Scana 10-K 28 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 15, 2019	Jun. 30, 2018
Document Information [Line Items]
Entity Registrant Name	SCANA CORP
Entity Central Index Key	754,737
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Shell Company	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		100
Entity Public Float			$ 5,486,355,874
SCE&G
Document Information [Line Items]
Entity Registrant Name	SOUTH CAROLINA ELECTRIC & GAS CO
Entity Central Index Key	91,882
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,296,147

CONSOLIDATED BALANCE SHEETS

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

CONSOLIDATED BALANCE SHEETS (Pa

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

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenues:
Electric Regulated Revenue	$ 2,322	$ 2,659	$ 2,614
Regulated Operating Revenue, Gas	934	874	788
Gas-nonregulated	796	874	825
Regulated and Unregulated Operating Revenue	4,052	4,407	4,227
Utilities Operating Expense [Abstract]
Fuel used in electric generation	671	594	576
Purchased power	92	80	64
Utilities Operating Expense, Gas and Petroleum Purchased	1,128	1,156	1,054
Other operation and maintenance	835	728	741
Utilities Operating Expense, Maintenance and Operations, Affiliate	18.4
Utilities Operating Expense, Impairments	1,376	1,118
Depreciation and amortization	403	382	371
Other taxes	276	264	254
Utilities Operating Expense	4,781	4,322	3,060
Operating Income	(729)	85	1,167
Other Nonoperating Income (Expense)	173	47	41
Other Income (Expense):
Other income	180	79	64
Other expenses	(46)	(55)	(52)
Interest charges, net of allowance for borrowed funds used during construction	(384)	(363)	(342)
Allowance for equity funds used during construction	19	23	29
Total Other Expense	173	47	41
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(940)	(231)	866
Income Tax Expense (Benefit)	(412)	(112)	271
Income Available to Common Shareholders	$ (528)	$ (119)	$ 595
Earnings Per Share, Basic and Diluted	$ (3.70)	$ (0.83)	$ 4.16
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ (512)	$ (120)	$ 611
Weighted Average Common Shares Outstanding (millions)
Weighted Average Number of Shares Outstanding, Basic	143	143	143
SCE&G
Operating Revenues:
Electric Regulated Revenue	$ 2,322	$ 2,659	$ 2,614
Electric Domestic Regulated Revenues - Affiliate	5	5	5
Regulated Operating Revenue, Gas	434	405	366
Regulated Operating Revenue Gas, Affiliate	1	1	1
Regulated Operating Revenue	2,762	3,070	2,986
Utilities Operating Expense [Abstract]
Fuel used in electric generation	531	465	472
Utilities Operating Expense, Fuel Used, Affiliate	140	129	104
Purchased power	92	80	64
Utilities Operating Expense, Gas and Petroleum Purchased	239	206	174
Utilities Operating Expense, Gas and Petroleum Purchased, affiliate			9
Other operation and maintenance	449	417	403
Utilities Operating Expense, Maintenance and Operations, Affiliate	182	180	199
Utilities Operating Expense, Impairments	1,376	1,118
Depreciation and amortization	327	312	302
Other taxes	251	241	227
Utilities Operating Expense, Taxes, Affiliate	6	5	7
Utilities Operating Expense	3,593	3,153	1,961
Operating Income	(831)	(83)	1,025
Other Nonoperating Income (Expense)	129	28	19
Other Income (Expense):
Other income	141	45	29
Other expenses	(28)	(32)	(36)
Interest charges, net of allowance for borrowed funds used during construction	(303)	(288)	(270)
Allowance for equity funds used during construction	11	15	26
Total Other Expense	129	28	19
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	(1,005)	(343)	774
Income Tax Expense (Benefit)	(416)	(171)	248
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(589)	(172)	526
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent	1	(1)	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(588)	(173)	526
Net Income (Loss) Attributable to Noncontrolling Interest	25	13	13
Earnings Available to Common Shareholder	(613)	$ (185)	$ 513
Subsidiaries [Member] | SCE&G
Other Income (Expense):
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (589)

