,232
As of December 31, 2017
Commodity contracts	6,430,000	13,433,000	19,863,000
Energy management contracts (a)	—	41,856,890	41,856,890
Total (a)	6,430,000	55,289,890	61,719,890

(a)  Includes amounts related to basis swap contracts totaling 9,396,000 MMBTU in 2018 and 2,582,000 MMBTU 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	September 30, 2018		December 31, 2017		September 30, 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 September 30, 2018
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	2	—	$	1
	Other deferred credits and other liabilities	—		16		—	6
Commodity contracts	Prepayments	$	1	—		—	—
Total		$	1	$	18	—	$	7
Not designated as hedging instruments
Interest rate contracts	Other deferred credits and other liabilities	—		$	2	—	$	2
Commodity contracts	Prepayments	$	1	—		—	—
Energy management contracts	Prepayments	1		—		—	—
	Other current assets	1		—		—	—
	Other current liabilities	—		2		—	—
Total		$	3	$	4	—	$	2

		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of December 31, 2017
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	3	—		$	1
	Other deferred credits and other liabilities	—		24		—		9
Commodity contracts	Prepayments	—		2		—		—
	Other current assets	—		1		—		—
Total		—		$	30	—		$	10
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	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		—		—		—
	Derivative financial instruments	—		2		—		—
Total		$	59	$	8	$	54	$	5

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

Derivatives in Cash Flow Hedging Relationships

The Company and Consolidated SCE&G:
	Gain (Loss) Deferred in Regulatory Accounts						(Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	—		—			Interest expense	—			—
Nine Months Ended September 30,
Interest rate contracts	$	2	$	(1	)	Interest expense	$	(1	)	$	(1	)

The Company:
	Gain (Loss) Recognized in OCI, net of tax						Gain (Loss) Reclassified from AOCI into Income, net of tax
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	$	1	—			Interest expense	$	(3	)	$	(2	)
Total	$	1	—				$	(3	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	3	$	(1	)	Interest expense	$	(7	)	$	(6	)
Commodity contracts	2		(4		)	Gas purchased for resale	(2		)	2
Total	$	5	$	(5	)		$	(9	)	$	(4	)

As of September 30, 2018, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $0.5 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.9 million as an increase to interest expense.  Reclassifications related to commodity and energy management contracts are not expected to be significant. As of September 30, 2018, all of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2021.

As of September 30, 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 $1.0 million 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 during all periods presented.

Derivatives Not designated as Hedging Instruments
The Company and Consolidated SCE&G:
	Gain (Loss) Deferred in Regulatory Accounts						Gain (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	$	1	$	(6	)	Interest Expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	66	$	(30	)	Interest Expense	$	(2	)	$	(2	)
						Other Income	115			—

As of September 30, 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	September 30, 2018			December 31, 2017		September 30, 2018		December 31, 2017
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	20.8		$	33.7	$	8.7	$	14.7
Fair value of collateral already posted	22.3			28.9		8.7		10.1
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	(1.5	)	$	4.8	—		$	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, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of $0.3 million related to $2.9 million in commodity derivatives that are in a net asset position at September 30, 2018, compared to letters of credit in the amount of $1.2 million related to derivatives of $4.0 million at December 31, 2017, if all the contingent features underlying these instruments had been fully triggered.

Information related to the offsetting of derivative assets and derivative liabilities 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 September 30, 2018
Gross Amounts of Recognized Assets	—		$	2	$	2	$	4	—
Gross Amounts Offset in Statement of Financial Position	—		—		—		—		—
Net Amounts Presented in Statement of Financial Position	—		2		2		4		—
Gross Amounts Not Offset - Financial Instruments	—		—		—		—		—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—		—		—
Net Amount	—		$	2	$	2	$	4	—
Balance sheet location
Prepayments							$	3	—
Other current assets							1		—
Total							$	4	—
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

Derivative Liabilities
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of September 30, 2018
Gross Amounts of Recognized Liabilities	$	20		—		$	2		$	22		$	9
Gross Amounts Offset in Statement of Financial Position	—			—		—			—			—
Net Amounts Presented in Statement of Financial Position	20			—		2			22			9
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(21		)	—		(1		)	(22		)	(9		)
Net Amount	$	(1	)	—		$	1		—			—
Balance sheet location
Derivative financial instruments									$	2		$	1
Other current liabilities									2			—
Other deferred credits and other liabilities									18			8
Total									$	22		$	9
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		)	27			—
Net Amount	$	60		$	3	$	1		$	64		$	15
Balance sheet location
Other current assets									$	2		—
Derivative financial instruments									7			$	2
Other deferred credits and other liabilities									28			13
Total									$	37		$	15

SCEG

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

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.  SCANA’s Board of Directors has 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 is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Board of Directors with regard to the management of risk and brings 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 that are designated as cash flow hedges may be 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 have not been 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 12 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 Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Gas Marketing	Total
As of September 30, 2018
Commodity contracts	7,050,000	16,856,000	23,906,000
Energy management contracts (a)	—	40,949,232	40,949,232
Total (a)	7,050,000	57,805,232	64,855,232
As of December 31, 2017
Commodity contracts	6,430,000	13,433,000	19,863,000
Energy management contracts (a)	—	41,856,890	41,856,890
Total (a)	6,430,000	55,289,890	61,719,890

(a)  Includes amounts related to basis swap contracts totaling 9,396,000 MMBTU in 2018 and 2,582,000 MMBTU 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	September 30, 2018		December 31, 2017		September 30, 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 September 30, 2018
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	2	—	$	1
	Other deferred credits and other liabilities	—		16		—	6
Commodity contracts	Prepayments	$	1	—		—	—
Total		$	1	$	18	—	$	7
Not designated as hedging instruments
Interest rate contracts	Other deferred credits and other liabilities	—		$	2	—	$	2
Commodity contracts	Prepayments	$	1	—		—	—
Energy management contracts	Prepayments	1		—		—	—
	Other current assets	1		—		—	—
	Other current liabilities	—		2		—	—
Total		$	3	$	4	—	$	2

		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of December 31, 2017
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	3	—		$	1
	Other deferred credits and other liabilities	—		24		—		9
Commodity contracts	Prepayments	—		2		—		—
	Other current assets	—		1		—		—
Total		—		$	30	—		$	10
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	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		—		—		—
	Derivative financial instruments	—		2		—		—
Total		$	59	$	8	$	54	$	5

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

Derivatives in Cash Flow Hedging Relationships

The Company and Consolidated SCE&G:
	Gain (Loss) Deferred in Regulatory Accounts						(Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	—		—			Interest expense	—			—
Nine Months Ended September 30,
Interest rate contracts	$	2	$	(1	)	Interest expense	$	(1	)	$	(1	)

The Company:
	Gain (Loss) Recognized in OCI, net of tax						Gain (Loss) Reclassified from AOCI into Income, net of tax
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	$	1	—			Interest expense	$	(3	)	$	(2	)
Total	$	1	—				$	(3	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	3	$	(1	)	Interest expense	$	(7	)	$	(6	)
Commodity contracts	2		(4		)	Gas purchased for resale	(2		)	2
Total	$	5	$	(5	)		$	(9	)	$	(4	)

As of September 30, 2018, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $0.5 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.9 million as an increase to interest expense.  Reclassifications related to commodity and energy management contracts are not expected to be significant. As of September 30, 2018, all of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2021.

As of September 30, 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 $1.0 million 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 during all periods presented.

Derivatives Not designated as Hedging Instruments
The Company and Consolidated SCE&G:
	Gain (Loss) Deferred in Regulatory Accounts						Gain (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	$	1	$	(6	)	Interest Expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	66	$	(30	)	Interest Expense	$	(2	)	$	(2	)
						Other Income	115			—

As of September 30, 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	September 30, 2018			December 31, 2017		September 30, 2018		December 31, 2017
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	20.8		$	33.7	$	8.7	$	14.7
Fair value of collateral already posted	22.3			28.9		8.7		10.1
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	(1.5	)	$	4.8	—		$	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, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of $0.3 million related to $2.9 million in commodity derivatives that are in a net asset position at September 30, 2018, compared to letters of credit in the amount of $1.2 million related to derivatives of $4.0 million at December 31, 2017, if all the contingent features underlying these instruments had been fully triggered.

Information related to the offsetting of derivative assets and derivative liabilities 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 September 30, 2018
Gross Amounts of Recognized Assets	—		$	2	$	2	$	4	—
Gross Amounts Offset in Statement of Financial Position	—		—		—		—		—
Net Amounts Presented in Statement of Financial Position	—		2		2		4		—
Gross Amounts Not Offset - Financial Instruments	—		—		—		—		—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—		—		—
Net Amount	—		$	2	$	2	$	4	—
Balance sheet location
Prepayments							$	3	—
Other current assets							1		—
Total							$	4	—
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

Derivative Liabilities
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of September 30, 2018
Gross Amounts of Recognized Liabilities	$	20		—		$	2		$	22		$	9
Gross Amounts Offset in Statement of Financial Position	—			—		—			—			—
Net Amounts Presented in Statement of Financial Position	20			—		2			22			9
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(21		)	—		(1		)	(22		)	(9		)
Net Amount	$	(1	)	—		$	1		—			—
Balance sheet location
Derivative financial instruments									$	2		$	1
Other current liabilities									2			—
Other deferred credits and other liabilities									18			8
Total									$	22		$	9
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		)	27			—
Net Amount	$	60		$	3	$	1		$	64		$	15
Balance sheet location
Other current assets									$	2		—
Derivative financial instruments									7			$	2
Other deferred credits and other liabilities									28			13
Total									$	37		$	15

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

9 Months Ended

Sep. 30, 2018

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Disclosures [Text Block]

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 September 30, 2018						As of December 31, 2017
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	15	—		—		$	119	—		$	100	—
Held to maturity securities	—		$	6	—		—		$	6	—		—
Interest rate contracts	—		—		—		—		54		—		$	54
Commodity contracts	2		—		—		1		—		—		—
Energy management contracts	—		2		—		—		4		—		—
Liabilities:
Interest rate contracts	—		20		$	9	—		32		—		15
Commodity contracts	—		—		—		2		1		—		—
Energy management contracts	—		4		—		1		4		—		—

The Company and Consolidated SCE&G had no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during either period presented.

Financial instruments for which the carrying amount may not equal estimated fair value were as follows:

Long-Term Debt	September 30, 2018				December 31, 2017
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,753.3	$	6,980.8	$	6,632.9	$	7,399.7
Consolidated SCE&G	5,145.2		5,295.2		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 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.

SCEG

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Disclosures [Text Block]

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 September 30, 2018						As of December 31, 2017
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	15	—		—		$	119	—		$	100	—
Held to maturity securities	—		$	6	—		—		$	6	—		—
Interest rate contracts	—		—		—		—		54		—		$	54
Commodity contracts	2		—		—		1		—		—		—
Energy management contracts	—		2		—		—		4		—		—
Liabilities:
Interest rate contracts	—		20		$	9	—		32		—		15
Commodity contracts	—		—		—		2		1		—		—
Energy management contracts	—		4		—		1		4		—		—

The Company and Consolidated SCE&G had no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during either period presented.

Financial instruments for which the carrying amount may not equal estimated fair value were as follows:

Long-Term Debt	September 30, 2018				December 31, 2017
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,753.3	$	6,980.8	$	6,632.9	$	7,399.7
Consolidated SCE&G	5,145.2		5,295.2		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 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.

XML

EMPLOYEE BENEFIT PLANS

9 Months Ended

Sep. 30, 2018

Pension and Other Postretirement Benefit Plans

Pension and Other Postretirement Benefits Disclosure [Text Block]

9.    EMPLOYEE BENEFIT PLANS

Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows: 

The Company	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017
Three months ended September 30,
Service cost	$	5.9		$	5.7		$	1.1		$	1.0
Interest cost	8.5			9.2			2.2			2.8
Expected return on assets	(14.0		)	(13.4		)	—			—
Prior service cost amortization	0.1			0.4			—			—
Amortization of actuarial (gains) losses	3.7			4.4			(0.5		)	—
Net periodic benefit cost	$	4.2		$	6.3		$	2.8		$	3.8
Nine months ended September 30,
Service cost	$	15.8		$	16.3		$	3.4		$	3.4
Interest cost	25.6			28.0			7.6			8.6
Expected return on assets	(42.6		)	(41.0		)	—			—
Prior service cost amortization	0.4			1.2			—			—
Amortization of actuarial losses	9.6			12.2			0.6			0.8
Net periodic benefit cost	$	8.8		$	16.7		$	11.6		$	12.8

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017
Three months ended September 30,
Service cost	$	4.8		$	4.8		$	0.9		$	0.8
Interest cost	7.2			7.8			1.7			2.3
Expected return on assets	(11.8		)	(11.4		)	—			—
Prior service cost amortization	0.1			0.3			—			—
Amortization of actuarial (gains) losses	3.1			3.7			(0.4		)	—
Net periodic benefit cost	$	3.4		$	5.2		$	2.2		$	3.1
Nine months ended September 30,
Service cost	$	12.9		$	13.6		$	2.7		$	2.8
Interest cost	21.6			24.0			6.0			7.1
Expected return on assets	(36.0		)	(35.0		)	—			—
Prior service cost amortization	0.3			1.0			—			—
Amortization of actuarial losses	8.1			10.4			0.5			0.6
Net periodic benefit cost	$	6.9		$	14.0		$	9.2		$	10.5

No significant contribution to the pension trust is expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either 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 rat

SCEG

Pension and Other Postretirement Benefit Plans

Pension and Other Postretirement Benefits Disclosure [Text Block]

9.    EMPLOYEE BENEFIT PLANS

Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows: 

The Company	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017
Three months ended September 30,
Service cost	$	5.9		$	5.7		$	1.1		$	1.0
Interest cost	8.5			9.2			2.2			2.8
Expected return on assets	(14.0		)	(13.4		)	—			—
Prior service cost amortization	0.1			0.4			—			—
Amortization of actuarial (gains) losses	3.7			4.4			(0.5		)	—
Net periodic benefit cost	$	4.2		$	6.3		$	2.8		$	3.8
Nine months ended September 30,
Service cost	$	15.8		$	16.3		$	3.4		$	3.4
Interest cost	25.6			28.0			7.6			8.6
Expected return on assets	(42.6		)	(41.0		)	—			—
Prior service cost amortization	0.4			1.2			—			—
Amortization of actuarial losses	9.6			12.2			0.6			0.8
Net periodic benefit cost	$	8.8		$	16.7		$	11.6		$	12.8

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017
Three months ended September 30,
Service cost	$	4.8		$	4.8		$	0.9		$	0.8
Interest cost	7.2			7.8			1.7			2.3
Expected return on assets	(11.8		)	(11.4		)	—			—
Prior service cost amortization	0.1			0.3			—			—
Amortization of actuarial (gains) losses	3.1			3.7			(0.4		)	—
Net periodic benefit cost	$	3.4		$	5.2		$	2.2		$	3.1
Nine months ended September 30,
Service cost	$	12.9		$	13.6		$	2.7		$	2.8
Interest cost	21.6			24.0			6.0			7.1
Expected return on assets	(36.0		)	(35.0		)	—			—
Prior service cost amortization	0.3			1.0			—			—
Amortization of actuarial losses	8.1			10.4			0.5			0.6
Net periodic benefit cost	$	6.9		$	14.0		$	9.2		$	10.5

No significant contribution to the pension trust is expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either 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 rat

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COMMITMENTS AND CONTINGENCIES

6 Months Ended

9 Months Ended

Jun. 30, 2018

Sep. 30, 2018

Statement [Line Items]

Commitments and Contingencies Disclosure [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. Various difficulties were encountered which affected the ability of the Consortium to adhere to established budgets and construction schedules for the Nuclear Project and which, in light of Santee Cooper's decision to suspend construction of the Nuclear Project, led to the Company's decision on July 31, 2017 to stop the construction and seek cost recovery under the abandonment provisions of the BLRA. These difficulties and other developments occurring prior to the bankruptcy filing by WEC and WECTEC and other matters are described in Note 10 to the consolidated financial statements included in the Company's and Consolidated SCE&G's combined Form 10-K for the year ended December 31, 2017. Significant developments and continuing contingencies and uncertainties regarding the abandoned Nuclear Project subsequent to December 31, 2017 are discussed below.

EPC Contract and BLRA 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 assert against WEC and WECTEC any and all claims that are based thereon or that may be 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 $290 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 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 below. 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. The proceeds received under or arising from the monetization of the Toshiba Settlement are recorded as a regulatory liability on the accompanying condensed consolidated balance sheets, as the net value of the proceeds will be utilized to benefit SCE&G's customers in a manner to be determined by the SCPSC.

As described 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 the reduction. On January 2, 2018, the purchase agreement with Citibank was amended to limit the amount that SCE&G and Santee Cooper could be required to reimburse Citibank for valid subcontractor and vendor pre-petition liens to $60 million ($33 million for SCE&G's 55% share).

Regulatory, Political and Legal Developments

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

On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, and in reliance on the opinion from the Office of Attorney General, the ORS filed the Request seeking an order from the SCPSC directing SCE&G to immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS, which the ORS believes should have been disclosed, that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections. On October 17, 2017, the ORS filed a motion with the SCPSC to amend the Request, in which motion the ORS asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. See Claims and Litigation herein for additional discussions regarding regarding the constitutionality of the BLRA.

On December 20, 2017, the SCPSC denied a motion by SCE&G to dismiss the Request. Parties who have intervened in the Request or who filed a letter in support of it include the state's Governor, Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, Santee Cooper, the SCEUC, certain large industrial customers, and several environmental groups. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets, including the Request, regarding the merits of the Joint Petition and related issues. This schedule was established in response to legislation described below. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the outcome of this matter. See also Note 2.

In 2017, special committees of the South Carolina General Assembly, both in the House of Representatives and in the Senate, conducted public hearings regarding the Company's decision to abandon the Nuclear Project. Several legislative proposals adverse to the Company and Consolidated SCE&G resulted from the work of these committees, two of which became law in 2018 and are described below.

On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA. Act 258 requires the SCPSC to order a reduction in 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%, or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On July 2 and 3, 2018, the SCPSC issued orders implementing the temporary rate reduction required by Act 258. The resulting new rates and retroactive credits required by Act 258 were put into effect in August 2018, with the retroactive credits for the second quarter being applied in August's billing cycles. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 alters certain provisions previously applicable under the BLRA, including redefining the standard of care required by the BLRA 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.

On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented.

Proposals to Resolve Outstanding Issues

On November 16, 2017, SCE&G announced for public consideration a proposal to resolve outstanding issues relating to the Nuclear Project. Under the proposal, SCE&G electric customers were to receive a 3.5% electric rate reduction, the addition of an existing 540-MW natural gas fired power plant by SCE&G with the acquisition cost borne by SCANA shareholders, and the addition of approximately 100-MW of large scale solar energy by SCE&G. The proposal also provided for the recovery of the nuclear construction costs (net of the proceeds of the Toshiba Settlement not utilized for satisfaction of project liens) over 50 years. While SCE&G’s proposal was not formally submitted for regulatory approval at that time, discussions with key stakeholders over the ensuing weeks indicated that SCE&G's proposal would not be sufficient to resolve the outstanding issues.

On January 2, 2018, SCANA entered into the Merger Agreement with Dominion Energy, and on January 12, 2018, SCE&G and Dominion Energy filed the Joint Petition requesting SCPSC approval of the merger or a finding that either the merger is in the public interest or that there is an absence of harm arising from the merger. In this petition, the parties committed to providing an up-front, one time rate credit to SCE&G's electric customers totaling approximately $1.3 billion within 90 days of the merger's closing, providing at least a 5% reduction in customer bills (later adjusted to approximately 7% in light of the effects of the Tax Act), shortening the amortization period for costs related to the Nuclear Project to 20 years, forgoing recovery of approximately $1.7 billion in costs related to the Nuclear Project, and purchasing an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers.

On October 25, 2018, in response to the desire of various parties to the Concurrent Dockets for an alternative that would further reduce customer bills, Dominion Energy filed with the SCPSC the Alternative Customer Benefits Plan (Alternative Plan). The testimony filed by Dominion Energy in connection with the Alternative Plan indicates that customers would receive refunds totaling approximately $1.91 billion with approximately $1.0 billion being refunded evenly over 20 years and approximately $880 million credited to customers over approximately ten years instead of the up-front, one time rate credit of $1.3 billion originally proposed in the Joint Petition. In addition, such testimony indicates that approximately $2.3 billion in costs related to the Nuclear Project would not be recovered in connection with the Alternative Plan, instead of the $1.7 billion originally proposed. The parties to the Joint Petition estimate that these changes would result in customer bill reductions of approximately 14% (including the effects of the Tax Act). The Alternative Plan also contemplates the purchase of an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers.

The ORS has filed direct and rebuttal testimony and a pre-hearing brief related to the Concurrent Dockets. In these filings, the ORS has proposed (ORS Plan) that the SCPSC reduce SCE&G's electric rates during the 12 months following the effective date of its order by approximately $561 million compared to rates that would otherwise be in effect when the temporary rate reduction under Act 258 expires. This proposal includes reductions due to assumed merger synergies, the use of an ROE of 9.1% rather than 10.25% (which proposed ROE would be applied to a smaller rate base after all adjustments specified by the ORS), the ORS calculation of savings from the Tax Act (which exceeds SCE&G's calculation), the refund of amounts deferred as subject to refund that arise from the Tax Act and other adjustments. After 12 months (after amounts subject to refund have been returned to customers), the ORS proposes that SCE&G's electric rates be modified to an amount that would be approximately $528 million lower annually compared to rates that would otherwise be in effect when the temporary rate reduction under Act 258 expires.

On October 25, 2018, in testimony filed in connection with the Concurrent Dockets, a representative of Dominion Energy noted that (1) the ORS Plan, if adopted, would be devastating not only to the proposed merger but also to SCE&G's future and to the interests of SCE&G's customers and the state of South Carolina in reliable electric service at just and reasonable rates and (2) there is currently pending litigation in the South Carolina state courts in which the judge has indicated that he is considering issuing an order that would violate the "no change in law" provision of the Merger Agreement, and that if such an order were issued or the ORS Plan is adopted, the merger would be unable to close.

On October 26, 2018, Santee Cooper filed a pre-hearing brief with respect to the Joint Petition. In its filing, Santee Cooper requested that the SCPSC not approve a merger between SCANA and Dominion Energy as being in the public interest unless SCANA and Dominion Energy commit to creating a fund of approximately $351 million to mitigate the financial impact of the abandonment of the Nuclear Project on Santee Cooper's wholesale and retail customers. Santee Cooper proposes that the cost of creating such a fund should not be recoverable from SCE&G's customers.

On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets regarding the merits of the Joint Petition and related issues, and as noted above, pursuant to S. 954 the SCPSC is required to issue an order related to the Joint Petition no later than December 21, 2018. No assurance can be given as to the timing or outcome of efforts to consummate the Merger Agreement or to obtain approval of the Joint Petition.

On May 9, 2018, SCE&G completed its purchase of CEC, the existing 540-MW natural gas fired power plant referred to above, for approximately $180 million. As disclosed in Note 10 to the Company's and Consolidated SCE&G's Form 10-K for December 31, 2017, an impairment loss recorded in the fourth quarter of 2017 included $180 million related to SCE&G's commitment to not seek recovery from customers for the acquisition cost of this natural gas fired power plant, and accordingly, this amount was recorded as a reduction to unrecovered Nuclear Project costs within regulatory assets on the Company's and Consolidated SCE&G's consolidated balance sheets at December 31, 2017. As such, the Company's and Consolidated SCE&G's condensed consolidated balance sheet as of September 30, 2018 reflect the cost for CEC within Utility Plant in Service, and the $180 million impairment initially recorded as unrecovered Nuclear Project costs within regulatory assets is now reflected within Accumulated Depreciation and Amortization, which results in the carrying value of CEC being entirely written off. SCE&G’s commitment to not seek recovery from customers for the acquisition cost of CEC was one element of certain broader rate mitigation proposals contained within the Joint Petition and the Alternative Plan. Assuming that the SCPSC approves either of the mitigating proposals as outlined in the Joint Petition or approves the Alternative Plan, SCE&G will not seek recovery of CEC acquisition costs. 

Impairment Considerations

At September 30, 2018, SCE&G estimated that revised rates collections previously approved under the BLRA totaled approximately $445 million annually. SCE&G estimates that such revised rates collections for 2018 would be reduced by approximately $279 million if Act 258 remains in effect and is implemented through December 21, 2018, which is the expected pendency of the SCPSC proceeding with respect to the Joint Petition. New rates are expected to be ordered by the SCPSC in connection with its order on the Joint Petition, which order is to be issued no later than December 21, 2018. On a cumulative basis, at September 30, 2018, SCE&G estimated that revised rates collections previously approved under the BLRA totaled approximately $2.1 billion, which amount reflects the impacts of Act 258.

For each of the quarters ended June 30, 2018, September 30, 2018 and December 31, 2018, SCANA's Board of Directors declared a dividend of $0.1237 per share, which represents an approximately 80% reduction from the $0.6125 per share paid on SCANA’s common stock for the first quarter of 2018. This reduction corresponds to the portion of the dividend attributable to SCE&G's electric operations and serves to partially mitigate the liquidity impacts arising from the reduced revenues and cash flows resulting from the implementation of Act 258.

Under the current regulatory construct in South Carolina, pursuant to the BLRA or through other means, the ability of SCE&G to recover costs incurred in connection with Unit 2 and Unit 3, and a reasonable return on them, will be subject to review and approval by the SCPSC. In light of the contentious nature of activity involving the General Assembly and other officials and the Request being considered by the SCPSC that could result in the suspension of all rates currently being collected under the BLRA, as well as the return of such amounts previously collected, there is significant uncertainty as to SCE&G’s ultimate ability to recover its costs of Unit 2 and Unit 3 and a return on them from its customers. See also Claims and Litigation herein for additional discussion regarding the constitutionality of the BLRA. SCE&G continues to contest the specific challenges described above. However, based on the consideration of those challenges, and particularly in light of SCE&G's proposed solution announced on November 16, 2017 and details in the Joint Petition filed by SCE&G and Dominion Energy with the SCPSC on January 12, 2018, the Company and Consolidated SCE&G determined that a disallowance of recovery of part of the cost of the abandoned Nuclear Project is both probable and reasonably estimable under applicable accounting guidance. In addition, the Company and Consolidated SCE&G determined that full recovery of certain other related costs deferred within regulatory assets is less than probable. As a result, in 2017 the Company and Consolidated SCE&G recognized a pre-tax impairment loss totaling $1.118 billion ($690 million net of tax). Also, in the first quarter of 2018, the Company and Consolidated SCE&G recognized an additional pre-tax impairment loss of approximately $3.6 million ($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.

It is reasonably possible that a change in estimated impairment loss could occur in the near term and could be material; however, all such changes cannot be reasonably estimated. The impairment loss recorded in 2017 reflects impacts similar to those that would have resulted had the proposed solution announced on November 16, 2017 been implemented. If the merger benefits and cost recovery plan outlined in the Joint Petition are implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $1.7 billion (approximately $1.3 billion net of tax) would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $813 million recorded within regulatory assets, the write-off of unrecovered Nuclear Project costs of approximately $86 million recorded within Utility Plant, and the recording of additional liabilities for customer refunds totaling approximately $1.875 billion, net of approximately $1.065 billion, which amount represents the monetization of guaranty settlement recorded within regulatory liabilities less amounts that may be required to satisfy contractor liens.

If the Alternative Plan were implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $2.3 billion (approximately $1.7 billion net of tax) would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $1.368 billion recorded within regulatory assets, the write-off of unrecovered Nuclear Project costs of approximately $86 million recorded within Utility Plant, and the recording of additional liabilities for customer refunds of approximately $880 million. In addition, the Alternative Plan provides for the refunding of the existing regulatory liability associated with the monetization of guaranty settlement over 20 years less amounts that may be required to satisfy contractor liens.

If (i) the SCPSC does not approve the Joint Petition or the Alternative Plan and instead approves the Request by the ORS; (ii) the BLRA is found to be unconstitutional; or (iii) the General Assembly further amends or revokes the BLRA or approves other legislation with a similar effect, the Company and Consolidated SCE&G may be required to record an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $5.0 billion (approximately $3.7 billion net of tax). This additional impairment loss would result from the write-off of approximately $3.960 billion in regulatory assets (comprised of remaining unrecovered Nuclear Project costs of $4.140 billion offset by $180 million in previously impaired costs related to CEC, which would result from the proposals put forward in the Joint Petition or the Alternative Plan not being approved by the SCPSC) and the refund of revised rates collections under the BLRA described above of approximately $2.1 billion (comprised of the revised rates collections on a cumulative basis as of September 30, 2018 and reflective of the impacts of Act 258), net of approximately $1.065 billion, which amount represents the monetization of guaranty settlement recorded within regulatory liabilities less amounts that may be required to satisfy contractor liens. The Company and Consolidated SCE&G do not currently anticipate that any amounts collected prior to April 1, 2018, will be subject to refund (other than amounts arising from the effects of the Tax Act); however, no assurance can be given as to the outcome of this matter. See Claims and Litigation herein for additional discussion regarding the constitutionality of the BLRA.

At September 30, 2018, the Company and Consolidated SCE&G included considerations of the impact of Act 258 in the evaluation as to their ability to recover the remaining Nuclear Project costs and a reasonable return on those costs. Because Act 258 explicitly provides for an experimental rate that is temporary and does not disallow any of the costs currently deferred as a regulatory asset, and because the experimental rate is to be replaced by rates that the SCPSC is to determine and order no later than December 21, 2018, the Company and Consolidated SCE&G have concluded that additional impairment charges related to unrecovered Nuclear Project costs are not probable, and the recording of such charges would not be appropriate, at this time. However, if a disallowance were ordered or the rates under Act 258 were made other than temporary by the SCPSC in the Joint Petition proceeding, the Company and Consolidated SCE&G would reevaluate this conclusion. Were the rates under Act 258 made other than temporary following the SCPSC's final decision on the Joint Petition, and without consideration of any other factors that may be embodied in such an order, an additional pre-tax impairment charge totaling approximately $1.7 billion may be required.

In addition to the matters above, in the Joint Petition, the Company and Consolidated SCE&G proposed to remove from BLRA capital costs their investment in transmission assets that have been or will be placed in service and have not been abandoned. As of September 30, 2018, such investment in these assets total approximately $376 million (approximately $365 million within utility plant, net and approximately $11 million within regulatory assets, which amount represents certain deferred operating costs). The Company and Consolidated SCE&G believe that this investment represents assets that are or will be used to provide electric service to customers and that a recovery of and a reasonable return on the investment should be provided in future rates. During the hearing on the Concurrent Dockets, the SCPSC will consider a request by the ORS to allow the Company and Consolidated SCE&G to defer certain operating costs related to the investment and that a decision on the recovery of this investment, including operating costs deferrals, be addressed in a future rate proceeding. If the SCPSC were to disallow recovery of or a reasonable return on all or a portion of this investment, an impairment charge related to these assets totaling as much as approximately $376 million may be required.

Liquidity Considerations

              As a result of the legislative and regulatory reactions to the decision to stop construction of Unit 2 and Unit 3, downgrades by credit ratings agencies occurred.  The Company and Consolidated SCE&G have significant obligations that must be paid within the next 12 months, including long-term debt maturities and capital lease payments of $18 million for the Company (including $14 million for Consolidated SCE&G), short-term borrowings of $314 million for the Company (including $173 million for Consolidated SCE&G), interest payments of approximately $335 million for the Company (including $255 million for Consolidated SCE&G), future minimum payments for operating leases of $9 million for the Company (including $3 million for Consolidated SCE&G), and revenues collected subject to refund arising from the effects of the Tax Act of approximately $61 million for the Company and Consolidated SCE&G. Working capital requirements, such as those for fuel supply and similar obligations, also arise due to the lag between when such amounts are paid and when related collection of such costs through customer rates occurs. In addition, as described above under Impairment Considerations, SCE&G has been ordered to reduce revised rates previously approved under the BLRA by approximately $279 million in 2018. This reduction assumes that Act 258 remains in effect through December 21, 2018, which is the expected pendency of the SCPSC proceeding with respect to the Concurrent Dockets.

Also, any adverse final judgment by a court in any matter of litigation, or any levy for amounts assessed by a regulatory agency, including but not limited to matters described in Claims and Litigation below, could require the Company and/or Consolidated SCE&G to escrow funds or to post one or more bonds equal to the monetary amount of the judgment or assessment while the decision is being appealed or challenged.

              Management believes as of the date of issuance of these financial statements that it has access to available sources of cash to pay obligations when due over the next 12 months. These sources include committed, long-term lines of credit that expire in December 2020 totaling $1.8 billion for the Company (including $1.2 billion for Consolidated SCE&G). In addition, as of the date of issuance of these financial statements, SCE&G continues to collect the BLRA-related customer rates that remain after reductions ordered as a result of Act 258, as well as amounts provided for in other orders related to non-BLRA electric and gas rates. In 2018, however, certain of SCANA's credit ratings have fallen below investment grade, which has constrained its ability to issue commercial paper. The ability of Fuel Company and PSNC Energy to issue commercial paper has also been constrained.

Regulatory and legislative proceedings described above, and/or proceedings described under Claims and Litigation below, which are outside of the Company’s and Consolidated SCE&G’s control, have resulted in the temporary suspension of a substantial portion of the approximately $445 million annually of rates that were being collected under the BLRA, and may result in the permanent suspension of all or a portion of such amounts, the return of such amounts collected through September 30, 2018, of $2.1 billion, or the requirement that SCE&G's share of payments received from the Toshiba Settlement ($1.098 billion) be placed in escrow or be refunded to customers in the near term. Neither the Company nor Consolidated SCE&G can predict if or when these matters may be resolved or what additional actions, if any, may be proposed or taken, including other legislative or regulatory actions related to the BLRA or other litigation.

Were the SCPSC to grant the relief sought by the ORS in the Request or grant similar relief resulting from legislative action, and as further discussed above in Impairment Considerations, an additional impairment loss or other charges totaling approximately $5.0 billion (approximately $3.7 billion net of tax) may be required. Such an impairment loss or other charges would further increase the Company’s and Consolidated SCE&G’s debt to total capitalization ratio and may result in the Company’s and Consolidated SCE&G’s ratio of debt to total capitalization exceeding maximum levels prescribed in their respective credit agreements. Such an event likely would limit the Company’s and Consolidated SCE&G’s ability to borrow under their commercial paper programs and credit facilities and their ability to pay future dividends or may trigger events of default under such agreements.

Known and knowable conditions and events when considered in the aggregate as of the date of issuance of these financial statements do not suggest it is probable that the Company and Consolidated SCE&G will not be able to meet obligations as they come due over the next 12 months. However, certain possible adverse future actions, including but not limited to those contemplated in the Request by the ORS regarding the disallowance of all or part of the remaining unrecovered nuclear regulatory asset, rate reductions and refunds, and including actions that may result from other legal, regulatory and governmental proceedings and investigations, could likely have a material adverse impact on the Company’s and Consolidated SCE&G’s financial condition, liquidity, results of operations and cash flows such that management’s conclusion with respect to its ability to pay obligations when due could change.

Claims and Litigation

Following the Company’s decision to stop construction of Unit 2 and Unit 3, purported derivative and class action lawsuits have been filed in multiple state circuit courts and federal district court on behalf of customers, shareholders and SCANA (in the case of the derivative shareholder actions), against SCANA, SCE&G, or both, and in certain cases some of their officers and/or directors. The plaintiffs allege various causes of action, including but not limited to waste, breach of fiduciary duty, negligence, unfair trade practices, unjust enrichment, conspiracy, fraud, constructive fraud, misrepresentation and negligent misrepresentation, promissory estoppel, constructive trust, and money had and received, among other causes of action. Plaintiffs generally seek compensatory and consequential damages and statutory treble damages and such further relief as the court deems just and proper. In addition, certain plaintiffs seek a declaration that SCE&G may not charge its customers to reimburse itself for past and continuing costs of the Nuclear Project. Certain plaintiffs also seek to freeze or appoint a receiver for certain of SCE&G’s assets, including all money SCE&G has received under the Toshiba payment guaranty and related settlement agreement and money to be collected from customers for the Nuclear Project.