CONSOLIDATED STATEMENTS OF IN_2

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

CONSOLIDATED STATEMENTS OF COMP

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

CONSOLIDATED STATEMENTS OF CO_2

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

CONSOLIDATED STATEMENTS OF CASH

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

CONSOLIDATED STATEMENTS OF CA_2

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

CONSOLIDATED STATEMENTS OF COMM

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

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2018
Significant Accounting Policies
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization and Principles of Consolidation Effective January 1, 2019, SCANA became a wholly-owned subsidiary of Dominion Energy under the terms of the Merger Agreement. See additional discussion in Note 2 and Note 11. The Company SCANA, a South Carolina corporation, is a holding company created in 1984. The Company primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina, and the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia. The accompanying consolidated financial statements reflect the accounts of SCANA and the following wholly-owned subsidiaries. Regulated businesses Nonregulated businesses South Carolina Electric & Gas Company SCANA Energy Marketing, Inc. South Carolina Fuel Company, Inc. SCANA Services, Inc. South Carolina Generating Company, Inc. SCANA Corporate Security Services, Inc. Public Service Company of North Carolina, Incorporated SCANA Communications Holdings, Inc. SCANA reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. Discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. Consolidated SCE&G SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA. Consolidated SCE&G primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina. SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $500 million ) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. No estimate is made for legal costs expected to be incurred in connection with loss contingencies. Such costs are recorded when incurred. Utility Plant Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense. AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 7.7% for 2018, 5.6% for 2017, and 5.3% for 2016. Consolidated SCE&G calculated AFC using average composite rates of 7.0% for 2018, 3.9% for 2017, and 4.7% for 2016. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred. Provisions for depreciation and amortization are recorded using the straight-line method based on the estimated service lives of the various classes of property, and in most cases, include provisions for future cost of removal. The 2018 composite weighted average depreciation rates for utility plant by function were as follows: The Company Consolidated SCE&G Generation 2.61 % 2.61 % Transmission 2.47 % 2.74 % Distribution 2.48 % 2.41 % Storage 2.48 % 2.71 % General and other 5.64 % 3.18 % SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in Fuel used in electric generation and recovered through the fuel cost component of retail electric rates. Major Maintenance Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred. SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2018, and 2017, SCE&G incurred $16.3 million and $26.1 million , respectively, for turbine maintenance. Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 million annually for its portion of the nuclear refueling outages scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which SCE&G was responsible totaled $28.6 million in 2018 and $23.2 million in 2017. Goodwill The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company has tested goodwill for impairment annually as of January 1, unless indicators, events or circumstances required interim testing to be performed. The Company performed its test on January 1, 2019 and intends to test goodwill annually on April 1, effective April 1, 2019. Under current accounting guidance, the Company may perform a qualitative assessment of impairment. Based on this assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to make a quantitative estimate of the fair value of the reporting unit and to compare that amount to its carrying value. If the Company is required to make a quantitative assessment or if it chooses to do so without first performing a qualitative one, and if the quantitative assessment indicates a carrying value in excess of fair value, an impairment charge would be required. Any such charge would be treated as an operating expense. For each period presented, assets with a carrying value of $210 million for PSNC Energy (Gas Distribution segment), net of a writedown of $230 million taken in 2002, were classified as goodwill. The Company performed a quantitative assessment of goodwill in its evaluation as of January 1, 2019 and performed a qualitative assessment of goodwill in its evaluation as of January 1, 2018. No impairment of goodwill was required based on these evaluations. Nuclear Decommissioning Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $625.8 million , stated in 2018 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. Under SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ( $3.2 million pre-tax in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. The asset balance held in trust reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Unit 1 on an after-tax basis. Cash and Cash Equivalents Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds. At December 31, 2018, cash and cash equivalents at the Company and Consolidated SCE&G included approximately $115.3 million held in escrow pending consummation of the merger with Dominion Energy and final approval of a legal settlement in the SCE&G Ratepayer Case. As such, the Company and Consolidated SCE&G did not consider these amounts to be restricted at December 31, 2018. See Claims and Litigation in Note 11 for additional discussion. Receivables Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described in Note 3. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $217.5 million at December 31, 2018 and $220.9 million at December 31, 2017 for the Company. Unbilled revenues totaled $129.3 million at December 31, 2018 and $140.3 million at December 31, 2017 for Consolidated SCE&G. Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station. Inventories Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable. PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 46% and 39% of PSNC Energy’s natural gas inventory at December 31, 2018 and December 31, 2017, respectively, with a carrying value of $13.9 million and $11.5 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to customers. This agreement has been extended and expires October 31, 2020. Income Taxes SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 6 for a discussion of the impact of adjustments recorded in connection with enactment of the Tax Act. Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA for all periods presented. Also, under provisions of an income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions. Regulatory Assets and Regulatory Liabilities The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods that differ from those in which the costs would be charged to expense, or record revenues in periods that differ from those in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified on the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively. Debt Issuance Premiums, Discounts and Other Costs Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred credits or debits and are amortized over the term of the replacement debt, also as interest charges. Environmental An environmental assessment program is maintained to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred. Statement of Operations Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense). Revenue Recognition Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed. Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings. SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews. Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of operations. Earnings (Loss) Per Share The Company computes basic earnings (loss) per share by dividing net income (loss) by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings (loss) per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. New Accounting Matters Recently Adopted In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact or no significant impact on their respective financial statements except as indicated. • Goodwill impairment guidance, issued in January 2017, removed Step 2 of the goodwill impairment test. • Guidance for revenue arising from contracts with customers uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods were not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3. • The required presentation of net periodic pension and postretirement benefit costs has been changed to distinguish between service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees. Non-service cost components are now excluded from operating income. This guidance has been applied retrospectively for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017 and 2016. Increase (Decrease) Millions of dollars The Company Consolidated SCE&G Year Ended December 31 2017 2016 2017 2016 Other operation and maintenance $ (9 ) $ (14 ) $ (7 ) $ (12 ) Total Operating Expenses (9 ) (14 ) (7 ) (12 ) Operating Income 9 14 7 12 Other Income (Expense), Net (9 ) (14 ) (7 ) (12 ) In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost component, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs. Effective January 1, 2018, amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets. • Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things. • Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented. • Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented. Pending Adoption The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below. In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases currently classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged. The guidance is effective for the Company's and Consolidated SCE&G's interim and annual reporting periods beginning January 1, 2019. This revised accounting guidance will be adopted using a modified-retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Company and Consolidated SCE&G are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Company and Consolidated SCE&G will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. The Company and Consolidated SCE&G anticipate that the adoption of this guidance will result in approximately $30 million to $35 million and $15 million to $20 million , respectively, of offsetting right-of-use assets and liabilities added to their consolidated balance sheets for operating leases in effect at the adoption date. No material changes are expected to the Company's and Consolidated SCE&G's results of operations. In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 and do not expect it to have a significant impact on their respective financial statements. In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 on a prospective basis. Upon adoption, the Company and Consolidated SCE&G expect to record cumulative effect adjustments to retained earnings and AOCI in their statements of changes in common equity (in the amount of $8 million and $1 million at the Company and Consolidated SCE&G, respectively) and do not expect any other significant impact on their financial statements. The amounts to be reclassified reflect the impact of the reduction in the federal income tax rate arising from the Tax Act, and the related federal benefit of state income taxes, on the components of the Company’s and Consolidated SCE&G’s AOCI. In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. A modified-retrospective approach is required upon adoption, whereby a cumulative-effect adjustment to retained earnings is made as of the beginning of the first reporting period in which the guidance is effective. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements. In August 2018, the FASB issued accounting guidance to modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance must be applied retrospectively to all periods presented. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position.