On October 15, 2018, in an email to counsel of record in the customer class action, the state court judge provided instructions to counsel for the State of South Carolina and the plaintiffs to submit proposed orders to him.  Those instructions directed the attorneys to include language in the proposed orders stating, among other things, that the BLRA violates the hearing requirement of the procedural due process provisions Article I, Section 22 of the South Carolina Constitution.The proposed orders have been submitted to the judge by those attorneys, and SCANA and SCE&G have provided the judge with comments to various portions of the proposed orders.  In a later email to counsel dated October 22, 2018, the judge indicated that he was still considering his analysis of the applicable law, and he sought further input from all parties.  The judge made clear that his emails were not binding judicial orders but merely an indication of how the judge was then considering the matters he had taken under advisement. The judge has not yet entered an official, binding order, and he has not indicated when he intends to do so. The judge’s emails do not indicate what, if any, remedy is available tothe customer class action plaintiffs should he enter an order finding that the BLRA offers insufficient due process to meet the hearing requirement of Article I, Section 22 of the South Carolina Constitution.  SCANA and SCE&G will evaluate the court’s order when it is entered and, if it is adverse to SCANA and SCE&G, will determine whether to seek reconsideration or appeal.

Purported class action lawsuits have been filed on behalf of investors in federal court against SCANA and certain of its current and former executive officers and directors. The plaintiffs allege, among other things, that defendants violated Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder and RICO. The plaintiffs in each of these suits seek compensatory and consequential damages and such further relief as the court deems proper. The plaintiffs also allege, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that unfairly deprived plaintiffs of the true value of their SCANA stock, and that Dominion Energy and Sedona aided and abetted these actions. Among other remedies, the plaintiffs seek to enjoin the merger and rescind the Merger Agreement or to have the Merger Agreement amended to provide more favorable terms for plaintiffs, monetary damages, attorneys' fees and such further relief as the court deems proper.

Lawsuits seeking class action status have also been filed on behalf of investors and shareholder derivative actions have been filed in the Court of Common Pleas in the Counties of Lexington and Richland, South Carolina, against SCANA, its CEO and directors, Dominion Energy and Sedona. Following removal of certain of these class action lawsuits and shareholder derivative actions from state courts to federal court and their subsequent remand, Dominion Energy has filed appeals of the decisions to remand to the Court of Appeals, where the appeals have been consolidated and remain pending.

On July 13, 2018, SCANA’s Board of Directors elected two new, independent directors and exercised its right under South Carolina corporate law to form an SLC comprised solely of these newly elected members to investigate the Derivative Litigation and to determine SCANA’s best interests with respect to these actions. On July 24, 2018, SCANA, acting at the direction of the SLC, filed a motion to stay all federal court proceedings in the Derivative Litigation (In Re SCANA Corporation Derivative Litigation) to allow time for the SLC to conduct an independent investigation into the facts and circumstances giving rise to the Derivative Litigation, and to determine what course of action is in the best interests of SCANA and its shareholders with respect to the Derivative Litigation (e.g., prosecution of the claims in the name of SCANA, seeking dismissal of some or all of the claims, or taking other remedial actions). On October 31, 2018, the court denied the motion to stay with leave to refile after the SCPSC decision on the merger among Dominion Energy, Sedona and SCANA.

On July 17, 2018, a case filed in the District Court styled Penningtonet al.v. SCANA, Fluor Corporation and Fluor Enterprises was certified as a class action on behalf of persons who were formerly employed at the Nuclear Project. The plaintiffs allege, among other things, that the defendants violated the WARN Act in connection with the decision to stop construction on 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 the case described in the next paragraph.

On September 7, 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against SCE&G and Santee Cooper. The plaintiffs make claims for equitable indemnity, 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 Pennington case. Plaintiffs seek a damages award, including, but not limited to, defense costs, attorney fees and expenses and any other relief the court deems proper.

A complaint has been filed by Fairfield County against SCE&G making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of the implied duty of good faith and fair dealing, and unfair trade practices related to SCE&G’s termination of the FILOT agreement. Plaintiff seeks injunctive relief to prevent SCE&G from terminating the FILOT agreement; actual and consequential damages; treble damages; punitive damages; and attorneys’ fees.

The Company has also been 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.

The DOR has initiated an audit of SCE&G's sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The DOR's position is that the exemption for sales and use tax for purchases related to the Nuclear Project should not apply because Unit 2 and Unit 3 will not be placed into service and no electricity will be manufactured for sale. On June 1, 2018, SCE&G received from the DOR a notice of proposed assessment arising from that audit of approximately $410 million, plus interest. While SCE&G has filed a protest of the proposed assessment, it is reasonably possible that a loss estimated to be as much as $410 million, plus interest and penalties, could be incurred, of which SCE&G's proportionate share as a co-owner of the Nuclear Project would be 55%.

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, they cannot predict the timing or outcome of these matters or others that may arise, including any claims that may be asserted by or against Santee Cooper in addition to claims made by Santee Cooper in connection with the Joint Petition, 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, each of the cases referred to above is in its 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 condensed 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 $13.1 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 $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 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 $84.8 million per incident, but not more than $12.6 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

On August 3, 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. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G are monitoring the final rule, but do not plan to construct new coal-fired units in the foreseeable future.     

On August 21, 2018, the EPA proposed the ACE rule which would replace the CPP. The EPA had proposed in 2017 to replace the CPP on the grounds that it exceeded the EPA’s statutory authority and in response to federal court proceedings and an Executive Order. 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 had become 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.

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 $9.6 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. 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 condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At September 30, 2018, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $23.6 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 the period that arise from the impact of the Tax Act. Such amounts have been recorded subject to refund, and are described in Note 2.

SCEG

Statement [Line Items]

Commitments and Contingencies Disclosure [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. Various difficulties were encountered which affected the ability of the Consortium to adhere to established budgets and construction schedules for the Nuclear Project and which, in light of Santee Cooper's decision to suspend construction of the Nuclear Project, led to the Company's decision on July 31, 2017 to stop the construction and seek cost recovery under the abandonment provisions of the BLRA. These difficulties and other developments occurring prior to the bankruptcy filing by WEC and WECTEC and other matters are described in Note 10 to the consolidated financial statements included in the Company's and Consolidated SCE&G's combined Form 10-K for the year ended December 31, 2017. Significant developments and continuing contingencies and uncertainties regarding the abandoned Nuclear Project subsequent to December 31, 2017 are discussed below.

EPC Contract and BLRA 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 assert against WEC and WECTEC any and all claims that are based thereon or that may be 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 $290 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 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 below. 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. The proceeds received under or arising from the monetization of the Toshiba Settlement are recorded as a regulatory liability on the accompanying condensed consolidated balance sheets, as the net value of the proceeds will be utilized to benefit SCE&G's customers in a manner to be determined by the SCPSC.

As described 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 the reduction. On January 2, 2018, the purchase agreement with Citibank was amended to limit the amount that SCE&G and Santee Cooper could be required to reimburse Citibank for valid subcontractor and vendor pre-petition liens to $60 million ($33 million for SCE&G's 55% share).

Regulatory, Political and Legal Developments

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

On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, and in reliance on the opinion from the Office of Attorney General, the ORS filed the Request seeking an order from the SCPSC directing SCE&G to immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS, which the ORS believes should have been disclosed, that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections. On October 17, 2017, the ORS filed a motion with the SCPSC to amend the Request, in which motion the ORS asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. See Claims and Litigation herein for additional discussions regarding regarding the constitutionality of the BLRA.

On December 20, 2017, the SCPSC denied a motion by SCE&G to dismiss the Request. Parties who have intervened in the Request or who filed a letter in support of it include the state's Governor, Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, Santee Cooper, the SCEUC, certain large industrial customers, and several environmental groups. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets, including the Request, regarding the merits of the Joint Petition and related issues. This schedule was established in response to legislation described below. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the outcome of this matter. See also Note 2.

In 2017, special committees of the South Carolina General Assembly, both in the House of Representatives and in the Senate, conducted public hearings regarding the Company's decision to abandon the Nuclear Project. Several legislative proposals adverse to the Company and Consolidated SCE&G resulted from the work of these committees, two of which became law in 2018 and are described below.

On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA. Act 258 requires the SCPSC to order a reduction in 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%, or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On July 2 and 3, 2018, the SCPSC issued orders implementing the temporary rate reduction required by Act 258. The resulting new rates and retroactive credits required by Act 258 were put into effect in August 2018, with the retroactive credits for the second quarter being applied in August's billing cycles. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 alters certain provisions previously applicable under the BLRA, including redefining the standard of care required by the BLRA 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.

On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented.

Proposals to Resolve Outstanding Issues

On November 16, 2017, SCE&G announced for public consideration a proposal to resolve outstanding issues relating to the Nuclear Project. Under the proposal, SCE&G electric customers were to receive a 3.5% electric rate reduction, the addition of an existing 540-MW natural gas fired power plant by SCE&G with the acquisition cost borne by SCANA shareholders, and the addition of approximately 100-MW of large scale solar energy by SCE&G. The proposal also provided for the recovery of the nuclear construction costs (net of the proceeds of the Toshiba Settlement not utilized for satisfaction of project liens) over 50 years. While SCE&G’s proposal was not formally submitted for regulatory approval at that time, discussions with key stakeholders over the ensuing weeks indicated that SCE&G's proposal would not be sufficient to resolve the outstanding issues.

On January 2, 2018, SCANA entered into the Merger Agreement with Dominion Energy, and on January 12, 2018, SCE&G and Dominion Energy filed the Joint Petition requesting SCPSC approval of the merger or a finding that either the merger is in the public interest or that there is an absence of harm arising from the merger. In this petition, the parties committed to providing an up-front, one time rate credit to SCE&G's electric customers totaling approximately $1.3 billion within 90 days of the merger's closing, providing at least a 5% reduction in customer bills (later adjusted to approximately 7% in light of the effects of the Tax Act), shortening the amortization period for costs related to the Nuclear Project to 20 years, forgoing recovery of approximately $1.7 billion in costs related to the Nuclear Project, and purchasing an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers.

On October 25, 2018, in response to the desire of various parties to the Concurrent Dockets for an alternative that would further reduce customer bills, Dominion Energy filed with the SCPSC the Alternative Customer Benefits Plan (Alternative Plan). The testimony filed by Dominion Energy in connection with the Alternative Plan indicates that customers would receive refunds totaling approximately $1.91 billion with approximately $1.0 billion being refunded evenly over 20 years and approximately $880 million credited to customers over approximately ten years instead of the up-front, one time rate credit of $1.3 billion originally proposed in the Joint Petition. In addition, such testimony indicates that approximately $2.3 billion in costs related to the Nuclear Project would not be recovered in connection with the Alternative Plan, instead of the $1.7 billion originally proposed. The parties to the Joint Petition estimate that these changes would result in customer bill reductions of approximately 14% (including the effects of the Tax Act). The Alternative Plan also contemplates the purchase of an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers.

The ORS has filed direct and rebuttal testimony and a pre-hearing brief related to the Concurrent Dockets. In these filings, the ORS has proposed (ORS Plan) that the SCPSC reduce SCE&G's electric rates during the 12 months following the effective date of its order by approximately $561 million compared to rates that would otherwise be in effect when the temporary rate reduction under Act 258 expires. This proposal includes reductions due to assumed merger synergies, the use of an ROE of 9.1% rather than 10.25% (which proposed ROE would be applied to a smaller rate base after all adjustments specified by the ORS), the ORS calculation of savings from the Tax Act (which exceeds SCE&G's calculation), the refund of amounts deferred as subject to refund that arise from the Tax Act and other adjustments. After 12 months (after amounts subject to refund have been returned to customers), the ORS proposes that SCE&G's electric rates be modified to an amount that would be approximately $528 million lower annually compared to rates that would otherwise be in effect when the temporary rate reduction under Act 258 expires.

On October 25, 2018, in testimony filed in connection with the Concurrent Dockets, a representative of Dominion Energy noted that (1) the ORS Plan, if adopted, would be devastating not only to the proposed merger but also to SCE&G's future and to the interests of SCE&G's customers and the state of South Carolina in reliable electric service at just and reasonable rates and (2) there is currently pending litigation in the South Carolina state courts in which the judge has indicated that he is considering issuing an order that would violate the "no change in law" provision of the Merger Agreement, and that if such an order were issued or the ORS Plan is adopted, the merger would be unable to close.

On October 26, 2018, Santee Cooper filed a pre-hearing brief with respect to the Joint Petition. In its filing, Santee Cooper requested that the SCPSC not approve a merger between SCANA and Dominion Energy as being in the public interest unless SCANA and Dominion Energy commit to creating a fund of approximately $351 million to mitigate the financial impact of the abandonment of the Nuclear Project on Santee Cooper's wholesale and retail customers. Santee Cooper proposes that the cost of creating such a fund should not be recoverable from SCE&G's customers.

On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets regarding the merits of the Joint Petition and related issues, and as noted above, pursuant to S. 954 the SCPSC is required to issue an order related to the Joint Petition no later than December 21, 2018. No assurance can be given as to the timing or outcome of efforts to consummate the Merger Agreement or to obtain approval of the Joint Petition.

On May 9, 2018, SCE&G completed its purchase of CEC, the existing 540-MW natural gas fired power plant referred to above, for approximately $180 million. As disclosed in Note 10 to the Company's and Consolidated SCE&G's Form 10-K for December 31, 2017, an impairment loss recorded in the fourth quarter of 2017 included $180 million related to SCE&G's commitment to not seek recovery from customers for the acquisition cost of this natural gas fired power plant, and accordingly, this amount was recorded as a reduction to unrecovered Nuclear Project costs within regulatory assets on the Company's and Consolidated SCE&G's consolidated balance sheets at December 31, 2017. As such, the Company's and Consolidated SCE&G's condensed consolidated balance sheet as of September 30, 2018 reflect the cost for CEC within Utility Plant in Service, and the $180 million impairment initially recorded as unrecovered Nuclear Project costs within regulatory assets is now reflected within Accumulated Depreciation and Amortization, which results in the carrying value of CEC being entirely written off. SCE&G’s commitment to not seek recovery from customers for the acquisition cost of CEC was one element of certain broader rate mitigation proposals contained within the Joint Petition and the Alternative Plan. Assuming that the SCPSC approves either of the mitigating proposals as outlined in the Joint Petition or approves the Alternative Plan, SCE&G will not seek recovery of CEC acquisition costs. 

Impairment Considerations

At September 30, 2018, SCE&G estimated that revised rates collections previously approved under the BLRA totaled approximately $445 million annually. SCE&G estimates that such revised rates collections for 2018 would be reduced by approximately $279 million if Act 258 remains in effect and is implemented through December 21, 2018, which is the expected pendency of the SCPSC proceeding with respect to the Joint Petition. New rates are expected to be ordered by the SCPSC in connection with its order on the Joint Petition, which order is to be issued no later than December 21, 2018. On a cumulative basis, at September 30, 2018, SCE&G estimated that revised rates collections previously approved under the BLRA totaled approximately $2.1 billion, which amount reflects the impacts of Act 258.

For each of the quarters ended June 30, 2018, September 30, 2018 and December 31, 2018, SCANA's Board of Directors declared a dividend of $0.1237 per share, which represents an approximately 80% reduction from the $0.6125 per share paid on SCANA’s common stock for the first quarter of 2018. This reduction corresponds to the portion of the dividend attributable to SCE&G's electric operations and serves to partially mitigate the liquidity impacts arising from the reduced revenues and cash flows resulting from the implementation of Act 258.

Under the current regulatory construct in South Carolina, pursuant to the BLRA or through other means, the ability of SCE&G to recover costs incurred in connection with Unit 2 and Unit 3, and a reasonable return on them, will be subject to review and approval by the SCPSC. In light of the contentious nature of activity involving the General Assembly and other officials and the Request being considered by the SCPSC that could result in the suspension of all rates currently being collected under the BLRA, as well as the return of such amounts previously collected, there is significant uncertainty as to SCE&G’s ultimate ability to recover its costs of Unit 2 and Unit 3 and a return on them from its customers. See also Claims and Litigation herein for additional discussion regarding the constitutionality of the BLRA. SCE&G continues to contest the specific challenges described above. However, based on the consideration of those challenges, and particularly in light of SCE&G's proposed solution announced on November 16, 2017 and details in the Joint Petition filed by SCE&G and Dominion Energy with the SCPSC on January 12, 2018, the Company and Consolidated SCE&G determined that a disallowance of recovery of part of the cost of the abandoned Nuclear Project is both probable and reasonably estimable under applicable accounting guidance. In addition, the Company and Consolidated SCE&G determined that full recovery of certain other related costs deferred within regulatory assets is less than probable. As a result, in 2017 the Company and Consolidated SCE&G recognized a pre-tax impairment loss totaling $1.118 billion ($690 million net of tax). Also, in the first quarter of 2018, the Company and Consolidated SCE&G recognized an additional pre-tax impairment loss of approximately $3.6 million ($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.

It is reasonably possible that a change in estimated impairment loss could occur in the near term and could be material; however, all such changes cannot be reasonably estimated. The impairment loss recorded in 2017 reflects impacts similar to those that would have resulted had the proposed solution announced on November 16, 2017 been implemented. If the merger benefits and cost recovery plan outlined in the Joint Petition are implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $1.7 billion (approximately $1.3 billion net of tax) would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $813 million recorded within regulatory assets, the write-off of unrecovered Nuclear Project costs of approximately $86 million recorded within Utility Plant, and the recording of additional liabilities for customer refunds totaling approximately $1.875 billion, net of approximately $1.065 billion, which amount represents the monetization of guaranty settlement recorded within regulatory liabilities less amounts that may be required to satisfy contractor liens.

If the Alternative Plan were implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $2.3 billion (approximately $1.7 billion net of tax) would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $1.368 billion recorded within regulatory assets, the write-off of unrecovered Nuclear Project costs of approximately $86 million recorded within Utility Plant, and the recording of additional liabilities for customer refunds of approximately $880 million. In addition, the Alternative Plan provides for the refunding of the existing regulatory liability associated with the monetization of guaranty settlement over 20 years less amounts that may be required to satisfy contractor liens.

If (i) the SCPSC does not approve the Joint Petition or the Alternative Plan and instead approves the Request by the ORS; (ii) the BLRA is found to be unconstitutional; or (iii) the General Assembly further amends or revokes the BLRA or approves other legislation with a similar effect, the Company and Consolidated SCE&G may be required to record an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $5.0 billion (approximately $3.7 billion net of tax). This additional impairment loss would result from the write-off of approximately $3.960 billion in regulatory assets (comprised of remaining unrecovered Nuclear Project costs of $4.140 billion offset by $180 million in previously impaired costs related to CEC, which would result from the proposals put forward in the Joint Petition or the Alternative Plan not being approved by the SCPSC) and the refund of revised rates collections under the BLRA described above of approximately $2.1 billion (comprised of the revised rates collections on a cumulative basis as of September 30, 2018 and reflective of the impacts of Act 258), net of approximately $1.065 billion, which amount represents the monetization of guaranty settlement recorded within regulatory liabilities less amounts that may be required to satisfy contractor liens. The Company and Consolidated SCE&G do not currently anticipate that any amounts collected prior to April 1, 2018, will be subject to refund (other than amounts arising from the effects of the Tax Act); however, no assurance can be given as to the outcome of this matter. See Claims and Litigation herein for additional discussion regarding the constitutionality of the BLRA.