SCE&G
Significant Accounting Policies
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization and Principles of Consolidation Effective January 1, 2019, SCANA became a wholly-owned subsidiary of Dominion Energy under the terms of the Merger Agreement. See additional discussion in Note 2 and Note 11. The Company SCANA, a South Carolina corporation, is a holding company created in 1984. The Company primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina, and the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia. The accompanying consolidated financial statements reflect the accounts of SCANA and the following wholly-owned subsidiaries. Regulated businesses Nonregulated businesses South Carolina Electric & Gas Company SCANA Energy Marketing, Inc. South Carolina Fuel Company, Inc. SCANA Services, Inc. South Carolina Generating Company, Inc. SCANA Corporate Security Services, Inc. Public Service Company of North Carolina, Incorporated SCANA Communications Holdings, Inc. SCANA reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. Discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. Consolidated SCE&G SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA. Consolidated SCE&G primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina. SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $500 million ) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. No estimate is made for legal costs expected to be incurred in connection with loss contingencies. Such costs are recorded when incurred. Utility Plant Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense. AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 7.7% for 2018, 5.6% for 2017, and 5.3% for 2016. Consolidated SCE&G calculated AFC using average composite rates of 7.0% for 2018, 3.9% for 2017, and 4.7% for 2016. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred. Provisions for depreciation and amortization are recorded using the straight-line method based on the estimated service lives of the various classes of property, and in most cases, include provisions for future cost of removal. The 2018 composite weighted average depreciation rates for utility plant by function were as follows: The Company Consolidated SCE&G Generation 2.61 % 2.61 % Transmission 2.47 % 2.74 % Distribution 2.48 % 2.41 % Storage 2.48 % 2.71 % General and other 5.64 % 3.18 % SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in Fuel used in electric generation and recovered through the fuel cost component of retail electric rates. Major Maintenance Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred. SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2018, and 2017, SCE&G incurred $16.3 million and $26.1 million , respectively, for turbine maintenance. Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 million annually for its portion of the nuclear refueling outages scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which SCE&G was responsible totaled $28.6 million in 2018 and $23.2 million in 2017. Goodwill The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company has tested goodwill for impairment annually as of January 1, unless indicators, events or circumstances required interim testing to be performed. The Company performed its test on January 1, 2019 and intends to test goodwill annually on April 1, effective April 1, 2019. Under current accounting guidance, the Company may perform a qualitative assessment of impairment. Based on this assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to make a quantitative estimate of the fair value of the reporting unit and to compare that amount to its carrying value. If the Company is required to make a quantitative assessment or if it chooses to do so without first performing a qualitative one, and if the quantitative assessment indicates a carrying value in excess of fair value, an impairment charge would be required. Any such charge would be treated as an operating expense. For each period presented, assets with a carrying value of $210 million for PSNC Energy (Gas Distribution segment), net of a writedown of $230 million taken in 2002, were classified as goodwill. The Company performed a quantitative assessment of goodwill in its evaluation as of January 1, 2019 and performed a qualitative assessment of goodwill in its evaluation as of January 1, 2018. No impairment of goodwill was required based on these evaluations. Nuclear Decommissioning Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $625.8 million , stated in 2018 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. Under SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ( $3.2 million pre-tax in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. The asset balance held in trust reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Unit 1 on an after-tax basis. Cash and Cash Equivalents Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds. At December 31, 2018, cash and cash equivalents at the Company and Consolidated SCE&G included approximately $115.3 million held in escrow pending consummation of the merger with Dominion Energy and final approval of a legal settlement in the SCE&G Ratepayer Case. As such, the Company and Consolidated SCE&G did not consider these amounts to be restricted at December 31, 2018. See Claims and Litigation in Note 11 for additional discussion. Receivables Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described in Note 3. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $217.5 million at December 31, 2018 and $220.9 million at December 31, 2017 for the Company. Unbilled revenues totaled $129.3 million at December 31, 2018 and $140.3 million at December 31, 2017 for Consolidated SCE&G. Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station. Inventories Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable. PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 46% and 39% of PSNC Energy’s natural gas inventory at December 31, 2018 and December 31, 2017, respectively, with a carrying value of $13.9 million and $11.5 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to customers. This agreement has been extended and expires October 31, 2020. Income Taxes SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 6 for a discussion of the impact of adjustments recorded in connection with enactment of the Tax Act. Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA for all periods presented. Also, under provisions of an income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions. Regulatory Assets and Regulatory Liabilities The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods that differ from those in which the costs would be charged to expense, or record revenues in periods that differ from those in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified on the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively. Debt Issuance Premiums, Discounts and Other Costs Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred credits or debits and are amortized over the term of the replacement debt, also as interest charges. Environmental An environmental assessment program is maintained to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred. Statement of Operations Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense). Revenue Recognition Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed. Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings. SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews. Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of operations. Earnings (Loss) Per Share The Company computes basic earnings (loss) per share by dividing net income (loss) by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings (loss) per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. New Accounting Matters Recently Adopted In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact or no significant impact on their respective financial statements except as indicated. • Goodwill impairment guidance, issued in January 2017, removed Step 2 of the goodwill impairment test. • Guidance for revenue arising from contracts with customers uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods were not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3. • The required presentation of net periodic pension and postretirement benefit costs has been changed to distinguish between service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees. Non-service cost components are now excluded from operating income. This guidance has been applied retrospectively for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017 and 2016. Increase (Decrease) Millions of dollars The Company Consolidated SCE&G Year Ended December 31 2017 2016 2017 2016 Other operation and maintenance $ (9 ) $ (14 ) $ (7 ) $ (12 ) Total Operating Expenses (9 ) (14 ) (7 ) (12 ) Operating Income 9 14 7 12 Other Income (Expense), Net (9 ) (14 ) (7 ) (12 ) In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost component, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs. Effective January 1, 2018, amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets. • Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things. • Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented. • Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented. Pending Adoption The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below. In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases currently classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged. The guidance is effective for the Company's and Consolidated SCE&G's interim and annual reporting periods beginning January 1, 2019. This revised accounting guidance will be adopted using a modified-retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Company and Consolidated SCE&G are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Company and Consolidated SCE&G will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. The Company and Consolidated SCE&G anticipate that the adoption of this guidance will result in approximately $30 million to $35 million and $15 million to $20 million , respectively, of offsetting right-of-use assets and liabilities added to their consolidated balance sheets for operating leases in effect at the adoption date. No material changes are expected to the Company's and Consolidated SCE&G's results of operations. In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 and do not expect it to have a significant impact on their respective financial statements. In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 on a prospective basis. Upon adoption, the Company and Consolidated SCE&G expect to record cumulative effect adjustments to retained earnings and AOCI in their statements of changes in common equity (in the amount of $8 million and $1 million at the Company and Consolidated SCE&G, respectively) and do not expect any other significant impact on their financial statements. The amounts to be reclassified reflect the impact of the reduction in the federal income tax rate arising from the Tax Act, and the related federal benefit of state income taxes, on the components of the Company’s and Consolidated SCE&G’s AOCI. In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. A modified-retrospective approach is required upon adoption, whereby a cumulative-effect adjustment to retained earnings is made as of the beginning of the first reporting period in which the guidance is effective. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements. In August 2018, the FASB issued accounting guidance to modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance must be applied retrospectively to all periods presented. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position.