At September 30, 2018, the Company and Consolidated SCE&G included considerations of the impact of Act 258 in the evaluation as to their ability to recover the remaining Nuclear Project costs and a reasonable return on those costs. Because Act 258 explicitly provides for an experimental rate that is temporary and does not disallow any of the costs currently deferred as a regulatory asset, and because the experimental rate is to be replaced by rates that the SCPSC is to determine and order no later than December 21, 2018, the Company and Consolidated SCE&G have concluded that additional impairment charges related to unrecovered Nuclear Project costs are not probable, and the recording of such charges would not be appropriate, at this time. However, if a disallowance were ordered or the rates under Act 258 were made other than temporary by the SCPSC in the Joint Petition proceeding, the Company and Consolidated SCE&G would reevaluate this conclusion. Were the rates under Act 258 made other than temporary following the SCPSC's final decision on the Joint Petition, and without consideration of any other factors that may be embodied in such an order, an additional pre-tax impairment charge totaling approximately $1.7 billion may be required.

In addition to the matters above, in the Joint Petition, the Company and Consolidated SCE&G proposed to remove from BLRA capital costs their investment in transmission assets that have been or will be placed in service and have not been abandoned. As of September 30, 2018, such investment in these assets total approximately $376 million (approximately $365 million within utility plant, net and approximately $11 million within regulatory assets, which amount represents certain deferred operating costs). The Company and Consolidated SCE&G believe that this investment represents assets that are or will be used to provide electric service to customers and that a recovery of and a reasonable return on the investment should be provided in future rates. During the hearing on the Concurrent Dockets, the SCPSC will consider a request by the ORS to allow the Company and Consolidated SCE&G to defer certain operating costs related to the investment and that a decision on the recovery of this investment, including operating costs deferrals, be addressed in a future rate proceeding. If the SCPSC were to disallow recovery of or a reasonable return on all or a portion of this investment, an impairment charge related to these assets totaling as much as approximately $376 million may be required.

Liquidity Considerations

              As a result of the legislative and regulatory reactions to the decision to stop construction of Unit 2 and Unit 3, downgrades by credit ratings agencies occurred.  The Company and Consolidated SCE&G have significant obligations that must be paid within the next 12 months, including long-term debt maturities and capital lease payments of $18 million for the Company (including $14 million for Consolidated SCE&G), short-term borrowings of $314 million for the Company (including $173 million for Consolidated SCE&G), interest payments of approximately $335 million for the Company (including $255 million for Consolidated SCE&G), future minimum payments for operating leases of $9 million for the Company (including $3 million for Consolidated SCE&G), and revenues collected subject to refund arising from the effects of the Tax Act of approximately $61 million for the Company and Consolidated SCE&G. Working capital requirements, such as those for fuel supply and similar obligations, also arise due to the lag between when such amounts are paid and when related collection of such costs through customer rates occurs. In addition, as described above under Impairment Considerations, SCE&G has been ordered to reduce revised rates previously approved under the BLRA by approximately $279 million in 2018. This reduction assumes that Act 258 remains in effect through December 21, 2018, which is the expected pendency of the SCPSC proceeding with respect to the Concurrent Dockets.

Also, any adverse final judgment by a court in any matter of litigation, or any levy for amounts assessed by a regulatory agency, including but not limited to matters described in Claims and Litigation below, could require the Company and/or Consolidated SCE&G to escrow funds or to post one or more bonds equal to the monetary amount of the judgment or assessment while the decision is being appealed or challenged.

              Management believes as of the date of issuance of these financial statements that it has access to available sources of cash to pay obligations when due over the next 12 months. These sources include committed, long-term lines of credit that expire in December 2020 totaling $1.8 billion for the Company (including $1.2 billion for Consolidated SCE&G). In addition, as of the date of issuance of these financial statements, SCE&G continues to collect the BLRA-related customer rates that remain after reductions ordered as a result of Act 258, as well as amounts provided for in other orders related to non-BLRA electric and gas rates. In 2018, however, certain of SCANA's credit ratings have fallen below investment grade, which has constrained its ability to issue commercial paper. The ability of Fuel Company and PSNC Energy to issue commercial paper has also been constrained.

Regulatory and legislative proceedings described above, and/or proceedings described under Claims and Litigation below, which are outside of the Company’s and Consolidated SCE&G’s control, have resulted in the temporary suspension of a substantial portion of the approximately $445 million annually of rates that were being collected under the BLRA, and may result in the permanent suspension of all or a portion of such amounts, the return of such amounts collected through September 30, 2018, of $2.1 billion, or the requirement that SCE&G's share of payments received from the Toshiba Settlement ($1.098 billion) be placed in escrow or be refunded to customers in the near term. Neither the Company nor Consolidated SCE&G can predict if or when these matters may be resolved or what additional actions, if any, may be proposed or taken, including other legislative or regulatory actions related to the BLRA or other litigation.

Were the SCPSC to grant the relief sought by the ORS in the Request or grant similar relief resulting from legislative action, and as further discussed above in Impairment Considerations, an additional impairment loss or other charges totaling approximately $5.0 billion (approximately $3.7 billion net of tax) may be required. Such an impairment loss or other charges would further increase the Company’s and Consolidated SCE&G’s debt to total capitalization ratio and may result in the Company’s and Consolidated SCE&G’s ratio of debt to total capitalization exceeding maximum levels prescribed in their respective credit agreements. Such an event likely would limit the Company’s and Consolidated SCE&G’s ability to borrow under their commercial paper programs and credit facilities and their ability to pay future dividends or may trigger events of default under such agreements.

Known and knowable conditions and events when considered in the aggregate as of the date of issuance of these financial statements do not suggest it is probable that the Company and Consolidated SCE&G will not be able to meet obligations as they come due over the next 12 months. However, certain possible adverse future actions, including but not limited to those contemplated in the Request by the ORS regarding the disallowance of all or part of the remaining unrecovered nuclear regulatory asset, rate reductions and refunds, and including actions that may result from other legal, regulatory and governmental proceedings and investigations, could likely have a material adverse impact on the Company’s and Consolidated SCE&G’s financial condition, liquidity, results of operations and cash flows such that management’s conclusion with respect to its ability to pay obligations when due could change.

Claims and Litigation

Following the Company’s decision to stop construction of Unit 2 and Unit 3, purported derivative and class action lawsuits have been filed in multiple state circuit courts and federal district court on behalf of customers, shareholders and SCANA (in the case of the derivative shareholder actions), against SCANA, SCE&G, or both, and in certain cases some of their officers and/or directors. The plaintiffs allege various causes of action, including but not limited to waste, breach of fiduciary duty, negligence, unfair trade practices, unjust enrichment, conspiracy, fraud, constructive fraud, misrepresentation and negligent misrepresentation, promissory estoppel, constructive trust, and money had and received, among other causes of action. Plaintiffs generally seek compensatory and consequential damages and statutory treble damages and such further relief as the court deems just and proper. In addition, certain plaintiffs seek a declaration that SCE&G may not charge its customers to reimburse itself for past and continuing costs of the Nuclear Project. Certain plaintiffs also seek to freeze or appoint a receiver for certain of SCE&G’s assets, including all money SCE&G has received under the Toshiba payment guaranty and related settlement agreement and money to be collected from customers for the Nuclear Project.

On October 15, 2018, in an email to counsel of record in the customer class action, the state court judge provided instructions to counsel for the State of South Carolina and the plaintiffs to submit proposed orders to him.  Those instructions directed the attorneys to include language in the proposed orders stating, among other things, that the BLRA violates the hearing requirement of the procedural due process provisions Article I, Section 22 of the South Carolina Constitution.The proposed orders have been submitted to the judge by those attorneys, and SCANA and SCE&G have provided the judge with comments to various portions of the proposed orders.  In a later email to counsel dated October 22, 2018, the judge indicated that he was still considering his analysis of the applicable law, and he sought further input from all parties.  The judge made clear that his emails were not binding judicial orders but merely an indication of how the judge was then considering the matters he had taken under advisement. The judge has not yet entered an official, binding order, and he has not indicated when he intends to do so. The judge’s emails do not indicate what, if any, remedy is available tothe customer class action plaintiffs should he enter an order finding that the BLRA offers insufficient due process to meet the hearing requirement of Article I, Section 22 of the South Carolina Constitution.  SCANA and SCE&G will evaluate the court’s order when it is entered and, if it is adverse to SCANA and SCE&G, will determine whether to seek reconsideration or appeal.

Purported class action lawsuits have been filed on behalf of investors in federal court against SCANA and certain of its current and former executive officers and directors. The plaintiffs allege, among other things, that defendants violated Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder and RICO. The plaintiffs in each of these suits seek compensatory and consequential damages and such further relief as the court deems proper. The plaintiffs also allege, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that unfairly deprived plaintiffs of the true value of their SCANA stock, and that Dominion Energy and Sedona aided and abetted these actions. Among other remedies, the plaintiffs seek to enjoin the merger and rescind the Merger Agreement or to have the Merger Agreement amended to provide more favorable terms for plaintiffs, monetary damages, attorneys' fees and such further relief as the court deems proper.

Lawsuits seeking class action status have also been filed on behalf of investors and shareholder derivative actions have been filed in the Court of Common Pleas in the Counties of Lexington and Richland, South Carolina, against SCANA, its CEO and directors, Dominion Energy and Sedona. Following removal of certain of these class action lawsuits and shareholder derivative actions from state courts to federal court and their subsequent remand, Dominion Energy has filed appeals of the decisions to remand to the Court of Appeals, where the appeals have been consolidated and remain pending.

On July 13, 2018, SCANA’s Board of Directors elected two new, independent directors and exercised its right under South Carolina corporate law to form an SLC comprised solely of these newly elected members to investigate the Derivative Litigation and to determine SCANA’s best interests with respect to these actions. On July 24, 2018, SCANA, acting at the direction of the SLC, filed a motion to stay all federal court proceedings in the Derivative Litigation (In Re SCANA Corporation Derivative Litigation) to allow time for the SLC to conduct an independent investigation into the facts and circumstances giving rise to the Derivative Litigation, and to determine what course of action is in the best interests of SCANA and its shareholders with respect to the Derivative Litigation (e.g., prosecution of the claims in the name of SCANA, seeking dismissal of some or all of the claims, or taking other remedial actions). On October 31, 2018, the court denied the motion to stay with leave to refile after the SCPSC decision on the merger among Dominion Energy, Sedona and SCANA.

On July 17, 2018, a case filed in the District Court styled Penningtonet al.v. SCANA, Fluor Corporation and Fluor Enterprises was certified as a class action on behalf of persons who were formerly employed at the Nuclear Project. The plaintiffs allege, among other things, that the defendants violated the WARN Act in connection with the decision to stop construction on 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 the case described in the next paragraph.

On September 7, 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against SCE&G and Santee Cooper. The plaintiffs make claims for equitable indemnity, 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 Pennington case. Plaintiffs seek a damages award, including, but not limited to, defense costs, attorney fees and expenses and any other relief the court deems proper.

A complaint has been filed by Fairfield County against SCE&G making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of the implied duty of good faith and fair dealing, and unfair trade practices related to SCE&G’s termination of the FILOT agreement. Plaintiff seeks injunctive relief to prevent SCE&G from terminating the FILOT agreement; actual and consequential damages; treble damages; punitive damages; and attorneys’ fees.

The Company has also been 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.

The DOR has initiated an audit of SCE&G's sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The DOR's position is that the exemption for sales and use tax for purchases related to the Nuclear Project should not apply because Unit 2 and Unit 3 will not be placed into service and no electricity will be manufactured for sale. On June 1, 2018, SCE&G received from the DOR a notice of proposed assessment arising from that audit of approximately $410 million, plus interest. While SCE&G has filed a protest of the proposed assessment, it is reasonably possible that a loss estimated to be as much as $410 million, plus interest and penalties, could be incurred, of which SCE&G's proportionate share as a co-owner of the Nuclear Project would be 55%.

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, they cannot predict the timing or outcome of these matters or others that may arise, including any claims that may be asserted by or against Santee Cooper in addition to claims made by Santee Cooper in connection with the Joint Petition, 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, each of the cases referred to above is in its 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 condensed 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 $13.1 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 $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 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 $84.8 million per incident, but not more than $12.6 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

On August 3, 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. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G are monitoring the final rule, but do not plan to construct new coal-fired units in the foreseeable future.     

On August 21, 2018, the EPA proposed the ACE rule which would replace the CPP. The EPA had proposed in 2017 to replace the CPP on the grounds that it exceeded the EPA’s statutory authority and in response to federal court proceedings and an Executive Order. 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 had become 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.

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 $9.6 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. 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 condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At September 30, 2018, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $23.6 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 the period that arise from the impact of the Tax Act. Such amounts have been recorded subject to refund, and are described in Note 2.

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SEGMENT OF BUSINESS INFORMATION

9 Months Ended

Sep. 30, 2018

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

SEGMENT OF BUSINESS INFORMATION

Regulated operations measure profitability using operating income; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. The Gas Marketing segment measures profitability using net income.

The Company's Gas Distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented.

The Company
Millions of dollars	External Revenue		Intersegment Revenue			Operating Income (Loss)			Net Income
Three Months Ended September 30, 2018
Electric Operations	$	669	—			$	217		n/a
Gas Distribution	122		—			(10		)	n/a
Gas Marketing	135		$	35		n/a			$	1
All Other	—		124			—			(30		)
Adjustments/Eliminations	—		(159		)	(24		)	96
Consolidated Total	$	926	—			$	183		$	67
Nine Months Ended September 30, 2018
Electric Operations	$	1,767	$	3		$	396		n/a
Gas Distribution	631		1			107			n/a
Gas Marketing	550		95			n/a			$	21
All Other	—		347			—			(79		)
Adjustments/Eliminations	—		(446		)	(28		)	302
Consolidated Total	$	2,948	—			$	475		$	244

Three Months Ended September 30, 2017
Electric Operations	$	786	$	1		$	127		n/a
Gas Distribution	123		—			(7		)	n/a
Gas Marketing	167		35			n/a			$	1
All Other	—		90			—			(7		)
Adjustments/Eliminations	—		(126		)	2			40
Consolidated Total	$	1,076	—			$	122		$	34
Nine Months Ended September 30, 2017
Electric Operations	$	2,042	$	4		$	555		n/a
Gas Distribution	584		1			110			n/a
Gas Marketing	623		93			n/a			$	17
All Other	—		286			—			(14		)
Adjustments/Eliminations	—		(384		)	28			323
Consolidated Total	$	3,249	—			$	693		$	326

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income (Loss)			Comprehensive Income Available to Common Shareholder
Three Months Ended September 30, 2018
Electric Operations	$	670	$	216		n/a
Gas Distribution	69		(4		)	n/a
Adjustments/Eliminations	—		—			$	98
Consolidated Total	$	739	$	212		$	98
Nine Months Ended September 30, 2018
Electric Operations	$	1,770	$	396		n/a
Gas Distribution	304		44			n/a
Adjustments/Eliminations	—		—			$	248
Consolidated Total	$	2,074	$	440		$	248

Three Months Ended September 30, 2017
Electric Operations	$	787	$	126		n/a
Gas Distribution	69		(2		)	n/a
Adjustments/Eliminations	—		—			$	39
Consolidated Total	$	856	$	124		$	39
Nine Months Ended September 30, 2017
Electric Operations	$	2,046	$	555		n/a
Gas Distribution	285		42			n/a
Adjustments/Eliminations	—		—			$	270
Consolidated Total	$	2,331	$	597		$	270

Segment Assets	The Company				Consolidated SCE&G
	September 30,		December 31,		September 30,		December 31,
Millions of dollars	2018		2017		2018		2017
Electric Operations	$	12,046	$	11,979	$	12,046	$	11,979
Gas Distribution	3,384		3,259		909		869
Gas Marketing	204		230		n/a		n/a
All Other	1,071		1,042		n/a		n/a
Adjustments/Eliminations	2,111		2,229		3,174		3,098
Consolidated Total	$	18,816	$	18,739	$	16,129	$	15,946

SCEG

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

SEGMENT OF BUSINESS INFORMATION

Regulated operations measure profitability using operating income; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. The Gas Marketing segment measures profitability using net income.

The Company's Gas Distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented.

The Company
Millions of dollars	External Revenue		Intersegment Revenue			Operating Income (Loss)			Net Income
Three Months Ended September 30, 2018
Electric Operations	$	669	—			$	217		n/a
Gas Distribution	122		—			(10		)	n/a
Gas Marketing	135		$	35		n/a			$	1
All Other	—		124			—			(30		)
Adjustments/Eliminations	—		(159		)	(24		)	96
Consolidated Total	$	926	—			$	183		$	67
Nine Months Ended September 30, 2018
Electric Operations	$	1,767	$	3		$	396		n/a
Gas Distribution	631		1			107			n/a
Gas Marketing	550		95			n/a			$	21
All Other	—		347			—			(79		)
Adjustments/Eliminations	—		(446		)	(28		)	302
Consolidated Total	$	2,948	—			$	475		$	244

Three Months Ended September 30, 2017
Electric Operations	$	786	$	1		$	127		n/a
Gas Distribution	123		—			(7		)	n/a
Gas Marketing	167		35			n/a			$	1
All Other	—		90			—			(7		)
Adjustments/Eliminations	—		(126		)	2			40
Consolidated Total	$	1,076	—			$	122		$	34
Nine Months Ended September 30, 2017
Electric Operations	$	2,042	$	4		$	555		n/a
Gas Distribution	584		1			110			n/a
Gas Marketing	623		93			n/a			$	17
All Other	—		286			—			(14		)
Adjustments/Eliminations	—		(384		)	28			323
Consolidated Total	$	3,249	—			$	693		$	326

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income (Loss)			Comprehensive Income Available to Common Shareholder
Three Months Ended September 30, 2018
Electric Operations	$	670	$	216		n/a
Gas Distribution	69		(4		)	n/a
Adjustments/Eliminations	—		—			$	98
Consolidated Total	$	739	$	212		$	98
Nine Months Ended September 30, 2018
Electric Operations	$	1,770	$	396		n/a
Gas Distribution	304		44			n/a
Adjustments/Eliminations	—		—			$	248
Consolidated Total	$	2,074	$	440		$	248

Three Months Ended September 30, 2017
Electric Operations	$	787	$	126		n/a
Gas Distribution	69		(2		)	n/a
Adjustments/Eliminations	—		—			$	39
Consolidated Total	$	856	$	124		$	39
Nine Months Ended September 30, 2017
Electric Operations	$	2,046	$	555		n/a
Gas Distribution	285		42			n/a
Adjustments/Eliminations	—		—			$	270
Consolidated Total	$	2,331	$	597		$	270

Segment Assets	The Company				Consolidated SCE&G
	September 30,		December 31,		September 30,		December 31,
Millions of dollars	2018		2017		2018		2017
Electric Operations	$	12,046	$	11,979	$	12,046	$	11,979
Gas Distribution	3,384		3,259		909		869
Gas Marketing	204		230		n/a		n/a
All Other	1,071		1,042		n/a		n/a
Adjustments/Eliminations	2,111		2,229		3,174		3,098
Consolidated Total	$	18,816	$	18,739	$	16,129	$	15,946

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AFFILIATED TRANSACTIONS

9 Months Ended

Sep. 30, 2018

Related Party Transaction [Line Items]

Related Party Transactions Disclosure [Text Block]

AFFILIATED TRANSACTIONS

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 income (for the Company) and of comprehensive income (for Consolidated SCE&G).