RATE AND OTHER REGULATORY MATTE

RATE AND OTHER REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2018
Rate Matters [Line Items]
Schedule of Regulatory Assets and Liabilities [Text Block]	RATE AND OTHER REGULATORY MATTERS Rate Matters Tax Act Regulatory Proceedings The Tax Act lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the SCPSC and NCUC have required SCE&G and PSNC Energy to track and defer impacts related to the Tax Act arising from customer rates in 2018 as subject to refund. In addition, as further discussed under Regulatory Assets and Regulatory Liabilities below, certain accumulated deferred income taxes contained within regulatory liabilities represent excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act. Certain of these amounts are protected under normalization rules and will be amortized over the remaining regulatory life of the property, and certain of these amounts will be amortized to the benefit of customers, as instructed by regulators, which ranges from 5 years to 50 years. As of December 31, 2018, SCE&G has recorded approximately $73.7 million as Revenue subject to refund and approximately $3.7 million as Regulatory liabilities on the consolidated balance sheet for the Company and Consolidated SCE&G, and PSNC Energy has recorded approximately $15.4 million of such deferrals within Regulatory liabilities on the consolidated balance sheet for the Company. These amounts were collected through customer rates in 2018 and include the accrual of estimated carrying costs. In addition, the Company and Consolidated SCE&G have recorded amounts related to excess deferred income taxes arising from the Tax Act within Regulatory liabilities. For a discussion of related actions taken by the SCPSC and NCUC, see Electric - Other, Gas - SCE&G, and Gas - PSNC Energy below. Electric - BLRA and Merger Approval Order In 2016, the SCPSC approved revised rates under the BLRA to incorporate financing cost of SCE&G's incremental construction work in progress incurred for the Nuclear Project. Rate adjustments resulted in approximately $64.4 million in additional revenue on an annual basis and were effective for bills rendered on and after November 27, 2016. Such rate adjustments were based on SCE&G's updated cost of debt and capital structure and on an allowed ROE of 10.5% applied prospectively for purposes of calculating revised rates under the BLRA on and after January 1, 2016. No revised rates filings were pursued after this 2016 approval. In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for Unit 2 and Unit 3 which had been developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, the ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option included in that October 2015 contract amendment. By order dated February 28, 2017, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement, and that denial was not appealed. On July 2 and 3, 2018, the SCPSC issued orders implementing a legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from customers under the BLRA. These orders reduced the portion of SCE&G's retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer's bill to approximately 3.2% , which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. These lower rates remained in effect until February 2019 pursuant to the Merger Approval Order. On December 21, 2018, the SCPSC issued the Merger Approval Order. The order adopted Dominion Energy's Plan-B Levelized Customer Benefits Plan whereby the average bill for an SCE&G residential electric customer would approximate that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the SCPSC retroactive to April 1, 2018. The Merger Approval Order established an allowed ROE of 9.9% on unrecovered Nuclear Project costs, and resulted in the following findings and conditions: • No capital costs related to the Nuclear Project incurred after March 12, 2015 will be recoverable by SCE&G. • SCE&G will provide refunds and restitution to customers from prior years' revenues totaling an aggregate $2.039 billion , comprised of $1.032 billion to be credited to customers over 20 years and $1.007 billion credited to customers over approximately 11 years. • Except for rate adjustments for fuel and environmental costs, demand side management costs, and other rates routinely adjusted on an annual or biannual basis, SCE&G will freeze retail electric base rates at current levels until January 1, 2021. • SCE&G's natural gas customers will receive a refund totaling $2.45 million in 2019, 2020 and 2021 combined. • Corporate giving will increase above historical levels by $1 million per year for at least five years. • SCE&G will not seek to pass on to ratepayers its initial capital investment in CEC, a 540-MW combined-cycle natural gas-fired generating facility, and will not seek to pass on to ratepayers any acquisition premium costs, transition costs, or transaction cost associated with the merger. Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. On February 12, 2019, the SCPSC issued a ruling (1) finding that SCE&G was imprudent in its actions by not disclosing material information to the ORS and the SCPSC, and (2) denying the petitions for rehearing or reconsideration as to other issues raised in the various petitions. The Merger Approval Order and the ruling are subject to appeal by various parties. The Company and Consolidated SCE&G cannot predict the outcome of these matters. See also Note 11. Electric - Cost of Fuel SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. By order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G reduced the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G also began to recover projected DER program costs of approximately $6.9 million beginning with the first billing cycle of May 2016. By order dated April 27, 2017, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component to produce a projected under recovery of $61.0 million over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately $16.5 million . Additionally, deferral of carrying costs would be allowed for base fuel component under-collected balances as they occurred. On April 25, 2018, the SCPSC approved SCE&G’s proposal to increase the total fuel cost component of retail electric rates. Specifically, the SCPSC approved an increase to certain environmental, avoided capacity and DER program cost components and SCE&G’s agreement to maintain its base fuel component to produce a projected under-recovered balance of approximately $1.3 million at the end of the 12-month period beginning with the first billing cycle of May 2018. This projected under-recovered balance includes the effect of offsetting fuel cost recovery with gains realized from the settlement of certain interest rate derivatives in 2018. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2018, projected DER program costs of approximately $29.3 million . Petitions for rehearing and reconsideration were filed by various parties, and on October 30, 2018, the SCPSC issued an order granting one such petition related to SCE&G supplying certain information as in previous years. The other petitions were denied, and certain parties have appealed the decision to deny their petitions to the South Carolina Supreme Court. These appeals primarily relate to avoided cost rates that SCE&G is required to pay to solar energy developers, and these appeals are pending. The Company and Consolidated SCE&G cannot predict the outcome of these matters. On February 8, 2019, SCE&G filed with the SCPSC a proposal to decrease the total fuel cost component of retail electric rates. In the filing, SCE&G proposed to maintain its base fuel component at the current level to produce a projected under-recovered balance of approximately $35.4 million at the end of the 12-month period beginning with the first billing cycle of May 2019, and requested carrying costs for any base fuel under-collected balances, should they occur. SCE&G also proposed to reduce its variable environmental component and maintain or reduce its DER components. A public hearing on this matter is scheduled to be held in April 2019. Electric - Base Rates Pursuant to an SCPSC order, SCE&G removed from rate base certain deferred income tax assets arising from capital expenditures related to Unit 2 and Unit 3 and accrued carrying costs on those amounts during periods in which they were not included in rate base. Such carrying costs were determined at SCE&G’s weighted average long-term debt borrowing rate and were recorded as a regulatory asset and other income. Carrying costs totaled $18.8 million during 2017 and $14.0 million during 2016. As part of the Nuclear Project impairment loss described in Note 11, accumulated carrying costs related to these deferred income tax assets totaling $51.0 million were written off in 2017. Electric - Other The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues (both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below: Year Effective Amount 2018 First billing cycle of May $33.0 million 2017 First billing cycle of May $37.0 million 2016 First billing cycle of May $37.6 million In January 2019, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved the filing would allow recovery of approximately $30.3 million of costs and net lost revenues associated with DSM Programs, along with an incentive to invest in such programs. SCE&G utilizes a pension costs rider approved by the SCPSC which is designed to allow recovery of projected pension costs, including under-collected balances or net of over-collected balances, as applicable. The rider is typically reviewed for adjustment every 12 months with any resulting increase or decrease going into effect beginning with the first billing cycle in May. In 2017, this rider was adjusted to decrease annual revenue by approximately $11.9 million . No adjustment was made in 2018. No adjustment has been proposed in 2019. As part of the Merger Approval Order, the SCPSC approved refunds of approximately $100 million by SCE&G for the impact of the lower federal tax rate resulting from the Tax Act. The refunds include amounts which had been collected through customer rates in 2018 and January 2019 and also include the effects of the amortization of certain excess deferred taxes during the same period. At December 31, 2018, amounts to be refunded to electric customers totaled approximately $91 million, and were comprised of approximately $70 million included within Revenue subject to refund and approximately $21 million included within Regulatory liabilities. These refunds have been included in bills rendered on and after the first billing cycle of February 2019. In addition, the SCPSC approved the implementation of a tax rider whereby amounts collected though customer rates effectively would be reduced and excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act will be amortized to the benefit of customers. This tax rider is expected to reduce base rates to customers by approximately $67 million in each of 2019 and 2020, effective with the first billing cycle of February 2019. Unamortized excess deferred income taxes that remain at the end of 2020 will be considered in future rate proceedings. Gas - SCE&G The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: Year Action Amount 2018 4.6 % Decrease $19.7 million * 2017 2.2 % Increase $8.6 million 2016 1.2 % Increase $4.1 million * Includes the impact of the lower federal corporate tax rate resulting from the Tax Act. The SCPSC also approved revised rate schedules for natural gas service that include a rider to refund certain amounts previously collected from customers for SCE&G's income taxes. SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. Gas - PSNC Energy PSNC Energy's Rider D rate mechanism allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales. PSNC Energy establishes rates using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption. On October 28, 2016, the NCUC granted PSNC Energy a net annual increase of approximately $19.1 million , or 4.39% , in rates and charges to customers, and set PSNC Energy's authorized ROE at 9.7% . In addition, the NCUC has authorized PSNC Energy to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy files biannual applications to adjust its rates for this purpose. The NCUC has approved those applications for the incremental increase to annual revenue requirements, as follows: Rates Effective 2018 2017 March 1 $14.7 million $1.9 million September 1 $1.1 million $0.7 million On February 15, 2019, PSNC Energy submitted its biannual application to adjust rates associated with its pipeline integrity tracker. As approved by the NCUC, the filing increases PSNC Energy's allowed recovery by approximately $1.7 million effective March 1, 2019. On November 19, 2018, the NCUC issued an order approving the SCANA Combination subject to a stipulation agreement with the following provisions: (1) customer bill credits of $1.25 million in each of January 2019, 2020 and 2021; (2) a rate moratorium until November 1, 2021 other than for rate adjustments pursuant to the CUT, the Integrity Management Tracker and the PGA; and (3) an agreement that direct merger-related expenses will be excluded from PSNC Energy regulated expenses for ratemaking purposes. On December 17, 2018, the NCUC issued an order approving PSNC Energy's