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from Canadys Refined Coal, LLC	$	45.2	$	47.5	$	122.5	$	144.9
Sales to Canadys Refined Coal, LLC	44.9		47.2		121.8		144.0

Millions of Dollars	September 30, 2018		December 31, 2017
Receivable from Canadys Refined Coal, LLC	$	8.5	$	4.9
Payable to Canadys Refined Coal, LLC	8.5		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.

Consolidated SCE&G has provided $71.0 million in funding to a rabbi trust consolidated with SCANA in connection with the potential change in control arising from the Merger Agreement. This funding is recorded as long-term Other affiliate assets on the condensed consolidated balance sheet of Consolidated SCE&G.

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from SCANA Energy	$	35.0	$	35.3	$	95.0	$	93.4
Direct and Allocated Costs from SCANA Services	72.9		78.1		208.3		233.6

Millions of Dollars	September 30, 2018		December 31, 2017
Payable to SCANA Energy	$	10.6	$	10.0
Payable to SCANA Services	42.8		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.

SCEG

Related Party Transaction [Line Items]

Related Party Transactions Disclosure [Text Block]

AFFILIATED TRANSACTIONS

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 income (for the Company) and of comprehensive income (for Consolidated SCE&G).

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from Canadys Refined Coal, LLC	$	45.2	$	47.5	$	122.5	$	144.9
Sales to Canadys Refined Coal, LLC	44.9		47.2		121.8		144.0

Millions of Dollars	September 30, 2018		December 31, 2017
Receivable from Canadys Refined Coal, LLC	$	8.5	$	4.9
Payable to Canadys Refined Coal, LLC	8.5		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.

Consolidated SCE&G has provided $71.0 million in funding to a rabbi trust consolidated with SCANA in connection with the potential change in control arising from the Merger Agreement. This funding is recorded as long-term Other affiliate assets on the condensed consolidated balance sheet of Consolidated SCE&G.

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from SCANA Energy	$	35.0	$	35.3	$	95.0	$	93.4
Direct and Allocated Costs from SCANA Services	72.9		78.1		208.3		233.6

Millions of Dollars	September 30, 2018		December 31, 2017
Payable to SCANA Energy	$	10.6	$	10.0
Payable to SCANA Services	42.8		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.

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OTHER INCOME (EXPENSE), NET Notes

9 Months Ended

Sep. 30, 2018

Condensed Income Statements, Captions [Line Items]

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
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
Millions of dollars	2018			2017			2018			2017			2018			2017			2018			2017
Revenues from contracts with customers	$	4		—			$	14		—			$	1		—			$	4		—
Other income	8			$	28		144			$	61		5			$	21		135			$	36
Other expense	(14		)	(9		)	(34		)	(33		)	(10		)	(7		)	(22		)	(23		)
Allowance for equity funds used during construction	5			—			12			17			3			(3		)	7			13
Other income (expense), net	$	3		$	19		$	136		$	45		$	(1	)	$	11		$	124		$	26

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. Other income in 2018 includes gains from the settlement of interest rate derivatives of approximately $115 million (see Note 7). Non-service cost components of pension and other postretirement benefits are included in Other expense.

SCEG

Condensed Income Statements, Captions [Line Items]

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
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
Millions of dollars	2018			2017			2018			2017			2018			2017			2018			2017
Revenues from contracts with customers	$	4		—			$	14		—			$	1		—			$	4		—
Other income	8			$	28		144			$	61		5			$	21		135			$	36
Other expense	(14		)	(9		)	(34		)	(33		)	(10		)	(7		)	(22		)	(23		)
Allowance for equity funds used during construction	5			—			12			17			3			(3		)	7			13
Other income (expense), net	$	3		$	19		$	136		$	45		$	(1	)	$	11		$	124		$	26

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. Other income in 2018 includes gains from the settlement of interest rate derivatives of approximately $115 million (see Note 7). Non-service cost components of pension and other postretirement benefits are included in Other expense.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2018

Significant Accounting Policies

Basis Of Consolidation And Variable Interest Entities [Policy Text Block]

Basis of Consolidation and Variable Interest Entities

     The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed 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 condensed 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 $495 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.

Income Statement policy [Policy Text Block]

Income Statement 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 11) are presented within Operating Income, and other activities are presented within Other Income (Expense).

Asset Management and Supply Service Agreements

Asset Management and Supply Service Agreement

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, 45% and 39% of PSNC Energy’s natural gas inventory at September 30, 2018 and December 31, 2017, respectively, with a carrying value of $14.3 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 expires on March 31, 2019.

Earnings Per Share [Text Block]

Earnings Per Share

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

Reclassification, Policy [Policy Text Block]

Reclassifications

In the statement of operations, amounts reported for 2017 under the captions “Other income,” “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net.” Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated.

SCEG

Significant Accounting Policies

Basis Of Consolidation And Variable Interest Entities [Policy Text Block]

Basis of Consolidation and Variable Interest Entities

     The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed 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 condensed 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 $495 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.

Income Statement policy [Policy Text Block]

Income Statement 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 11) are presented within Operating Income, and other activities are presented within Other Income (Expense).

Reclassification, Policy [Policy Text Block]

Reclassifications

In the statement of operations, amounts reported for 2017 under the captions “Other income,” “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net.” Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES RECLASSIFICATION (Tables)

9 Months Ended

Sep. 30, 2018

Condensed Statement of Income Captions [Line Items]

Statement of Income [Table Text Block]

Increase (Decrease) Millions of dollars	The Company						Consolidated SCE&G
September 30, 2017	Three Months Ended			Nine Months Ended			Three Months Ended			Nine Months Ended
Other operation and maintenance	$	(2	)	$	(8	)	$	(1	)	$	(6	)
Total Operating Expenses	(2		)	(8		)	(1		)	(6		)
Operating Income	2			8			1			6
Other Income (Expense), Net	(2		)	(8		)	(1		)	(6		)

SCEG

Condensed Statement of Income Captions [Line Items]

Statement of Income [Table Text Block]

Increase (Decrease) Millions of dollars	The Company						Consolidated SCE&G
September 30, 2017	Three Months Ended			Nine Months Ended			Three Months Ended			Nine Months Ended
Other operation and maintenance	$	(2	)	$	(8	)	$	(1	)	$	(6	)
Total Operating Expenses	(2		)	(8		)	(1		)	(6		)
Operating Income	2			8			1			6
Other Income (Expense), Net	(2		)	(8		)	(1		)	(6		)

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RATE AND OTHER REGULATORY MATTERS (Tables)

9 Months Ended

Sep. 30, 2018

Public Utilities, General Disclosures [Line Items]

Pipeline integrity management revenue requirement [Table Text Block]

Rates Effective	Incremental Increase
March 1, 2018	$14.7 million
September 1, 2018	$1.1 million

Schedule of Regulatory Assets [Table Text Block]

	The Company				Consolidated SCE&G
Millions of dollars	September 30, 2018		December 31, 2017		September 30, 2018		December 31, 2017
Regulatory Assets:
Unrecovered Nuclear Project costs	$	4,140	$	3,976	$	4,140	$	3,976
AROs and related funding	448		434		423		410
Deferred employee benefit plan costs	282		305		254		273
Deferred losses on interest rate derivatives	446		456		446		456
Other unrecovered plant	96		105		96		105
DSM Programs	57		59		57		59
Pipeline integrity management costs	67		51		9		8
Environmental remediation costs	28		30		24		25
Deferred storm damage costs	29		24		29		24
Deferred transmission operating costs	11		—		11		—
Other	135		140		134		140
Total Regulatory Assets	$	5,739	$	5,580	$	5,623	$	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	1,075		1,076		916		914
Asset removal costs	775		757		539		527
Deferred gains on interest rate derivatives	77		131		77		131
Other	15		—		5		—
Total Regulatory Liabilities	$	3,040	$	3,059	$	2,635	$	2,667

SCEG

Public Utilities, General Disclosures [Line Items]

Schedule of Regulatory Assets [Table Text Block]

	The Company				Consolidated SCE&G
Millions of dollars	September 30, 2018		December 31, 2017		September 30, 2018		December 31, 2017
Regulatory Assets:
Unrecovered Nuclear Project costs	$	4,140	$	3,976	$	4,140	$	3,976
AROs and related funding	448		434		423		410
Deferred employee benefit plan costs	282		305		254		273
Deferred losses on interest rate derivatives	446		456		446		456
Other unrecovered plant	96		105		96		105
DSM Programs	57		59		57		59
Pipeline integrity management costs	67		51		9		8
Environmental remediation costs	28		30		24		25
Deferred storm damage costs	29		24		29		24
Deferred transmission operating costs	11		—		11		—
Other	135		140		134		140
Total Regulatory Assets	$	5,739	$	5,580	$	5,623	$	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	1,075		1,076		916		914
Asset removal costs	775		757		539		527
Deferred gains on interest rate derivatives	77		131		77		131
Other	15		—		5		—
Total Regulatory Liabilities	$	3,040	$	3,059	$	2,635	$	2,667

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REVENUE RECOGNITION Revenue Recognition (Tables)

9 Months Ended

Sep. 30, 2018

Disaggregation of Revenue [Table Text Block]

The Company	Consolidated SCE&G				PSNC Energy				Gas-nonregulated
Millions of dollars	Electric		Gas-regulated		Gas-regulated		Total  Gas-regulated
Three months ended September 30, 2018
Customer class:
Residential	$	310	$	25	$	27	$	52	$	22
Commercial	231		19		19		38		14
Industrial	95		19		—		19		93
Other	31		6		7		13		6
Revenues from contracts with customers	667		69		53		122		135
Other operating revenues	3		—		—		—		—
Total Operating Revenues	$	670	$	69	$	53	$	122	$	135
Nine months ended September 30, 2018
Customer class:
Residential	$	805	$	145	$	210	$	355	$	158
Commercial	571		80		85		165		64
Industrial	286		64		10		74		304
Other	99		13		22		35		24
Revenues from contracts with customers	1,761		302		327		629		550
Other operating revenues	9		1		1		2		—
Total Operating Revenues	$	1,770	$	303	$	328	$	631	$	550

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	(1.1		)
Impairment	—
September 30, 2018	$	15.2

SCEG

Disaggregation of Revenue [Table Text Block]

The Company	Consolidated SCE&G				PSNC Energy				Gas-nonregulated
Millions of dollars	Electric		Gas-regulated		Gas-regulated		Total  Gas-regulated
Three months ended September 30, 2018
Customer class:
Residential	$	310	$	25	$	27	$	52	$	22
Commercial	231		19		19		38		14
Industrial	95		19		—		19		93
Other	31		6		7		13		6
Revenues from contracts with customers	667		69		53		122		135
Other operating revenues	3		—		—		—		—
Total Operating Revenues	$	670	$	69	$	53	$	122	$	135
Nine months ended September 30, 2018
Customer class:
Residential	$	805	$	145	$	210	$	355	$	158
Commercial	571		80		85		165		64
Industrial	286		64		10		74		304
Other	99		13		22		35		24
Revenues from contracts with customers	1,761		302		327		629		550
Other operating revenues	9		1		1		2		—
Total Operating Revenues	$	1,770	$	303	$	328	$	631	$	550

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	(1.1		)
Impairment	—
September 30, 2018	$	15.2

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LONG-TERM AND SHORT-TERM DEBT (Tables)

9 Months Ended

Sep. 30, 2018

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

September 30, 2018 (Millions of dollars)	Total		SCANA			Consolidated SCE&G			PSNC  Energy
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
LOC advances	40.0		40.0			—			—
Weighted average interest rate			3.78		%	—			—
Outstanding commercial paper (270 or fewer days)	314.2		3.7			173.2			137.3
Weighted average interest rate			3.20		%	3.21		%	3.13		%
Letters of credit supported by LOC	37.6		37.3			0.3			—
Available	$	1,608.2	$	319.0		$	1,226.5		$	62.7

December 31, 2017 (Millions of dollars)	Total		SCANA		Consolidated SCE&G			PSNC  Energy
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

SCEG

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

September 30, 2018 (Millions of dollars)	Total		SCANA			Consolidated SCE&G			PSNC  Energy
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
LOC advances	40.0		40.0			—			—
Weighted average interest rate			3.78		%	—			—
Outstanding commercial paper (270 or fewer days)	314.2		3.7			173.2			137.3
Weighted average interest rate			3.20		%	3.21		%	3.13		%
Letters of credit supported by LOC	37.6		37.3			0.3			—
Available	$	1,608.2	$	319.0		$	1,226.5		$	62.7

December 31, 2017 (Millions of dollars)	Total		SCANA		Consolidated SCE&G			PSNC  Energy
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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DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

9 Months Ended

Sep. 30, 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 Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Gas Marketing	Total
As of September 30, 2018
Commodity contracts	7,050,000	16,856,000	23,906,000
Energy management contracts (a)	—	40,949,232	40,949,232
Total (a)	7,050,000	57,805,232	64,855,232
As of December 31, 2017
Commodity contracts	6,430,000	13,433,000	19,863,000
Energy management contracts (a)	—	41,856,890	41,856,890
Total (a)	6,430,000	55,289,890	61,719,890

(a)  Includes amounts related to basis swap contracts totaling 9,396,000 MMBTU in 2018 and 2,582,000 MMBTU 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	September 30, 2018		December 31, 2017		September 30, 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]

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 September 30, 2018
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	2	—	$	1
	Other deferred credits and other liabilities	—		16		—	6
Commodity contracts	Prepayments	$	1	—		—	—
Total		$	1	$	18	—	$	7
Not designated as hedging instruments
Interest rate contracts	Other deferred credits and other liabilities	—		$	2	—	$	2
Commodity contracts	Prepayments	$	1	—		—	—
Energy management contracts	Prepayments	1		—		—	—
	Other current assets	1		—		—	—
	Other current liabilities	—		2		—	—
Total		$	3	$	4	—	$	2

		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of December 31, 2017
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	3	—		$	1
	Other deferred credits and other liabilities	—		24		—		9
Commodity contracts	Prepayments	—		2		—		—
	Other current assets	—		1		—		—
Total		—		$	30	—		$	10
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	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		—		—		—
	Derivative financial instruments	—		2		—		—
Total		$	59	$	8	$	54	$	5

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

The Company and Consolidated SCE&G:
	Gain (Loss) Deferred in Regulatory Accounts						(Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	—		—			Interest expense	—			—
Nine Months Ended September 30,
Interest rate contracts	$	2	$	(1	)	Interest expense	$	(1	)	$	(1	)

The Company:
	Gain (Loss) Recognized in OCI, net of tax						Gain (Loss) Reclassified from AOCI into Income, net of tax
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	$	1	—			Interest expense	$	(3	)	$	(2	)
Total	$	1	—				$	(3	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	3	$	(1	)	Interest expense	$	(7	)	$	(6	)
Commodity contracts	2		(4		)	Gas purchased for resale	(2		)	2
Total	$	5	$	(5	)		$	(9	)	$	(4	)

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 Regulatory Accounts						Gain (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	$	1	$	(6	)	Interest Expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	66	$	(30	)	Interest Expense	$	(2	)	$	(2	)
						Other Income	115			—

Disclosure of Credit Derivatives [Table Text Block]

Derivative Contracts with Credit Contingent Features
	The Company					Consolidated SCE&G
Millions of dollars	September 30, 2018			December 31, 2017		September 30, 2018		December 31, 2017
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	20.8		$	33.7	$	8.7	$	14.7
Fair value of collateral already posted	22.3			28.9		8.7		10.1
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	(1.5	)	$	4.8	—		$	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

Offseting Assets [Table Text Block]

Information related to the offsetting of derivative assets and derivative liabilities 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 September 30, 2018
Gross Amounts of Recognized Assets	—		$	2	$	2	$	4	—
Gross Amounts Offset in Statement of Financial Position	—		—		—		—		—
Net Amounts Presented in Statement of Financial Position	—		2		2		4		—
Gross Amounts Not Offset - Financial Instruments	—		—		—		—		—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—		—		—
Net Amount	—		$	2	$	2	$	4	—
Balance sheet location
Prepayments							$	3	—
Other current assets							1		—
Total							$	4	—
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]

Derivative Liabilities
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of September 30, 2018
Gross Amounts of Recognized Liabilities	$	20		—		$	2		$	22		$	9
Gross Amounts Offset in Statement of Financial Position	—			—		—			—			—
Net Amounts Presented in Statement of Financial Position	20			—		2			22			9
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(21		)	—		(1		)	(22		)	(9		)
Net Amount	$	(1	)	—		$	1		—			—
Balance sheet location
Derivative financial instruments									$	2		$	1
Other current liabilities									2			—
Other deferred credits and other liabilities									18			8
Total									$	22		$	9
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		)	27			—
Net Amount	$	60		$	3	$	1		$	64		$	15
Balance sheet location
Other current assets									$	2		—
Derivative financial instruments									7			$	2
Other deferred credits and other liabilities									28			13
Total									$	37		$	15

SCEG

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	September 30, 2018		December 31, 2017		September 30, 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]