proposed adjustments to customer rates to reflect the reduction in the federal corporate tax rate arising from the Tax Act. These lower rates became effective for service rendered on and after January 1, 2019. The impact of the lower tax rate collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC Energy's next general rate case proceeding or in three years, whichever is sooner (i.e., no later than October 25, 2021). The reduction in the federal corporate tax rate and its impact on PSNC Energy's various rate riders will be addressed in future proceedings related to those riders. Regulatory Assets and Regulatory Liabilities Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises. As a result, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Except for certain unrecovered nuclear project costs and other unrecovered plant, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities. The Company Consolidated SCE&G December 31, December 31, Millions of dollars 2018 2017 2018 2017 Regulatory Assets: Unrecovered Nuclear Project costs $ 2,768 3,976 $ 2,768 3,976 AROs and related funding 406 434 380 410 Deferred employee benefit plan costs 302 305 272 273 Deferred losses on interest rate derivatives 448 456 448 456 Other unrecovered plant 93 105 93 105 DSM Programs 65 59 65 59 Pipeline integrity management costs 73 51 9 8 Environmental remediation costs 27 30 24 25 Deferred storm damage costs 35 24 35 24 Deferred transmission operating costs 15 — 15 — Other 148 140 147 140 Total Regulatory Assets $ 4,380 $ 5,580 $ 4,256 $ 5,476 Regulatory Liabilities: Monetization of guaranty settlement $ 1,098 1,095 $ 1,098 1,095 Accumulated deferred income taxes 814 1,076 659 914 Asset removal costs 779 757 541 527 Deferred gains on interest rate derivatives 77 131 77 131 Other 21 — 5 — Total Regulatory Liabilities $ 2,789 $ 3,059 $ 2,380 $ 2,667 The carrying amount of the regulatory asset for unrecovered Nuclear Project costs has been recorded based on such amount not being probable of loss in accordance with the accounting guidance on abandonments, whereas the other regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under applicable GAAP for regulated operations. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include certain costs which have not been specifically approved for recovery by one of these regulatory agencies, including deferred transmission operating costs that are the subject of regulatory proceedings as further discussed above and in Note 11. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts embodied in rate orders or applicable state law. The costs are currently not being recovered but are expected to be recovered through rates in future periods. In the future, as a result of deregulation, changes in state law, other changes in the regulatory environment or changes in accounting requirements or other adverse legislative or regulatory developments, the Company or Consolidated SCE&G could be required to write off all or a portion of its regulatory assets and liabilities. Such an event could have a material effect on the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded. Unrecovered Nuclear Project costs represents expenditures by SCE&G that have been reclassified from construction work in progress and, pursuant to the Merger Approval Order and subsequent SCANA Combination, are to be recovered over a 20-year period ending in 2039. In 2017, such amounts were recorded pending a final determination by the SCPSC. See Note 11 for a discussion of impairment charges related to the Nuclear Project. AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 106 years. Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. SCE&G recovers deferred pension costs through utility rates of approximately $2 million annually for electric operations, which will end in 2044, and approximately $1 million annually for gas operations, which will end in 2027. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees up to approximately 11 years. Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. Such deferred amounts are expected to be amortized to interest expense over the lives of the underlying debt which, with respect to (i), is through 2043, and with respect to (ii), is through 2065. Other unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return. DSM Programs represent SCE&G's deferred costs associated with electric demand reduction programs, and such deferred costs are being recovered over approximately five years through an approved rate rider. Pipeline integrity management costs represent operating costs expended to comply with federal regulatory requirements related to natural gas pipelines. PSNC Energy is recovering costs totaling $4.1 million annually through 2021. PSNC Energy is continuing to defer pipeline integrity costs, and as of December 31, 2018 costs of $51.3 million have been deferred pending future approval of rate recovery. Effective November 2018, SCE&G began amortizing deferred pipeline integrity costs at an annual rate of $3.2 million . Prior to November 2018, such costs were amortized at an annual rate of $1.9 million annually. Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy. SCE&G's remediation costs are expected to be recovered over periods of up to approximately 16 years, and PSNC Energy's remediation costs of $3.8 million are being recovered over a period that will end in 2021. Deferred storm damage costs represent storm restoration costs for which SCE&G expects to receive future recovery through customer rates. Deferred transmission operating costs include deferred depreciation and property taxes associated with certain transmission assets for which SCE&G expects recovery from customers through future rates. See also Note 11. Various other regulatory assets are expected to be recovered through rates over varying periods through 2047 . Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement. In accordance with the Merger Approval Order, this balance, net of amounts that may be required to satisfy liens described in Note 11, will be refunded to electric customers over a period ending in 2039. Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the Tax Act (certain of which are protected under normalization rules and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over prescribed periods as instructed by regulators) and (ii) deferred income taxes arising from investment tax credits, offset by (iii) deferred income taxes that arise from utility operations that have not been included in customer rates (a portion of which relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 85 years). See also Note 6. Asset removal costs represent estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.
SCE&G
Rate Matters [Line Items]
Schedule of Regulatory Assets and Liabilities [Text Block]	RATE AND OTHER REGULATORY MATTERS Rate Matters Tax Act Regulatory Proceedings The Tax Act lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the SCPSC and NCUC have required SCE&G and PSNC Energy to track and defer impacts related to the Tax Act arising from customer rates in 2018 as subject to refund. In addition, as further discussed under Regulatory Assets and Regulatory Liabilities below, certain accumulated deferred income taxes contained within regulatory liabilities represent excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act. Certain of these amounts are protected under normalization rules and will be amortized over the remaining regulatory life of the property, and certain of these amounts will be amortized to the benefit of customers, as instructed by regulators, which ranges from 5 years to 50 years. As of December 31, 2018, SCE&G has recorded approximately $73.7 million as Revenue subject to refund and approximately $3.7 million as Regulatory liabilities on the consolidated balance sheet for the Company and Consolidated SCE&G, and PSNC Energy has recorded approximately $15.4 million of such deferrals within Regulatory liabilities on the consolidated balance sheet for the Company. These amounts were collected through customer rates in 2018 and include the accrual of estimated carrying costs. In addition, the Company and Consolidated SCE&G have recorded amounts related to excess deferred income taxes arising from the Tax Act within Regulatory liabilities. For a discussion of related actions taken by the SCPSC and NCUC, see Electric - Other, Gas - SCE&G, and Gas - PSNC Energy below. Electric - BLRA and Merger Approval Order In 2016, the SCPSC approved revised rates under the BLRA to incorporate financing cost of SCE&G's incremental construction work in progress incurred for the Nuclear Project. Rate adjustments resulted in approximately $64.4 million in additional revenue on an annual basis and were effective for bills rendered on and after November 27, 2016. Such rate adjustments were based on SCE&G's updated cost of debt and capital structure and on an allowed ROE of 10.5% applied prospectively for purposes of calculating revised rates under the BLRA on and after January 1, 2016. No revised rates filings were pursued after this 2016 approval. In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for Unit 2 and Unit 3 which had been developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, the ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option included in that October 2015 contract amendment. By order dated February 28, 2017, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement, and that denial was not appealed. On July 2 and 3, 2018, the SCPSC issued orders implementing a legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from customers under the BLRA. These orders reduced the portion of SCE&G's retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer's bill to approximately 3.2% , which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. These lower rates remained in effect until February 2019 pursuant to the Merger Approval Order. On December 21, 2018, the SCPSC issued the Merger Approval Order. The order adopted Dominion Energy's Plan-B Levelized Customer Benefits Plan whereby the average bill for an SCE&G residential electric customer would approximate that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the SCPSC retroactive to April 1, 2018. The Merger Approval Order established an allowed ROE of 9.9% on unrecovered Nuclear Project costs, and resulted in the following findings and conditions: • No capital costs related to the Nuclear Project incurred after March 12, 2015 will be recoverable by SCE&G. • SCE&G will provide refunds and restitution to customers from prior years' revenues totaling an aggregate $2.039 billion , comprised of $1.032 billion to be credited to customers over 20 years and $1.007 billion credited to customers over approximately 11 years. • Except for rate adjustments for fuel and environmental costs, demand side management costs, and other rates routinely adjusted on an annual or biannual basis, SCE&G will freeze retail electric base rates at current levels until January 1, 2021. • SCE&G's natural gas customers will receive a refund totaling $2.45 million in 2019, 2020 and 2021 combined. • Corporate giving will increase above historical levels by $1 million per year for at least five years. • SCE&G will not seek to pass on to ratepayers its initial capital investment in CEC, a 540-MW combined-cycle natural gas-fired generating facility, and will not seek to pass on to ratepayers any acquisition premium costs, transition costs, or transaction cost associated with the merger. Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. On February 12, 2019, the SCPSC issued a ruling (1) finding that SCE&G was imprudent in its actions by not disclosing material information to the ORS and the SCPSC, and (2) denying the petitions for rehearing or reconsideration as to other issues raised in the various petitions. The Merger Approval Order and the ruling are subject to appeal by various parties. The Company and Consolidated SCE&G cannot predict the outcome of these matters. See also Note 11. Electric - Cost of Fuel SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. By order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G reduced the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G also began to recover projected DER program costs of approximately $6.9 million beginning with the first billing cycle of May 2016. By order dated April 27, 2017, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component to produce a projected under recovery of $61.0 million over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately $16.5 million . Additionally, deferral of carrying costs would be allowed for base fuel component under-collected balances as they occurred. On April 25, 2018, the SCPSC approved SCE&G’s proposal to increase the total fuel cost component of retail electric rates. Specifically, the SCPSC approved an increase to certain environmental, avoided capacity and DER program cost components and SCE&G’s agreement to maintain its base fuel component to produce a projected under-recovered balance of approximately $1.3 million at the end of the 12-month period beginning with the first billing cycle of May 2018. This projected under-recovered balance includes the effect of offsetting fuel cost recovery with gains realized from the settlement of certain interest rate derivatives in 2018. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2018, projected DER program costs of approximately $29.3 million . Petitions for rehearing and reconsideration were filed by various parties, and on October 30, 2018, the SCPSC issued an order granting one such petition related to SCE&G supplying certain information as in previous years. The other petitions were denied, and certain parties have appealed the decision to deny their petitions to the South Carolina Supreme Court. These appeals primarily relate to avoided cost rates that SCE&G is required to pay to solar energy developers, and these appeals are pending. The Company and Consolidated SCE&G cannot predict the outcome of these matters. On February 8, 2019, SCE&G filed with the SCPSC a proposal to decrease the total fuel cost component of retail electric rates. In the filing, SCE&G proposed to maintain its base fuel component at the current level to produce a projected under-recovered balance of approximately $35.4 million at the end of the 12-month period beginning with the first billing cycle of May 2019, and requested carrying costs for any base fuel under-collected balances, should they occur. SCE&G also proposed to reduce its variable environmental component and maintain or reduce its DER components. A public hearing on this matter is scheduled to be held in April 2019. Electric - Base Rates Pursuant to an SCPSC order, SCE&G removed from rate base certain deferred income tax assets arising from capital expenditures related to Unit 2 and Unit 3 and accrued carrying costs on those amounts during periods in which they were not included in rate base. Such carrying costs were determined at SCE&G’s weighted average long-term debt borrowing rate and were recorded as a regulatory asset and other income. Carrying costs totaled $18.8 million during 2017 and $14.0 million during 2016. As part of the Nuclear Project impairment loss described in Note 11, accumulated carrying costs related to these deferred income tax assets totaling $51.0 million were written off in 2017. Electric - Other The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues (both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below: Year Effective Amount 2018 First billing cycle of May $33.0 million 2017 First billing cycle of May $37.0 million 2016 First billing cycle of May $37.6 million In January 2019, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved the filing would allow recovery of approximately $30.3 million of costs and net lost revenues associated with DSM Programs, along with an incentive to invest in such programs. SCE&G utilizes a pension costs rider approved by the SCPSC which is designed to allow recovery of projected pension costs, including under-collected balances or net of over-collected balances, as applicable. The rider is typically reviewed for adjustment every 12 months with any resulting increase or decrease going into effect beginning with the first billing cycle in May. In 2017, this rider was adjusted to decrease annual revenue by approximately $11.9 million . No adjustment was made in 2018. No adjustment has been proposed in 2019. As part of the Merger Approval Order, the SCPSC approved refunds of approximately $100 million by SCE&G for the impact of the lower federal tax rate resulting from the Tax Act. The refunds include amounts which had been collected through customer rates in 2018 and January 2019 and also include the effects of the amortization of certain excess deferred taxes during the same period. At December 31, 2018, amounts to be refunded to electric customers totaled approximately $91 million, and were comprised of approximately $70 million included within Revenue subject to refund and approximately $21 million included within Regulatory liabilities. These refunds have been included in bills rendered on and after the first billing cycle of February 2019. In addition, the SCPSC approved the implementation of a tax rider whereby amounts collected though customer rates effectively would be reduced and excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act will be amortized to the benefit of customers. This tax rider is expected to reduce base rates to customers by approximately $67 million in each of 2019 and 2020, effective with the first billing cycle of February 2019. Unamortized excess deferred income taxes that remain at the end of 2020 will be considered in future rate proceedings. Gas - SCE&G The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: Year Action Amount 2018 4.6 % Decrease $19.7 million * 2017 2.2 % Increase $8.6 million 2016 1.2 % Increase $4.1 million * Includes the impact of the lower federal corporate tax rate resulting from the Tax Act. The SCPSC also approved revised rate schedules for natural gas service that include a rider to refund certain amounts previously collected from customers for SCE&G's income taxes. SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. Gas - PSNC Energy PSNC Energy's Rider D rate mechanism allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales. PSNC Energy establishes rates using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption. On October 28, 2016, the NCUC granted PSNC Energy a net annual increase of approximately $19.1 million , or 4.39% , in rates and charges to customers, and set PSNC Energy's authorized ROE at 9.7% . In addition, the NCUC has authorized PSNC Energy to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy files biannual applications to adjust its rates for this purpose. The NCUC has approved those applications for the incremental increase to annual revenue requirements, as follows: Rates Effective 2018 2017 March 1 $14.7 million $1.9 million September 1 $1.1 million $0.7 million On February 15, 2019, PSNC Energy submitted its biannual application to adjust rates associated with its pipeline integrity tracker. As approved by the NCUC, the filing increases PSNC Energy's allowed recovery by approximately $1.7 million effective March 1, 2019. On November 19, 2018, the NCUC issued an order approving the SCANA Combination subject to a stipulation agreement with the following provisions: (1) customer bill credits of $1.25 million in each of January 2019, 2020 and 2021; (2) a rate moratorium until November 1, 2021 other than for rate adjustments pursuant to the CUT, the Integrity Management Tracker and the PGA; and (3) an agreement that direct merger-related expenses will be excluded from PSNC Energy regulated expenses for ratemaking purposes. On December 17, 2018, the NCUC issued an order approving PSNC Energy's proposed adjustments to customer rates to reflect the reduction in the federal corporate tax rate arising from the Tax Act. These lower rates became effective for service rendered on and after January 1, 2019. The impact of the lower tax rate collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC Energy's next general rate case proceeding or in three years, whichever is sooner (i.e., no later than October 25, 2021). The reduction in the federal corporate tax rate and its impact on PSNC Energy's various rate riders will be addressed in future proceedings related to those riders. Regulatory Assets and Regulatory Liabilities Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises. As a result, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Except for certain unrecovered nuclear project costs and other unrecovered plant, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities. The Company Consolidated SCE&G December 31, December 31, Millions of dollars 2018 2017 2018 2017 Regulatory Assets: Unrecovered Nuclear Project costs $ 2,768 3,976 $ 2,768 3,976 AROs and related funding 406 434 380 410 Deferred employee benefit plan costs 302 305 272 273 Deferred losses on interest rate derivatives 448 456 448 456 Other unrecovered plant 93 105 93 105 DSM Programs 65 59 65 59 Pipeline integrity management costs 73 51 9 8 Environmental remediation costs 27 30 24 25 Deferred storm damage costs 35 24 35 24 Deferred transmission operating costs 15 — 15 — Other 148 140 147 140 Total Regulatory Assets $ 4,380 $ 5,580 $ 4,256 $ 5,476 Regulatory Liabilities: Monetization of guaranty settlement $ 1,098 1,095 $ 1,098 1,095 Accumulated deferred income taxes 814 1,076 659 914 Asset removal costs 779 757 541 527 Deferred gains on interest rate derivatives 77 131 77 131 Other 21 — 5 — Total Regulatory Liabilities $ 2,789 $ 3,059 $ 2,380 $ 2,667 The carrying amount of the regulatory asset for unrecovered Nuclear Project costs has been recorded based on such amount not being probable of loss in accordance with the accounting guidance on abandonments, whereas the other regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under applicable GAAP for regulated operations. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include certain costs which have not been specifically approved for recovery by one of these regulatory agencies, including deferred transmission operating costs that are the subject of regulatory proceedings as further discussed above and in Note 11. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts embodied in rate orders or applicable state law. The costs are currently not being recovered but are expected to be recovered through rates in future periods. In the future, as a result of deregulation, changes in state law, other changes in the regulatory environment or changes in accounting requirements or other adverse legislative or regulatory developments, the Company or Consolidated SCE&G could be required to write off all or a portion of its regulatory assets and liabilities. Such an event could have a material effect on the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded. Unrecovered Nuclear Project costs represents expenditures by SCE&G that have been reclassified from construction work in progress and, pursuant to the Merger Approval Order and subsequent SCANA Combination, are to be recovered over a 20-year period ending in 2039. In 2017, such amounts were recorded pending a final determination by the SCPSC. See Note 11 for a discussion of impairment charges related to the Nuclear Project. AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 106 years. Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. SCE&G recovers deferred pension costs through utility rates of approximately $2 million annually for electric operations, which will end in 2044, and approximately $1 million annually for gas operations, which will end in 2027. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees up to approximately 11 years. Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. Such deferred amounts are expected to be amortized to interest expense over the lives of the underlying debt which, with respect to (i), is through 2043, and with respect to (ii), is through 2065. Other unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return. DSM Programs represent SCE&G's deferred costs associated with electric demand reduction programs, and such deferred costs are being recovered over approximately five years through an approved rate rider. Pipeline integrity management costs represent operating costs expended to comply with federal regulatory requirements related to natural gas pipelines. PSNC Energy is recovering costs totaling $4.1 million annually through 2021. PSNC Energy is continuing to defer pipeline integrity costs, and as of December 31, 2018 costs of $51.3 million have been deferred pending future approval of rate recovery. Effective November 2018, SCE&G began amortizing deferred pipeline integrity costs at an annual rate of $3.2 million . Prior to November 2018, such costs were amortized at an annual rate of $1.9 million annually. Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy. SCE&G's remediation costs are expected to be recovered over periods of up to approximately 16 years, and PSNC Energy's remediation costs of $3.8 million are being recovered over a period that will end in 2021. Deferred storm damage costs represent storm restoration costs for which SCE&G expects to receive future recovery through customer rates. Deferred transmission operating costs include deferred depreciation and property taxes associated with certain transmission assets for which SCE&G expects recovery from customers through future rates. See also Note 11. Various other regulatory assets are expected to be recovered through rates over varying periods through 2047 . Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement. In accordance with the Merger Approval Order, this balance, net of amounts that may be required to satisfy liens described in Note 11, will be refunded to electric customers over a period ending in 2039. Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the Tax Act (certain of which are protected under normalization rules and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over prescribed periods as instructed by regulators) and (ii) deferred income taxes arising from investment tax credits, offset by (iii) deferred income taxes that arise from utility operations that have not been included in customer rates (a portion of which relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 85 years). See also Note 6. Asset removal costs represent estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.