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 September 30, 2018
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	2	—	$	1
	Other deferred credits and other liabilities	—		16		—	6
Commodity contracts	Prepayments	$	1	—		—	—
Total		$	1	$	18	—	$	7
Not designated as hedging instruments
Interest rate contracts	Other deferred credits and other liabilities	—		$	2	—	$	2
Commodity contracts	Prepayments	$	1	—		—	—
Energy management contracts	Prepayments	1		—		—	—
	Other current assets	1		—		—	—
	Other current liabilities	—		2		—	—
Total		$	3	$	4	—	$	2

		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of December 31, 2017
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	3	—		$	1
	Other deferred credits and other liabilities	—		24		—		9
Commodity contracts	Prepayments	—		2		—		—
	Other current assets	—		1		—		—
Total		—		$	30	—		$	10
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	$	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		—		—		—
	Derivative financial instruments	—		2		—		—
Total		$	59	$	8	$	54	$	5

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

The Company and Consolidated SCE&G:
	Gain (Loss) Deferred in Regulatory Accounts						(Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	—		—			Interest expense	—			—
Nine Months Ended September 30,
Interest rate contracts	$	2	$	(1	)	Interest expense	$	(1	)	$	(1	)

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 Regulatory Accounts						Gain (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2018		2017			Location	2018			2017
Three Months Ended September 30,
Interest rate contracts	$	1	$	(6	)	Interest Expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	66	$	(30	)	Interest Expense	$	(2	)	$	(2	)
						Other Income	115			—

For

Disclosure of Credit Derivatives [Table Text Block]

Derivative Contracts with Credit Contingent Features
	The Company					Consolidated SCE&G
Millions of dollars	September 30, 2018			December 31, 2017		September 30, 2018		December 31, 2017
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	20.8		$	33.7	$	8.7	$	14.7
Fair value of collateral already posted	22.3			28.9		8.7		10.1
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	(1.5	)	$	4.8	—		$	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

Offseting Assets [Table Text Block]

Information related to the offsetting of derivative assets and derivative liabilities 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 September 30, 2018
Gross Amounts of Recognized Assets	—		$	2	$	2	$	4	—
Gross Amounts Offset in Statement of Financial Position	—		—		—		—		—
Net Amounts Presented in Statement of Financial Position	—		2		2		4		—
Gross Amounts Not Offset - Financial Instruments	—		—		—		—		—
Gross Amounts Not Offset - Cash Collateral Received	—		—		—		—		—
Net Amount	—		$	2	$	2	$	4	—
Balance sheet location
Prepayments							$	3	—
Other current assets							1		—
Total							$	4	—
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]

Derivative Liabilities
Millions of dollars	Interest Rate Contracts			Commodity Contracts		Energy Management Contracts			Total			Interest Rate Contracts
As of September 30, 2018
Gross Amounts of Recognized Liabilities	$	20		—		$	2		$	22		$	9
Gross Amounts Offset in Statement of Financial Position	—			—		—			—			—
Net Amounts Presented in Statement of Financial Position	20			—		2			22			9
Gross Amounts Not Offset - Financial Instruments	—			—		—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(21		)	—		(1		)	(22		)	(9		)
Net Amount	$	(1	)	—		$	1		—			—
Balance sheet location
Derivative financial instruments									$	2		$	1
Other current liabilities									2			—
Other deferred credits and other liabilities									18			8
Total									$	22		$	9
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		)	27			—
Net Amount	$	60		$	3	$	1		$	64		$	15
Balance sheet location
Other current assets									$	2		—
Derivative financial instruments									7			$	2
Other deferred credits and other liabilities									28			13
Total									$	37		$	15

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

9 Months Ended

Sep. 30, 2018

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

 Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

	As of September 30, 2018						As of December 31, 2017
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	15	—		—		$	119	—		$	100	—
Held to maturity securities	—		$	6	—		—		$	6	—		—
Interest rate contracts	—		—		—		—		54		—		$	54
Commodity contracts	2		—		—		1		—		—		—
Energy management contracts	—		2		—		—		4		—		—
Liabilities:
Interest rate contracts	—		20		$	9	—		32		—		15
Commodity contracts	—		—		—		2		1		—		—
Energy management contracts	—		4		—		1		4		—		—

Fair Value, by Balance Sheet Grouping [Table Text Block]

Financial instruments for which the carrying amount may not equal estimated fair value were as follows:

Long-Term Debt	September 30, 2018				December 31, 2017
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,753.3	$	6,980.8	$	6,632.9	$	7,399.7
Consolidated SCE&G	5,145.2		5,295.2		5,163.3		5,790.3

SCEG

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

	As of September 30, 2018						As of December 31, 2017
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	15	—		—		$	119	—		$	100	—
Held to maturity securities	—		$	6	—		—		$	6	—		—
Interest rate contracts	—		—		—		—		54		—		$	54
Commodity contracts	2		—		—		1		—		—		—
Energy management contracts	—		2		—		—		4		—		—
Liabilities:
Interest rate contracts	—		20		$	9	—		32		—		15
Commodity contracts	—		—		—		2		1		—		—
Energy management contracts	—		4		—		1		4		—		—

Fair Value, by Balance Sheet Grouping [Table Text Block]

Financial instruments for which the carrying amount may not equal estimated fair value were as follows:

Long-Term Debt	September 30, 2018				December 31, 2017
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,753.3	$	6,980.8	$	6,632.9	$	7,399.7
Consolidated SCE&G	5,145.2		5,295.2		5,163.3		5,790.3

XML

EMPLOYEE BENEFIT PLANS (Tables)

9 Months Ended

Sep. 30, 2018

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

The Company	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017
Three months ended September 30,
Service cost	$	5.9		$	5.7		$	1.1		$	1.0
Interest cost	8.5			9.2			2.2			2.8
Expected return on assets	(14.0		)	(13.4		)	—			—
Prior service cost amortization	0.1			0.4			—			—
Amortization of actuarial (gains) losses	3.7			4.4			(0.5		)	—
Net periodic benefit cost	$	4.2		$	6.3		$	2.8		$	3.8
Nine months ended September 30,
Service cost	$	15.8		$	16.3		$	3.4		$	3.4
Interest cost	25.6			28.0			7.6			8.6
Expected return on assets	(42.6		)	(41.0		)	—			—
Prior service cost amortization	0.4			1.2			—			—
Amortization of actuarial losses	9.6			12.2			0.6			0.8
Net periodic benefit cost	$	8.8		$	16.7		$	11.6		$	12.8

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017
Three months ended September 30,
Service cost	$	4.8		$	4.8		$	0.9		$	0.8
Interest cost	7.2			7.8			1.7			2.3
Expected return on assets	(11.8		)	(11.4		)	—			—
Prior service cost amortization	0.1			0.3			—			—
Amortization of actuarial (gains) losses	3.1			3.7			(0.4		)	—
Net periodic benefit cost	$	3.4		$	5.2		$	2.2		$	3.1
Nine months ended September 30,
Service cost	$	12.9		$	13.6		$	2.7		$	2.8
Interest cost	21.6			24.0			6.0			7.1
Expected return on assets	(36.0		)	(35.0		)	—			—
Prior service cost amortization	0.3			1.0			—			—
Amortization of actuarial losses	8.1			10.4			0.5			0.6
Net periodic benefit cost	$	6.9		$	14.0		$	9.2		$	10.5

SCEG

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2018			2017			2018			2017
Three months ended September 30,
Service cost	$	4.8		$	4.8		$	0.9		$	0.8
Interest cost	7.2			7.8			1.7			2.3
Expected return on assets	(11.8		)	(11.4		)	—			—
Prior service cost amortization	0.1			0.3			—			—
Amortization of actuarial (gains) losses	3.1			3.7			(0.4		)	—
Net periodic benefit cost	$	3.4		$	5.2		$	2.2		$	3.1
Nine months ended September 30,
Service cost	$	12.9		$	13.6		$	2.7		$	2.8
Interest cost	21.6			24.0			6.0			7.1
Expected return on assets	(36.0		)	(35.0		)	—			—
Prior service cost amortization	0.3			1.0			—			—
Amortization of actuarial losses	8.1			10.4			0.5			0.6
Net periodic benefit cost	$	6.9		$	14.0		$	9.2		$	10.5

XML

SEGMENT OF BUSINESS INFORMATION (Tables)

9 Months Ended

Sep. 30, 2018

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

The Company
Millions of dollars	External Revenue		Intersegment Revenue			Operating Income (Loss)			Net Income
Three Months Ended September 30, 2018
Electric Operations	$	669	—			$	217		n/a
Gas Distribution	122		—			(10		)	n/a
Gas Marketing	135		$	35		n/a			$	1
All Other	—		124			—			(30		)
Adjustments/Eliminations	—		(159		)	(24		)	96
Consolidated Total	$	926	—			$	183		$	67
Nine Months Ended September 30, 2018
Electric Operations	$	1,767	$	3		$	396		n/a
Gas Distribution	631		1			107			n/a
Gas Marketing	550		95			n/a			$	21
All Other	—		347			—			(79		)
Adjustments/Eliminations	—		(446		)	(28		)	302
Consolidated Total	$	2,948	—			$	475		$	244

Three Months Ended September 30, 2017
Electric Operations	$	786	$	1		$	127		n/a
Gas Distribution	123		—			(7		)	n/a
Gas Marketing	167		35			n/a			$	1
All Other	—		90			—			(7		)
Adjustments/Eliminations	—		(126		)	2			40
Consolidated Total	$	1,076	—			$	122		$	34
Nine Months Ended September 30, 2017
Electric Operations	$	2,042	$	4		$	555		n/a
Gas Distribution	584		1			110			n/a
Gas Marketing	623		93			n/a			$	17
All Other	—		286			—			(14		)
Adjustments/Eliminations	—		(384		)	28			323
Consolidated Total	$	3,249	—			$	693		$	326

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income (Loss)			Comprehensive Income Available to Common Shareholder
Three Months Ended September 30, 2018
Electric Operations	$	670	$	216		n/a
Gas Distribution	69		(4		)	n/a
Adjustments/Eliminations	—		—			$	98
Consolidated Total	$	739	$	212		$	98
Nine Months Ended September 30, 2018
Electric Operations	$	1,770	$	396		n/a
Gas Distribution	304		44			n/a
Adjustments/Eliminations	—		—			$	248
Consolidated Total	$	2,074	$	440		$	248

Three Months Ended September 30, 2017
Electric Operations	$	787	$	126		n/a
Gas Distribution	69		(2		)	n/a
Adjustments/Eliminations	—		—			$	39
Consolidated Total	$	856	$	124		$	39
Nine Months Ended September 30, 2017
Electric Operations	$	2,046	$	555		n/a
Gas Distribution	285		42			n/a
Adjustments/Eliminations	—		—			$	270
Consolidated Total	$	2,331	$	597		$	270

Segment Assets	The Company				Consolidated SCE&G
	September 30,		December 31,		September 30,		December 31,
Millions of dollars	2018		2017		2018		2017
Electric Operations	$	12,046	$	11,979	$	12,046	$	11,979
Gas Distribution	3,384		3,259		909		869
Gas Marketing	204		230		n/a		n/a
All Other	1,071		1,042		n/a		n/a
Adjustments/Eliminations	2,111		2,229		3,174		3,098
Consolidated Total	$	18,816	$	18,739	$	16,129	$	15,946

SCEG

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income (Loss)			Comprehensive Income Available to Common Shareholder
Three Months Ended September 30, 2018
Electric Operations	$	670	$	216		n/a
Gas Distribution	69		(4		)	n/a
Adjustments/Eliminations	—		—			$	98
Consolidated Total	$	739	$	212		$	98
Nine Months Ended September 30, 2018
Electric Operations	$	1,770	$	396		n/a
Gas Distribution	304		44			n/a
Adjustments/Eliminations	—		—			$	248
Consolidated Total	$	2,074	$	440		$	248

Three Months Ended September 30, 2017
Electric Operations	$	787	$	126		n/a
Gas Distribution	69		(2		)	n/a
Adjustments/Eliminations	—		—			$	39
Consolidated Total	$	856	$	124		$	39
Nine Months Ended September 30, 2017
Electric Operations	$	2,046	$	555		n/a
Gas Distribution	285		42			n/a
Adjustments/Eliminations	—		—			$	270
Consolidated Total	$	2,331	$	597		$	270

Segment Assets	The Company				Consolidated SCE&G
	September 30,		December 31,		September 30,		December 31,
Millions of dollars	2018		2017		2018		2017
Electric Operations	$	12,046	$	11,979	$	12,046	$	11,979
Gas Distribution	3,384		3,259		909		869
Gas Marketing	204		230		n/a		n/a
All Other	1,071		1,042		n/a		n/a
Adjustments/Eliminations	2,111		2,229		3,174		3,098
Consolidated Total	$	18,816	$	18,739	$	16,129	$	15,946

XML

AFFILIATED TRANSACTIONS Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2018

Related Party Transaction [Line Items]

Schedule of Related Party Transactions [Table Text Block]

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from Canadys Refined Coal, LLC	$	45.2	$	47.5	$	122.5	$	144.9
Sales to Canadys Refined Coal, LLC	44.9		47.2		121.8		144.0

Millions of Dollars	September 30, 2018		December 31, 2017
Receivable from Canadys Refined Coal, LLC	$	8.5	$	4.9
Payable to Canadys Refined Coal, LLC	8.5		4.9

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from SCANA Energy	$	35.0	$	35.3	$	95.0	$	93.4
Direct and Allocated Costs from SCANA Services	72.9		78.1		208.3		233.6

Millions of Dollars	September 30, 2018		December 31, 2017
Payable to SCANA Energy	$	10.6	$	10.0
Payable to SCANA Services	42.8		42.0

Related Party Transactions Disclosure [Text Block]

AFFILIATED TRANSACTIONS

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 income (for the Company) and of comprehensive income (for Consolidated SCE&G).

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from Canadys Refined Coal, LLC	$	45.2	$	47.5	$	122.5	$	144.9
Sales to Canadys Refined Coal, LLC	44.9		47.2		121.8		144.0

Millions of Dollars	September 30, 2018		December 31, 2017
Receivable from Canadys Refined Coal, LLC	$	8.5	$	4.9
Payable to Canadys Refined Coal, LLC	8.5		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.

Consolidated SCE&G has provided $71.0 million in funding to a rabbi trust consolidated with SCANA in connection with the potential change in control arising from the Merger Agreement. This funding is recorded as long-term Other affiliate assets on the condensed consolidated balance sheet of Consolidated SCE&G.

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from SCANA Energy	$	35.0	$	35.3	$	95.0	$	93.4
Direct and Allocated Costs from SCANA Services	72.9		78.1		208.3		233.6

Millions of Dollars	September 30, 2018		December 31, 2017
Payable to SCANA Energy	$	10.6	$	10.0
Payable to SCANA Services	42.8		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.

SCEG

Related Party Transaction [Line Items]

Schedule of Related Party Transactions [Table Text Block]

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from SCANA Energy	$	35.0	$	35.3	$	95.0	$	93.4
Direct and Allocated Costs from SCANA Services	72.9		78.1		208.3		233.6

Millions of Dollars	September 30, 2018		December 31, 2017
Payable to SCANA Energy	$	10.6	$	10.0
Payable to SCANA Services	42.8		42.0

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from Canadys Refined Coal, LLC	$	45.2	$	47.5	$	122.5	$	144.9
Sales to Canadys Refined Coal, LLC	44.9		47.2		121.8		144.0

Millions of Dollars	September 30, 2018		December 31, 2017
Receivable from Canadys Refined Coal, LLC	$	8.5	$	4.9
Payable to Canadys Refined Coal, LLC	8.5		4.9

Related Party Transactions Disclosure [Text Block]

AFFILIATED TRANSACTIONS

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 income (for the Company) and of comprehensive income (for Consolidated SCE&G).

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from Canadys Refined Coal, LLC	$	45.2	$	47.5	$	122.5	$	144.9
Sales to Canadys Refined Coal, LLC	44.9		47.2		121.8		144.0

Millions of Dollars	September 30, 2018		December 31, 2017
Receivable from Canadys Refined Coal, LLC	$	8.5	$	4.9
Payable to Canadys Refined Coal, LLC	8.5		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.

Consolidated SCE&G has provided $71.0 million in funding to a rabbi trust consolidated with SCANA in connection with the potential change in control arising from the Merger Agreement. This funding is recorded as long-term Other affiliate assets on the condensed consolidated balance sheet of Consolidated SCE&G.

	Three Months Ended September 30,				Nine Months Ended September 30,
Millions of Dollars	2018		2017		2018		2017
Purchases from SCANA Energy	$	35.0	$	35.3	$	95.0	$	93.4
Direct and Allocated Costs from SCANA Services	72.9		78.1		208.3		233.6

Millions of Dollars	September 30, 2018		December 31, 2017
Payable to SCANA Energy	$	10.6	$	10.0
Payable to SCANA Services	42.8		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.

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OTHER INCOME (EXPENSE), NET Other Income (Expense) (Tables)

9 Months Ended

Sep. 30, 2018

Schedule of Other Nonoperating Income (Expense) [Table Text Block]

	The Company												Consolidated SCE&G
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
Millions of dollars	2018			2017			2018			2017			2018			2017			2018			2017
Revenues from contracts with customers	$	4		—			$	14		—			$	1		—			$	4		—
Other income	8			$	28		144			$	61		5			$	21		135			$	36
Other expense	(14		)	(9		)	(34		)	(33		)	(10		)	(7		)	(22		)	(23		)
Allowance for equity funds used during construction	5			—			12			17			3			(3		)	7			13
Other income (expense), net	$	3		$	19		$	136		$	45		$	(1	)	$	11		$	124		$	26

SCEG

Schedule of Other Nonoperating Income (Expense) [Table Text Block]

	The Company												Consolidated SCE&G
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
Millions of dollars	2018			2017			2018			2017			2018			2017			2018			2017
Revenues from contracts with customers	$	4		—			$	14		—			$	1		—			$	4		—
Other income	8			$	28		144			$	61		5			$	21		135			$	36
Other expense	(14		)	(9		)	(34		)	(33		)	(10		)	(7		)	(22		)	(23		)
Allowance for equity funds used during construction	5			—			12			17			3			(3		)	7			13
Other income (expense), net	$	3		$	19		$	136		$	45		$	(1	)	$	11		$	124		$	26

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) MW	Sep. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Reclassification Operations and Maintenance Expense	$ (2.0)		$ (8.0)
Reclassification Total Operating Expense	(2.0)		(8.0)
Reclassification Operating Income	2.0		8.0
Reclassification Other Income(Expense)	(2.0)		(8.0)
Property, Plant and Equipment, Net		$ 269.0		$ 270.0
SCEG
Reclassification Operations and Maintenance Expense	(1.0)		(6.0)
Reclassification Total Operating Expense	(1.0)		(6.0)
Reclassification Operating Income	1.0		6.0
Reclassification Other Income(Expense)	$ (1.0)		$ (6.0)
Property, Plant and Equipment, Net		73.0		$ 71.0
Genco
Property, Plant and Equipment, Net		$ 495.0
Power Generation Capacity Megawatts | MW		605
PSNC Energy [Member]
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)		45.00%		39.00%
Natural gas inventory, carrying amount		$ 14.3		$ 11.5
PercentOfStorageFeesCreditedToRatePayers		75.00%

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RATE AND OTHER REGULATORY MATTERS (Details) - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Dec. 31, 2018	Mar. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Jan. 01, 2019
Rate Matters [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent			21.00%	35.00%	35.00%
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery			$ 0.035
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA			18.00%
Change in Retail Electric Rates Approved Under BLRA			$ 0.032
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 31,000,000
Asset Retirement Obligation Costs [Member]
Rate Matters [Line Items]
Regulatory Noncurrent Asset Amortization Period			107 years
Environmental Restoration Costs [Member]
Rate Matters [Line Items]
MPG environmental remediation			17
SCEG
Rate Matters [Line Items]
Refund to Customer Related to Tax Act			$ 61,000,000
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			1,300,000
SCPSC Order, Annual DSM Program Rate Rider Recovery Amount			33,000,000
Public Utilities changes in Retail Natural Gas Rates Approved under RSA	$ 19,700,000
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates	4.61%
SCEG | Pension costs, electric [Member]
Rate Matters [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority			2,000,000
SCEG | Pension costs, gas [Member]
Rate Matters [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority			1,000,000
SCANA [Member]
Rate Matters [Line Items]
Refund to Customer Related to Tax Act			3,800,000
PSNC Energy
Rate Matters [Line Items]
Proposed Merger Credits						$ 1,250,000
Refund to Customer Related to Tax Act			$ 10,100,000
MPG environmental remediation			4.2
Pipeline integrity mgmt annual revenue requirement approved by NCUC		$ 14,700,000

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RATE AND OTHER REGULATORY MATTERS (Details 2) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Mar. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Regulatory Assets
Asset Impairment Charges		$ 4.0	$ 210.0
Regulatory Liability, Noncurrent		3,040.0		$ 3,059.0
Regulatory Assets, Noncurrent		5,739.0		5,580.0
SCEG
Regulatory Assets
Asset Impairment Charges		4.0	$ 210.0
Regulatory Liability, Noncurrent		2,635.0		2,667.0
Regulatory Assets, Noncurrent		5,623.0		5,476.0
PSNC Energy [Member]
Regulatory Assets
Pipeline integrity mgmt annual revenue requirement approved by NCUC	$ 14.7
Pipeline integrity management costs, amount deferred pending future approval of rate recovery		$ 44.9
MPG environmental remediation		4.2
Pipeline integrity management costs, amount recovering beginning November 2016		$ 4.1
Settlement Proceeds [Member] | Summer Station Unit 2 and Unit 3 [Domain]
Regulatory Assets
Regulatory Liability, Noncurrent		1,098.0		1,095.0
Settlement Proceeds [Member] | SCEG
Regulatory Assets
Regulatory Liability, Noncurrent		1,098.0		1,095.0
Deferred Income Tax Charge [Member]
Regulatory Assets
Regulatory Liability, Noncurrent		1,075.0		1,076.0
Deferred Income Tax Charge [Member] | SCEG
Regulatory Assets
Regulatory Liability, Noncurrent		916.0		914.0
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Liability, Noncurrent		775.0		757.0
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Liability, Noncurrent		539.0		527.0
Deferred gains on interest rate derivatives [Member]
Regulatory Assets
Regulatory Liability, Noncurrent		77.0		131.0
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Assets
Regulatory Liability, Noncurrent		77.0		131.0
Other Regulatory Liability [Member]
Regulatory Assets
Regulatory Liability, Noncurrent		15.0
Other Regulatory Liability [Member] | SCEG
Regulatory Assets
Regulatory Liability, Noncurrent		5.0		0.0
Unrecovered nuclear project costs post impairment [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		$ 4,140.0		3,976.0
Unrecovered nuclear project costs post impairment [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent				3,976.0
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Asset, Amortization Period		107 years
Regulatory Assets, Noncurrent		$ 448.0		434.0
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		423.0		410.0
Pension Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		282.0		305.0
Pension Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		254.0		273.0
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		446.0		456.0
Deferred Losses On Interest Rate Derivatives [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		446.0		456.0
unrecovered plant [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		96.0		105.0
unrecovered plant [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		96.0		105.0
Demand Side Management programs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		$ 57.0		59.0
Demand Side Management programs [Member] | SCEG
Regulatory Assets
Regulatory Asset, Amortization Period		5 years
Regulatory Assets, Noncurrent		$ 57.0		59.0
Pipeline integrity management costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		67.0		51.0
Pipeline integrity management costs [Member] | SCEG
Regulatory Assets
Pipeline integrity management costs, annual amortization amount		1.9
Regulatory Assets, Noncurrent		$ 9.0		8.0
Environmental Restoration Costs [Member]
Regulatory Assets
MPG environmental remediation		17
Regulatory Assets, Noncurrent		$ 28.0		30.0
Environmental Restoration Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		24.0		25.0
Storm Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		29.0		24.0
Storm Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		$ 29.0		24.0
Other Regulatory Assets [Member]
Regulatory Assets
Regulatory Asset Recovery Assessments		2047
Regulatory Assets, Noncurrent		$ 135.0		140.0
Other Regulatory Assets [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		134.0		$ 140.0
Deferred transmission operating costs [Member] [Domain]
Regulatory Assets
Regulatory Assets, Noncurrent		11.0
Deferred transmission operating costs [Member] [Domain] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		$ 11.0

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RATE AND OTHER REGULATORY MATTERS (Details 3) - USD ($) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%	35.00%
Regulatory Liabilities	$ 3,040.0		$ 3,059.0
SCEG
Regulatory Liabilities [Line Items]
Refund to Customer Related to Tax Act	61.0
Regulatory Liabilities	2,635.0		2,667.0
PSNC Energy [Member]
Regulatory Liabilities [Line Items]
Refund to Customer Related to Tax Act	10.1
Settlement Proceeds [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	1,098.0		1,095.0
Deferred Income Tax Charge [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	1,075.0		1,076.0
Deferred Income Tax Charge [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	916.0		914.0
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	775.0		757.0
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	539.0		527.0
Deferred gains on interest rate derivatives [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	77.0		131.0
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	77.0		131.0
Other Regulatory Liability [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	15.0
Other Regulatory Liability [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 5.0		$ 0.0

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REVENUE RECOGNITION (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Electric Regulated Revenue	$ 669.0	$ 786.0	$ 1,767.0	$ 2,042.0
Regulated Operating Revenue, Gas	122.0	123.0	631.0	584.0
Total Operating Revenues Gas	122.0		629.0
SCEG
Electric Regulated Revenue	669.0	786.0	1,767.0	2,042.0
Regulated Operating Revenue, Gas	69.0	69.0	303.0	284.0
Capitalized Contract Cost, Net	15.2		15.2		$ 16.3
Regulated Operating Revenue	739.0	856.0	2,074.0	2,331.0
Capitalized Contract Cost, Amortization			(1.1)
Electric Operations
Electric Regulated Revenue		786.0		2,042.0
Electric Operations | SCEG
Electric Regulated Revenue		$ 787.0		$ 2,046.0
Disaggregation of Revenue [Table Text Block]	667.0		1,761.0
Other Revenues	3.0		9.0
Regulated Operating Revenue	670.0		1,770.0
Residential [Member]
Total Operating Revenues Gas	52.0		355.0
Gas -non regulated revenues	22.0		158.0
Residential [Member] | SCEG
Electric Regulated Revenue	310.0		805.0
Regulated Operating Revenue, Gas	25.0		145.0
Residential [Member] | PSNC Energy [Member]
Regulated Operating Revenue, Gas	27.0		210.0
Wholesale [Member]
Total Operating Revenues Gas	13.0		35.0
Gas -non regulated revenues	6.0		24.0
Wholesale [Member] | SCEG
Electric Regulated Revenue	31.0		99.0
Regulated Operating Revenue, Gas	6.0		13.0
Wholesale [Member] | PSNC Energy [Member]
Regulated Operating Revenue, Gas	7.0		22.0
Industrial [Member]
Total Operating Revenues Gas	19.0		74.0
Gas -non regulated revenues	93.0		304.0
Industrial [Member] | SCEG
Electric Regulated Revenue	95.0		286.0
Regulated Operating Revenue, Gas	19.0		64.0
Industrial [Member] | PSNC Energy [Member]
Regulated Operating Revenue, Gas	0.0		10.0
Commercial [Member]
Total Operating Revenues Gas	38.0		165.0
Gas -non regulated revenues	14.0		64.0
Commercial [Member] | SCEG
Electric Regulated Revenue	231.0		571.0
Regulated Operating Revenue, Gas	19.0		80.0
Commercial [Member] | PSNC Energy [Member]
Regulated Operating Revenue, Gas	19.0		85.0
Gas Distribution
Total Operating Revenues Gas	122.0		631.0
Other Revenues	0.0		2.0
Gas Distribution | SCEG
Disaggregation of Revenue [Table Text Block]	69.0		302.0
Other Revenues	0.0		1.0
Regulated Operating Revenue	69.0		303.0
Gas Distribution | PSNC Energy [Member]
Disaggregation of Revenue [Table Text Block]	53.0		327.0
Other Revenues	0.0		1.0
Regulated Operating Revenue	53.0		328.0
Gas Marketing segment [Member]
Disaggregation of Revenue [Table Text Block]	135.0		550.0
Other Revenues	0.0		0.0
Regulated Operating Revenue	$ 135.0		$ 550.0

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REVENUE RECOGNITION Contract Costs (Details) - SCEG - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Capitalized Contract Cost, Amortization	$ (1.1)
Capitalized Contract Cost, Net	15.2	$ 16.3
Capitalized Contract Cost, Gross	$ 0.0

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COMMON EQUITY (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Schedule of Capitalization, Equity [Line Items]
Dividend Payment Restrictions Schedule, Description			0.6125
Common Stock, Shares Authorized	200.0		200.0
Common Stock, Shares, Outstanding	143.0		143.0		143.0
SCEG
Schedule of Capitalization, Equity [Line Items]
Retained Earnings, Appropriated	$ 99.9	$ 83.9	$ 99.9	$ 83.9
Common Stock, Shares Authorized	50.0		50.0
Common Stock, Shares, Outstanding	40.3		40.3		40.3
Preferred Stock, Shares Authorized	20.0		20.0
Preferred Stock, Shares Outstanding	0.0		0.0
PSNC Energy [Member]
Schedule of Capitalization, Equity [Line Items]
Dividend Payment Restrictions Schedule, Description			$30 million plus 85%
Cash distributions in allowed in excess			$ 100.0
Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 0.0	0.0	(2.0)	2.0
Interest Rate Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(3.0)	(2.0)	(7.0)	(6.0)
Gas Purchased for Resale [Member] [Member] | Cash Flow Hedging [Member] | Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net			2.0	(2.0)
Interest Expense [Member] | Cash Flow Hedging [Member] | Interest Rate Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 3.0	$ 2.0	$ 7.0	$ 6.0

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LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($)	6 Months Ended		9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Related Party Transaction, Due from (to) Related Party, Current			$ 195,000,000	$ 28,000,000
Proceeds from Issuance of First Mortgage Bond			300,000,000
SCEG
Debt Instrument [Line Items]
Debt Instrument, Face Amount			67,800,000	67,800,000
Related Party Transaction, Due from (to) Related Party, Current			177,000,000	$ 37,000,000
Proceeds from Issuance of First Mortgage Bond			400,000,000
Genco
Debt Instrument [Line Items]
Secured Debt			160,000,000
Interest Expense, Debt			$ 0.0606
PSNC Energy [Member]
Debt Instrument [Line Items]
Senior Notes	$ 100,000,000	$ 150,000,000
Debt Instrument, Interest Rate, Increase (Decrease)	4.33%	4.18%

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LONG-TERM AND SHORT-TERM DEBT (Details 2) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Interest Income, Related Party	$ 1.0	$ 3.0
Interest Expense, Related Party	1.1	2.5
Proceeds from Issuance of First Mortgage Bond		$ 300.0
interest rate on first mortgage bonds issued		4.25%
Borrowings under credit agreement		$ 100.0
Related Party Transaction, Due from (to) Related Party, Current	195.0	195.0	$ 28.0
Line of Credit Facility, Maximum Borrowing Capacity	2,000.0	2,000.0	2,000.0
Borrowings under LOC		40.0
Long-term Line of Credit	1,800.0	$ 1,800.0
Weighted Average interest rate on LOC borrowing		0.00%
Commercial Paper	314.2	$ 314.2	350.3
Letters of Credit Outstanding, Amount	37.6	37.6	3.3
Line of Credit Facility, Remaining Borrowing Capacity	1,608.2	1,608.2	1,646.4
Commercial paper borrowing limit	600.0	600.0
Repayments of First Mortgage Bond		$ 250.0
interest rate first mortgage bonds redeemed		6.50%
First Mortgage Bond rate [Domain]
Debt Instrument [Line Items]
interest rate on first mortgage bonds issued		3.50%
five year credit [Domain]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,300.0	$ 1,300.0	1,300.0
SCANA [Member]
Debt Instrument [Line Items]
Borrowings under credit agreement		40.0
Line of Credit Facility, Maximum Borrowing Capacity	400.0	$ 400.0	400.0
Weighted Average interest rate on LOC borrowing		3.78%
Commercial Paper	$ 3.7	$ 3.7	$ 0.0
Debt, Weighted Average Interest Rate	3.20%	3.20%	0.00%
Letters of Credit Outstanding, Amount	$ 37.3	$ 37.3	$ 3.0
Line of Credit Facility, Remaining Borrowing Capacity	319.0	319.0	397.0
SCEG including Fuel Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,400.0	1,400.0	1,400.0
Borrowings under LOC		0.0
Commercial Paper	$ 173.2	$ 173.2	$ 251.6
Debt, Weighted Average Interest Rate	3.21%	3.21%	1.92%
Letters of Credit Outstanding, Amount	$ 0.3	$ 0.3	$ 0.3
Line of Credit Facility, Remaining Borrowing Capacity	1,226.5	1,226.5	1,148.1
Commercial paper borrowing limit	1,600.0	1,600.0
Genco
Debt Instrument [Line Items]
Commercial paper borrowing limit	200.0	200.0
Fuel Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	500.0	500.0	500.0
Long-Term Line of Credit - SC Fuel Co only	500.0	500.0	500.0
SCEG
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond		400.0
Related Party Transaction, Due from (to) Related Party, Current	177.0	177.0	37.0
Line of Credit Facility, Maximum Borrowing Capacity	700.0	700.0	700.0
Long-term Line of Credit	1,200.0	1,200.0
Long-term Line of Credit - SCE&G only	200.0	200.0	200.0
Repayments of First Mortgage Bond		$ 300.0
interest rate first mortgage bonds redeemed		5.25%
PSNC Energy [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200.0	$ 200.0	200.0
Commercial Paper	$ 137.3	$ 137.3	$ 98.7
Debt, Weighted Average Interest Rate	3.13%	3.13%	1.93%
Line of Credit Facility, Remaining Borrowing Capacity	$ 62.7	$ 62.7	$ 101.3

XML

INCOME TAXES (Details) - USD ($)	3 Months Ended	9 Months Ended		12 Months Ended
	Mar. 31, 2019	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		$ 98,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate		98,000,000
Decrease in Unrecognized Tax Benefits is Reasonably Possible		11,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Accrued		1.4
Deferred Tax Liabilities, Deferred Expense, Reserves and Accruals		$ 6,800,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	2.50%	3.00%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	35.00%	35.00%
SCEG
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		$ 98,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate		98,000,000
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound		0
Decrease in Unrecognized Tax Benefits is Reasonably Possible		11,000,000
SCANA [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		$ 19,000,000

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2018 USD ($) MMBTU	Dec. 31, 2017 MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	64,855,232	61,719,890
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,050,000	6,430,000
Gas Marketing segment [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	57,805,232	55,289,890
Commodity Contract
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	23,906,000	19,863,000
Commodity Contract | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,050,000	6,430,000
Commodity Contract | Gas Marketing segment [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	16,856,000	13,433,000
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	40,949,232	41,856,890
Energy Related Derivative [Member] | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0	0
Energy Related Derivative [Member] | Gas Marketing segment [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	40,949,232	41,856,890
Energy Related Derivative [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	9,396,000	2,582,000

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DERIVATIVE FINANCIAL INSTRUMENTS Fair Value on Balance Sheet (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 4.0	$ 59.0
Derivative Liability, Fair Value, Gross Liability	22.0	38.0
Interest Rate Contract
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0.0	54.0
Derivative Liability, Fair Value, Gross Liability	20.0	32.0
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2.0	1.0
Derivative Liability, Fair Value, Gross Liability	0.0	3.0
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2.0	4.0
Derivative Liability, Fair Value, Gross Liability	2.0	3.0
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1.0	0.0
Derivative Liability, Fair Value, Gross Liability	18.0	30.0
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	106.8	111.2
Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	2.0	3.0
Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	16.0	24.0
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1.0	0.0
Derivative Liability, Fair Value, Gross Liability	0.0	2.0
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0
Derivative Liability, Fair Value, Gross Liability		1.0
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	3.0	59.0
Derivative Liability, Fair Value, Gross Liability	4.0	8.0
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	35.0	735.0
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		1.0
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		54.0
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	2.0	4.0
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1.0
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		1.0
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		2.0
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		1.0
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	2.0
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1.0	0.0
Derivative Liability, Fair Value, Gross Liability		1.0
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1.0	3.0
Derivative Liability, Fair Value, Gross Liability		0.0
SCEG | Interest Rate Contract
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0.0	54.0
Derivative Liability, Fair Value, Gross Liability	9.0	15.0
SCEG | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	7.0	10.0
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	36.4	36.4
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1.0	1.0
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	6.0	9.0
SCEG | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0.0	54.0
Derivative Liability, Fair Value, Gross Liability	2.0	5.0
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	35.0	735.0
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		1.0
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		54.0
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 2.0	$ 4.0