REVENUE RECOGNITION (Notes)

REVENUE RECOGNITION (Notes)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Text Block]	REVENUE RECOGNITION Identifying Revenue Streams and Related Performance Obligations Operating Revenues Operating revenues arise primarily from the sale and transmission of electricity and the sale and transportation of natural gas. Electric and Gas regulated revenues consist primarily of retail sales to residential, commercial and industrial customers under various tariff rates approved by state regulatory commissions. These tariff rates generally include charges for the energy consumed and a standard basic facilities or demand charge designed to recover certain fixed costs incurred to provide service to the customer. Tariff rates also include commission-approved regulatory mechanisms in the form of adjustments or riders, such as for weather normalization, fuel and environmental cost recovery, energy conservation programs, interruptible service and real time pricing provisions, among others. Electric revenues also include wholesale sales and transmission service, primarily to municipal customers and other service providers, under contracts or tariffs approved by the FERC. Gas nonregulated revenues arise from natural gas sales at market-based rates. Such sales to residential and certain commercial customers include charges for natural gas delivered, at either variable or fixed prices, together with any applicable customer service charges, charges originating from an interstate pipeline company, and other incidental charges. The Company has determined that its gas marketing subsidiary serves as an agent for distribution services provided by a nonaffiliated company in its retail market. Accordingly, the pass-through charges to customers related to such services are not considered revenues. Sales to other commercial and to industrial customers include commodity and transportation charges for natural gas delivered at contracted rates, together with applicable fees for storage, injection, demand, and charges originating from one or more interstate pipeline companies. Performance obligations which have not been satisfied by the Company or Consolidated SCE&G relate primarily to demand or standby service for natural gas. Demand or standby charges for natural gas arise when an industrial customer reserves capacity on assets controlled by the service provider and may use that capacity to move natural gas it has acquired from other suppliers. For all periods presented, the amount of revenue recognized by the Company and Consolidated SCE&G for these charges is equal to the amount of consideration they have a right to invoice and corresponds directly to the value transferred to the customer. As a result, amounts related to performance obligations that have not been fully satisfied are not disclosed. Contracts governing the transactions above do not have a significant financing component. Also, due to the nature of the commodities underlying these transactions, no performance obligations arise for returns, refunds or warranties. In addition, taxes billed to customers are excluded from the transaction price. Such amounts are recorded as liabilities until they are remitted to the respective taxing authority and are not included in revenues or expenses in the statements of operations. Non-Operating Revenues Non-operating revenues are derived from the sale of appliances and water heaters, as well as from contracts covering the repair of certain appliances, wiring, plumbing and similar systems and fees received for such repairs from customers not under a repair contract. In addition, the portion of fees received under asset management agreements that regulators have recognized to be incentives for the Company and Consolidated SCE&G to engage in such transactions is recorded as non-operating revenues. Revenues from sales are recorded when the appliance or water heater is delivered to the customer. Repair contract coverage fees are recorded when invoiced, generally on a monthly basis in advance of the period of coverage. Additional charges for service calls and non-covered repairs are billed and collected at the time service is rendered. Revenues from asset management agreements are recorded when the related fixed monthly amounts are due, which corresponds to timing of the value received by the customer. The point at which the customer controls the use of a purchased product or has obtained substantially all of the benefits from repair services, corresponds to when revenues are recorded and performance obligations are fulfilled. Contract assets arising from invoicing repair contract fees in advance of the coverage period are not material. Income earned from financing sales of appliances and other products is recorded within interest income. Any performance obligations arising from returns, refunds or warranties are not material. Non-operating revenues also arise from sources unrelated to contracts with customers, such as carrying costs recorded on certain regulatory assets, gains from property sales and income from rentals and from equity method investments, among others. In 2018, such amounts include gains realized upon the settlement of certain interest rate swaps (see Note 15). Such revenues are outside the scope of revenues from contracts with customers. Non-operating revenues are further described in Note 15. Such revenues arising from contracts with customers were not material for any period presented, and accordingly, detailed disclosures regarding these revenues are not provided. Significant Judgments and Estimates Electricity and natural gas are sold and delivered to the customer for immediate consumption and the customer controls the use of, and obtains substantially all of the benefits from, the energy and related services as they are delivered. As such, the related performance obligations are satisfied over time and revenue is recognized over the same period. The Company and Consolidated SCE&G have determined that their right to consideration from a customer directly corresponds to the value of the performance completed at the date each customer invoice is rendered. As a result, the Company and Consolidated SCE&G recognize revenue in the amounts for which they have a right to invoice. This includes estimated amounts unbilled at a balance sheet date, but which are to be invoiced in the normal cycle. Regulatory mechanisms exist within electric and gas tariffs or orders from regulators that result in adjustments to customer bills. These regulatory mechanisms are designed: • To recover costs related to fuel, pension, pipeline integrity and energy conservation, among others; • To recover carrying costs associated with debt-based financing; • To replace revenues lost as a result of the utility implementing DER programs and DSM Programs; and • For gas revenues, to achieve weather normalization or to decouple gas revenues from weather and other factors through the WNA at SCE&G or the CUT at PSNC Energy. Recovery of deferred costs and carrying costs and the replacement of lost revenues are components of approved tariffs, and therefore, adjustments to customer bills occur as electricity or natural gas is sold and delivered to the customer. As such, the Company and Consolidated SCE&G have concluded that performance obligations related to these adjustments are not capable of being distinct from the underlying tariff based sales. Accordingly, revenues arising from these adjustments are recorded within Operating Revenues - Electric or Gas - regulated on the statements of operations, consistent with revenues from underlying tariff based sales. Adjustments for SCE&G’s WNA increase gas customer bills when weather is milder than normal and decrease gas customer bills when weather is colder than normal. These adjustments are made during the same period that the underlying natural gas is sold and delivered to the customer, and the performance obligations associated with these adjustments are not capable of being distinct from tariff based sales. Such adjustments are recorded within Operating Revenues - Gas - regulated on the statements of operations. When weather is significantly milder than normal, SCE&G limits such adjustments on a gas customer’s bill to an amount that would be added if weather were 50% milder than normal. Adjustments exceeding this limit, though still recorded as operating revenue, are deferred within regulatory assets until customers are subsequently billed for the excess with the approval of the SCPSC. PSNC Energy’s CUT is a decoupling mechanism that adjusts bills for residential and commercial customers based on per customer average consumption. When average consumption exceeds actual usage, PSNC Energy records increased revenue associated with this undercollection and defers it within regulatory assets. Likewise, when actual usage exceeds average consumption, a decrement to revenue associated with this overcollection is recorded and deferred within regulatory liabilities. PSNC Energy’s tariff based rates are adjusted semiannually, with the approval of the NCUC, to collect or refund these deferred amounts over the subsequent 12 month period. Amounts deferred for the WNA and the CUT arise under specific arrangements with regulators rather than customers. As a result, the Company and Consolidated SCE&G have concluded that these arrangements represent alternative revenue programs. Revenue from alternative revenue programs is included within Operating Revenues - Gas - regulated on the statements of operations in the month such adjustments are deferred within regulatory accounts and is shown as Other operating revenues when disaggregated in the table below. As permitted, the Company and Consolidated SCE&G have elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues. Disaggregation of Revenues The impact of several factors on the amount, timing and uncertainty of operating revenues and cash flows can vary significantly by customer class. For electric revenues and nonregulated gas revenues, which do not have weather normalization mechanisms in place, weather and conservation measures on energy usage typically affect residential and commercial customers to a greater degree than other customer classes. For utilities, revenue requirements result in increases or decreases in tariff rates approved by regulatory bodies and often vary by customer class. Also, certain cost recovery and other mechanisms may have an uneven impact on a particular customer class depending on the underlying tariffs affected. For nonregulated gas, revenues are impacted by competitive market rates tailored to appeal to specific customer classes. The Company and Consolidated SCE&G have disaggregated operating revenues by customer class as follows: The Company Consolidated SCE&G PSNC Energy Total Gas-regulated Gas-nonregulated Millions of dollars Electric Gas-regulated Gas-regulated 2018 Customer class: Residential $ 1,054 $ 208 $ 325 $ 533 $ 244 Commercial 744 117 125 242 92 Industrial 385 92 15 107 422 Transportation — 13 32 45 — Other 132 4 — 4 38 Revenues from contracts with customers 2,315 434 497 931 796 Other operating revenues 12 1 3 4 — Total Operating Revenues $ 2,327 $ 435 $ 500 $ 935 $ 796 Contract Liabilities Contract liabilities represent the obligation to transfer goods or services to a customer for which consideration has already been received from the customer. At December 31, 2018 and 2017, the Company had contract liability balances of $9.4 million and $8.3 million , respectively, and Consolidated SCE&G had contract liability balances of $3.6 million and $2.9 million , respectively. During the twelve months ended December 31, 2018, the Company and Consolidated SCE&G recognized all amounts from their respective December 31, 2017 contract liability balances as each of them fulfilled their obligations to provide service to their customers. Such obligations at December 31, 2018 are expected to be fulfilled within twelve months. Contract liabilities are recorded in Customer deposits and customer prepayments in the consolidated balance sheets. Contract Costs Costs to obtain contracts are generally expensed when incurred. In limited instances, SCE&G provides economic development grants intended to support economic growth within SCE&G’s electric service territory and defers such grants as regulatory assets on the consolidated balance sheet. Whenever these grants are contingent on a customer entering into a long-term electric supply contract with SCE&G, they are considered costs to obtain that underlying contract. Such costs that exceed certain thresholds are deferred and amortized on a straight-line basis over the term of the related service contract, which generally ranges from ten to 15 years. Balances and activity related to contract costs deferred as regulatory assets were as follows: The Company and Consolidated SCE&G Millions of dollars Regulatory Assets January 1, 2018 $ 16.3 Additional costs — Amortization (1.5 ) Impairment — December 31, 2018 $ 14.8