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DERIVATIVE FINANCIAL INSTRUMENTS On Income Statement (Details) - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ 1.0	$ 1.0	$ 3.0	$ 0.0	$ (3.0)	$ (2.0)	$ 5.0	$ (5.0)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ (3.0)	$ (2.0)	$ (4.0)	$ (2.0)	$ (2.0)		$ (9.0)	$ (4.0)
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant			insignificant			insignificant	insignificant
Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 0.0			$ 0.0			$ 2.0	$ (2.0)
Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax							2.0	(4.0)
Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	3.0			2.0			7.0	6.0
Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	1.0			0.0			3.0	(1.0)
Gas Purchased for Resale [Member] [Member] | Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net							(2.0)	2.0
Gas Purchased for Resale [Member] [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred							0.5
Interest Expense [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred							7.9
Interest Expense [Member] | Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (3.0)			$ (2.0)			$ (7.0)	$ (6.0)
SCEG
Derivative [Line Items]
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant			insignificant			insignificant	insignificant
Not Designated as Hedging Instrument [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ 1.0			$ (6.0)			$ 66.0	$ (30.0)
Not Designated as Hedging Instrument [Member] | Other Nonoperating Income (Expense) [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income				(1.0)				(2.0)
Not Designated as Hedging Instrument [Member] | Interest Expense [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(1.0)						(2.0)
Not Designated as Hedging Instrument [Member] | Interest Expense [Member] | Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred							(2.8)
Not Designated as Hedging Instrument [Member] | Other Income [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income							115.0
Designated as Hedging Instrument [Member] | Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net				0.0			2.0	(1.0)
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred							(1.0)
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ 0.0			$ 0.0			$ (1.0)	$ (1.0)

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DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Credit Risk) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Derivative [Line Items]
Letter of Credit Available Commodity Derivatives asset position	$ 0.3		$ 0.3		$ 1.2
Commodity Derivative, Net Asset Position, Aggregate Fair Value	2.9		2.9		4.0
Collateral Already Posted, Aggregate Fair Value	22.3		22.3		28.9
Additional Collateral, Aggregate Fair Value	(1.5)		(1.5)		(4.8)
Derivative, Net Liability Position, Aggregate Fair Value	20.8		20.8		33.7
Cash collateral to request from interest rate derivative counterparty	0.0		0.0		53.5
Interest Rate Derivative, net asset position, Aggregate Fair Value	0.0		0.0		53.5
SCEG
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	8.7		8.7		10.1
Additional Collateral, Aggregate Fair Value	0.0		0.0		(4.6)
Derivative, Net Liability Position, Aggregate Fair Value	8.7		8.7		14.7
Cash collateral to request from interest rate derivative counterparty	0.0		0.0		53.5
Interest Rate Derivative, net asset position, Aggregate Fair Value	0.0		0.0		$ 53.5
Not Designated as Hedging Instrument [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	1.0	$ (6.0)	66.0	$ (30.0)
Designated as Hedging Instrument [Member] | Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net		0.0	2.0	(1.0)
Interest Expense [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(1.0)		(2.0)
Interest Expense [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ 0.0	$ 0.0	(1.0)	$ (1.0)
Other Income [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income			$ 115.0

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DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments Offsetting Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 4	$ 59
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset	4	59
Derivative Liability, Fair Value, Gross Liability	22	38
Derivative Liability, Fair Value, Gross Asset	0	(1)
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative, Collateral, Right to Reclaim Cash	22	27
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	64
Derivative Liability	22	37
Derivative, Collateral, Obligation to Return Securities	0	0
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	4	59
Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	2	7
Prepayments [Member]
Derivative [Line Items]
Derivative Asset	3
Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	1	58
Derivative Liability		2
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset		1
Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	18	28
Other Liabilities	2
Interest Rate Contract
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	54
Derivative Asset	0	54
Derivative Liability, Fair Value, Gross Liability	20	32
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative, Collateral, Right to Reclaim Cash	21	28
Derivative Liability, Fair Value, Amount Offset Against Collateral	(1)	60
Derivative Liability	20	32
Derivative, Collateral, Obligation to Return Securities	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0	54
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2	1
Derivative Asset, Fair Value, Gross Liability	0
Derivative Asset	2	1
Derivative Liability, Fair Value, Gross Liability	0	3
Derivative Liability, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	3
Derivative Liability	0	3
Derivative Asset, Fair Value, Amount Offset Against Collateral	2	1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2	4
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset	2	4
Derivative Liability, Fair Value, Gross Liability	2	3
Derivative Liability, Fair Value, Gross Asset	0	(1)
Derivative, Collateral, Right to Reclaim Cash	1	1
Derivative Liability, Fair Value, Amount Offset Against Collateral	1	1
Derivative Liability	2	2
Derivative Asset, Fair Value, Amount Offset Against Collateral	2	4
SCEG
Derivative [Line Items]
Derivative Asset	0	54
Derivative Liability	9	15
SCEG | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	1	2
SCEG | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset		54
SCEG | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset		0
SCEG | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	8	13
SCEG | Interest Rate Contract
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	54
Derivative Asset	0	54
Derivative Liability, Fair Value, Gross Liability	9	15
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative, Collateral, Right to Reclaim Cash	9	0
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	15
Derivative Liability	9	15
Derivative, Collateral, Obligation to Return Securities	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	$ 0	$ 54

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	$ 15	$ 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 | 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
Liabilities, Fair Value Disclosure	20	32
Commodity Contract | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	2	1
Liabilities, Fair Value Disclosure	0	2
Commodity Contract | 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
Liabilities, Fair Value Disclosure	0	1
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	0
Liabilities, Fair Value Disclosure	0	1
Other energy management contracts [Member] [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
Liabilities, Fair Value Disclosure	4	4
SCEG | Available-for-sale Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure		100
SCEG | Interest Rate Contract | 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
Liabilities, Fair Value Disclosure	$ 9	$ 15

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 6,753.3	$ 6,632.9
Long-term Debt, Fair Value	6,980.8	7,399.7
SCEG
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	5,145.2	5,163.3
Long-term Debt, Fair Value	$ 5,295.2	$ 5,790.3

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EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pension and Other Postretirement Benefit Plans
Pension Contributions			No
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 5.9	$ 5.7	$ 15.8	$ 16.3
Interest cost	8.5	9.2	25.6	28.0
Expected return on assets	(14.0)	(13.4)	(42.6)	(41.0)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.4	0.4	1.2
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.7	4.4	9.6	12.2
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	4.2	6.3	8.8	16.7
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.1	1.0	3.4	3.4
Interest cost	2.2	2.8	7.6	8.6
Expected return on assets	0.0	0.0	0.0	0.0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.0	0.0	0.0	0.0
Defined Benefit Plan, Actuarial Net (Gains) Losses	(0.5)	0.0	0.6	0.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	2.8	3.8	$ 11.6	12.8
SCEG
Pension and Other Postretirement Benefit Plans
Pension Contributions			No
SCEG | Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	4.8	4.8	$ 12.9	13.6
Interest cost	7.2	7.8	21.6	24.0
Expected return on assets	(11.8)	(11.4)	(36.0)	(35.0)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.3	0.3	1.0
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.1	3.7	8.1	10.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	3.4	5.2	6.9	14.0
SCEG | Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	0.9	0.8	2.7	2.8
Interest cost	1.7	2.3	6.0	7.1
Expected return on assets	0.0	0.0	0.0	0.0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.0	0.0	0.0	0.0
Defined Benefit Plan, Actuarial Net (Gains) Losses	(0.4)	0.0	0.5	0.6
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 2.2	$ 3.1	$ 9.2	$ 10.5

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COMMITMENTS AND CONTINGENCIES (Details)	3 Months Ended				9 Months Ended		12 Months Ended
	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Commitments and contingencies
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 31,000,000
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments		$ 180,000,000			180,000,000
Sales and Excise Tax Payable		410,000,000			410,000,000
Utilities Operating Loss, Impairment, Net of Taxes		3,700,000,000	$ 2,700,000					$ 690,000,000
Impairment loss write off		3,960,000,000
Regulatory Request to Lower Revenues	$ 279,000,000				445,000,000
Utilities Operating Expense, Impairments		0	$ 3,600,000	$ 210,000,000	4,000,000	$ 210,000,000		1,118,000,000
Remaining Impairment Loss		5,000,000,000
Long-term Line of Credit		1,800,000,000			1,800,000,000
Costs Not to Be Recovered, Alternate Merger Plan		2,300,000,000			$ 2,300,000,000
Estimated Percentage Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances					14.00%
SCPSC Order Percentage Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances					5.00%
Long-term Debt, Current Maturities		18,000,000			$ 18,000,000			727,000,000
Short-term borrowings		314,000,000			314,000,000			350,000,000
Impairment Cost, Additional Liabilities, Post Merger					1,700,000,000
Transmission Assets related to BLRA Capital Costs		376,000,000			376,000,000
Impairment Cost, Additional Liabilities, Post Merger Utility Plant Alternative Plan					86,000,000
Customer Fees, Refunds Payments, Additional Liability Alternative Plan		1,880,000,000			1,880,000,000
Impairment Cost, Additional Liabilities, Post Merger Utility Plant					86,000,000
Monetization Settlement Exceeding Costs Incurred, Post Merger		1,000,000,000			1,000,000,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery					0.035
Guarantee Settlement Receipts					2,200,000,000
Asset Impairment Charges					4,000,000	210,000,000
Monetization Settlement Exceeding Costs Incurred					1,997,000,000
Estimate of aggregate amount of subcontractor and vendor liens filed					290,000,000
Estimated Litigation Liability		75,000,000			75,000,000
Operating Leases, Future Minimum Payments Due		9,000,000			9,000,000
Summer Station Unit 2 and Unit 3 [Domain]
Commitments and contingencies
Customer Refundable Fees, Refund Payments, Post Merger					1,300,000,000
Customer Refundable Fees, Alternative Plan					1,910,000,000
Customer Refundable Fees, Alternative Plan over 20 yrs					1,000,000,000
Customer Credits, Alternative Plan over 10 yrs					880,000,000
Debt Instrument, Periodic Payment, Interest					335,000,000
Short-term borrowings		314,000,000			314,000,000
Impairment Cost, Additional Liabilities, Post Merger					800,000,000
Unrecovered Nuclear Project Costs		4,140,000,000			4,140,000,000
Impairment Cost, Additional Liabilities, Post Merger Alternative Plan					1,368,000,000
SCEG
Commitments and contingencies
Regulatory Request to Lower Revenues					2,100,000,000
Utilities Operating Expense, Impairments				$ 210,000,000	4,000,000	210,000,000
Long-term Line of Credit		1,200,000,000			1,200,000,000
Long-term Debt, Current Maturities		14,000,000			14,000,000			723,000,000
Short-term borrowings		173,000,000			173,000,000			$ 252,000,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery					1,300,000
Guarantee Settlement Receipts					1,200,000,000
Asset Impairment Charges					4,000,000	$ 210,000,000
Monetization Settlement Exceeding Costs Incurred					1,098,000,000
Estimate of aggregate amount of subcontractor and vendor liens filed					33,000,000
Operating Leases, Future Minimum Payments Due		3,000,000			3,000,000
Nuclear Insurance
Maximum liability assessment per reactor for each nuclear incident					127,300,000
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					13,100,000,000
Maximum Federal Limit on Public Liability Claims Per Reactor for Each Year					18,900,000
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3					84,800,000
Maximum Federal Limit on Public Liability Claims Per Incident for Each Year					$ 12,600,000
Inflation adjustment period for nuclear insurance					5
NEIL Maximum Insurance Coverage To Nuclear Facility For Property Damage And Outage Costs From Non-Nuclear Event					$ 2,330,000,000
NEIL Maximum Insurance Coverage of Accidental Property Damage		2,750,000,000			2,750,000,000
EMANI Maximum Retrospective Premium Assessment					2,000,000
EMANI Maximum Insurance Coverage for Summer Station Unit 1 For Property Damage And Outage Costs From Non-Nuclear Event					415,000,000
NEIL Maximum Prosepective Insurance Premium Per Nuclear Incident					23,400,000
NEIL Maximum Insurance Coverage to Nuclear Facility for Property Damage and Outage Costs		2,750,000,000			2,750,000,000
Environmental
Environmental Remediation Costs Recognized in Regulatory Assets		$ 23,600,000			$ 23,600,000
Number of MGP decommissioned sites that contain residues of byproduct chemicals		4			4
Number Of States Required To Reduce Emissions Under CSAPR		28			28
Site Contingency MGP Estimated Environmental Remediation Costs					$ 9,600,000
Environmental Exit Costs, Reasonably Possible Additional Loss					8,000,000
SCEG | SCEG
Commitments and contingencies
Debt Instrument, Periodic Payment, Interest					255,000,000
Short-term borrowings		$ 173,000,000			173,000,000
Summer Station Unit 2 and Unit 3 [Domain]
Commitments and contingencies
Transmission Assets related to BLRA Capital Costs		$ 365,000,000			365,000,000
Estimate of aggregate amount of subcontractor and vendor liens filed					$ 60,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share		55.00%			55.00%
Summer Station Unit 2 and Unit 3 [Domain]
Commitments and contingencies
Impairment Cost, Additional Liabilities, Post Merger, Net of Tax	$ 1,000,000,000						$ 1,000,000,000
Impairment Cost, Additional Liabilities, Post Merger Alternate Plan							$ 2,300,000,000

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SEGMENT OF BUSINESS INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Electric Regulated Revenue	$ 669			$ 786			$ 1,767	$ 2,042
Revenues	0			0			0	0
Net Income (Loss) Available to Common Stockholders, Basic	67	$ 8	$ 169	34	$ 121	$ 171	244	326
Operating Income	183			122			475	693
Regulated Operating Revenue, Gas	122			123			631	584
Regulated and Unregulated Operating Revenue	926			1,076			2,948	3,249
Segment Assets	18,816						18,816		$ 18,739
Electric Operations
Segment Reporting Information [Line Items]
Electric Regulated Revenue				786				2,042
Revenues	0			1			3	4
Operating Income	217			127			396	555
Segment Assets	12,046						12,046		11,979
Gas Distribution
Segment Reporting Information [Line Items]
Revenues	0			0			1	1
Operating Income	(10)			(7)			107	110
Regulated and Unregulated Operating Revenue	122			123			631	584
Segment Assets	3,384						3,384		3,259
Gas Marketing [Member]
Segment Reporting Information [Line Items]
Revenues	35			35			95	93
Net Income (Loss) Available to Common Stockholders, Basic	1			1			21	17
Regulated and Unregulated Operating Revenue	135			167			550	623
Segment Assets	204						204		230
All Other [member]
Segment Reporting Information [Line Items]
Revenues	124			90			347	286
Net Income (Loss) Available to Common Stockholders, Basic	(30)			(7)			(79)	(14)
Operating Income	0			0			0	0
Regulated and Unregulated Operating Revenue	0			0			0	0
Segment Assets	1,071						1,071		1,042
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Revenues	(159)			(126)			(446)	(384)
Net Income (Loss) Available to Common Stockholders, Basic	96			40			302	323
Operating Income	(24)			2			(28)	28
Regulated and Unregulated Operating Revenue	0			0			0	0
Segment Assets	2,111						2,111		2,229
SCEG
Segment Reporting Information [Line Items]
Electric Regulated Revenue	669			786			1,767	2,042
Operating Income	212			124			440	597
Regulated Operating Revenue, Gas	69			69			303	284
Net Income (Loss) Attributable to Parent	98			39			248	270
Regulated Operating Revenue	739			856			2,074	2,331
Segment Assets	16,129						16,129		15,946
SCEG | Electric Operations
Segment Reporting Information [Line Items]
Electric Regulated Revenue				787				2,046
Operating Income	216			126			396	555
Regulated Operating Revenue	670						1,770
Segment Assets	12,046						12,046		11,979
SCEG | Gas Distribution
Segment Reporting Information [Line Items]
Operating Income	(4)			(2)			44	42
Regulated and Unregulated Operating Revenue				69			304	285
Regulated Operating Revenue	69						303
Segment Assets	909						909		869
SCEG | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Operating Income	0			0			0	0
Regulated and Unregulated Operating Revenue	0			0			0	0
Net Income (Loss) Attributable to Parent	98			$ 39			248	$ 270
Segment Assets	$ 3,174						$ 3,174		$ 3,098

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AFFILIATED TRANSACTIONS (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Related Party Transaction [Line Items]
Advances to Affiliate	$ 71,000,000		$ 71,000,000
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Due from (to) Related Party	$ 8,500,000		$ 8,500,000		$ 4,900,000
Equity Method Investment, Ownership Percentage	40.00%		40.00%
Related Party Transaction, Purchases from Related Party	$ 45,200,000	$ 47,500,000	$ 122,500,000	$ 144,900,000
Sales to Affiliates	44,900,000	47,200,000	121,800,000	144,000,000
Due to Related Parties	8,500,000		8,500,000		4,900,000
Energy Marketing [Member]
Related Party Transaction [Line Items]
Due to Affiliate, Current	10,600,000		10,600,000		10,000,000
Related Party Transaction, Purchases from Related Party	35,000	35,300,000	95,000,000	93,400,000
SCANA Services [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	72,900,000	$ 78,100,000	208,300,000	$ 233,600,000
Accounts Payable, Related Parties, Current	42,800,000		42,800,000		42,000,000
SCEG
Related Party Transaction [Line Items]
Due to Affiliate, Current	259,000,000		259,000,000		102,000,000
Due from Affiliate, Current	$ 186,000,000		$ 186,000,000		$ 32,000,000

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OTHER INCOME (EXPENSE), NET Other Income (Expense) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue from Contract with Customer, Including Assessed Tax	$ 4		$ 14
Other income	8	$ 28	144	$ 61
Other Nonoperating Expense	(14)	(9)	(34)	(33)
Public Utilities, Allowance for Funds Used During Construction, Additions	5	0	12	17
Other Nonoperating Income (Expense)	3	19	136	45
SCEG
Revenue from Contract with Customer, Including Assessed Tax	1		4	0
Other income	5	21	135	36
Other Nonoperating Expense	(10)	(7)	(22)	(23)
Public Utilities, Allowance for Funds Used During Construction, Additions	3	(3)	7	13
Other Nonoperating Income (Expense)	$ (1)	$ 11	124	$ 26
Other Income [Member] | Interest Rate Contract | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income			$ 115