SCE&G
Revenue from Contract with Customer [Text Block]	REVENUE RECOGNITION Identifying Revenue Streams and Related Performance Obligations Operating Revenues Operating revenues arise primarily from the sale and transmission of electricity and the sale and transportation of natural gas. Electric and Gas regulated revenues consist primarily of retail sales to residential, commercial and industrial customers under various tariff rates approved by state regulatory commissions. These tariff rates generally include charges for the energy consumed and a standard basic facilities or demand charge designed to recover certain fixed costs incurred to provide service to the customer. Tariff rates also include commission-approved regulatory mechanisms in the form of adjustments or riders, such as for weather normalization, fuel and environmental cost recovery, energy conservation programs, interruptible service and real time pricing provisions, among others. Electric revenues also include wholesale sales and transmission service, primarily to municipal customers and other service providers, under contracts or tariffs approved by the FERC. Gas nonregulated revenues arise from natural gas sales at market-based rates. Such sales to residential and certain commercial customers include charges for natural gas delivered, at either variable or fixed prices, together with any applicable customer service charges, charges originating from an interstate pipeline company, and other incidental charges. The Company has determined that its gas marketing subsidiary serves as an agent for distribution services provided by a nonaffiliated company in its retail market. Accordingly, the pass-through charges to customers related to such services are not considered revenues. Sales to other commercial and to industrial customers include commodity and transportation charges for natural gas delivered at contracted rates, together with applicable fees for storage, injection, demand, and charges originating from one or more interstate pipeline companies. Performance obligations which have not been satisfied by the Company or Consolidated SCE&G relate primarily to demand or standby service for natural gas. Demand or standby charges for natural gas arise when an industrial customer reserves capacity on assets controlled by the service provider and may use that capacity to move natural gas it has acquired from other suppliers. For all periods presented, the amount of revenue recognized by the Company and Consolidated SCE&G for these charges is equal to the amount of consideration they have a right to invoice and corresponds directly to the value transferred to the customer. As a result, amounts related to performance obligations that have not been fully satisfied are not disclosed. Contracts governing the transactions above do not have a significant financing component. Also, due to the nature of the commodities underlying these transactions, no performance obligations arise for returns, refunds or warranties. In addition, taxes billed to customers are excluded from the transaction price. Such amounts are recorded as liabilities until they are remitted to the respective taxing authority and are not included in revenues or expenses in the statements of operations. Non-Operating Revenues Non-operating revenues are derived from the sale of appliances and water heaters, as well as from contracts covering the repair of certain appliances, wiring, plumbing and similar systems and fees received for such repairs from customers not under a repair contract. In addition, the portion of fees received under asset management agreements that regulators have recognized to be incentives for the Company and Consolidated SCE&G to engage in such transactions is recorded as non-operating revenues. Revenues from sales are recorded when the appliance or water heater is delivered to the customer. Repair contract coverage fees are recorded when invoiced, generally on a monthly basis in advance of the period of coverage. Additional charges for service calls and non-covered repairs are billed and collected at the time service is rendered. Revenues from asset management agreements are recorded when the related fixed monthly amounts are due, which corresponds to timing of the value received by the customer. The point at which the customer controls the use of a purchased product or has obtained substantially all of the benefits from repair services, corresponds to when revenues are recorded and performance obligations are fulfilled. Contract assets arising from invoicing repair contract fees in advance of the coverage period are not material. Income earned from financing sales of appliances and other products is recorded within interest income. Any performance obligations arising from returns, refunds or warranties are not material. Non-operating revenues also arise from sources unrelated to contracts with customers, such as carrying costs recorded on certain regulatory assets, gains from property sales and income from rentals and from equity method investments, among others. In 2018, such amounts include gains realized upon the settlement of certain interest rate swaps (see Note 15). Such revenues are outside the scope of revenues from contracts with customers. Non-operating revenues are further described in Note 15. Such revenues arising from contracts with customers were not material for any period presented, and accordingly, detailed disclosures regarding these revenues are not provided. Significant Judgments and Estimates Electricity and natural gas are sold and delivered to the customer for immediate consumption and the customer controls the use of, and obtains substantially all of the benefits from, the energy and related services as they are delivered. As such, the related performance obligations are satisfied over time and revenue is recognized over the same period. The Company and Consolidated SCE&G have determined that their right to consideration from a customer directly corresponds to the value of the performance completed at the date each customer invoice is rendered. As a result, the Company and Consolidated SCE&G recognize revenue in the amounts for which they have a right to invoice. This includes estimated amounts unbilled at a balance sheet date, but which are to be invoiced in the normal cycle. Regulatory mechanisms exist within electric and gas tariffs or orders from regulators that result in adjustments to customer bills. These regulatory mechanisms are designed: • To recover costs related to fuel, pension, pipeline integrity and energy conservation, among others; • To recover carrying costs associated with debt-based financing; • To replace revenues lost as a result of the utility implementing DER programs and DSM Programs; and • For gas revenues, to achieve weather normalization or to decouple gas revenues from weather and other factors through the WNA at SCE&G or the CUT at PSNC Energy. Recovery of deferred costs and carrying costs and the replacement of lost revenues are components of approved tariffs, and therefore, adjustments to customer bills occur as electricity or natural gas is sold and delivered to the customer. As such, the Company and Consolidated SCE&G have concluded that performance obligations related to these adjustments are not capable of being distinct from the underlying tariff based sales. Accordingly, revenues arising from these adjustments are recorded within Operating Revenues - Electric or Gas - regulated on the statements of operations, consistent with revenues from underlying tariff based sales. Adjustments for SCE&G’s WNA increase gas customer bills when weather is milder than normal and decrease gas customer bills when weather is colder than normal. These adjustments are made during the same period that the underlying natural gas is sold and delivered to the customer, and the performance obligations associated with these adjustments are not capable of being distinct from tariff based sales. Such adjustments are recorded within Operating Revenues - Gas - regulated on the statements of operations. When weather is significantly milder than normal, SCE&G limits such adjustments on a gas customer’s bill to an amount that would be added if weather were 50% milder than normal. Adjustments exceeding this limit, though still recorded as operating revenue, are deferred within regulatory assets until customers are subsequently billed for the excess with the approval of the SCPSC. PSNC Energy’s CUT is a decoupling mechanism that adjusts bills for residential and commercial customers based on per customer average consumption. When average consumption exceeds actual usage, PSNC Energy records increased revenue associated with this undercollection and defers it within regulatory assets. Likewise, when actual usage exceeds average consumption, a decrement to revenue associated with this overcollection is recorded and deferred within regulatory liabilities. PSNC Energy’s tariff based rates are adjusted semiannually, with the approval of the NCUC, to collect or refund these deferred amounts over the subsequent 12 month period. Amounts deferred for the WNA and the CUT arise under specific arrangements with regulators rather than customers. As a result, the Company and Consolidated SCE&G have concluded that these arrangements represent alternative revenue programs. Revenue from alternative revenue programs is included within Operating Revenues - Gas - regulated on the statements of operations in the month such adjustments are deferred within regulatory accounts and is shown as Other operating revenues when disaggregated in the table below. As permitted, the Company and Consolidated SCE&G have elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues. Disaggregation of Revenues The impact of several factors on the amount, timing and uncertainty of operating revenues and cash flows can vary significantly by customer class. For electric revenues and nonregulated gas revenues, which do not have weather normalization mechanisms in place, weather and conservation measures on energy usage typically affect residential and commercial customers to a greater degree than other customer classes. For utilities, revenue requirements result in increases or decreases in tariff rates approved by regulatory bodies and often vary by customer class. Also, certain cost recovery and other mechanisms may have an uneven impact on a particular customer class depending on the underlying tariffs affected. For nonregulated gas, revenues are impacted by competitive market rates tailored to appeal to specific customer classes. The Company and Consolidated SCE&G have disaggregated operating revenues by customer class as follows: The Company Consolidated SCE&G PSNC Energy Total Gas-regulated Gas-nonregulated Millions of dollars Electric Gas-regulated Gas-regulated 2018 Customer class: Residential $ 1,054 $ 208 $ 325 $ 533 $ 244 Commercial 744 117 125 242 92 Industrial 385 92 15 107 422 Transportation — 13 32 45 — Other 132 4 — 4 38 Revenues from contracts with customers 2,315 434 497 931 796 Other operating revenues 12 1 3 4 — Total Operating Revenues $ 2,327 $ 435 $ 500 $ 935 $ 796 Contract Liabilities Contract liabilities represent the obligation to transfer goods or services to a customer for which consideration has already been received from the customer. At December 31, 2018 and 2017, the Company had contract liability balances of $9.4 million and $8.3 million , respectively, and Consolidated SCE&G had contract liability balances of $3.6 million and $2.9 million , respectively. During the twelve months ended December 31, 2018, the Company and Consolidated SCE&G recognized all amounts from their respective December 31, 2017 contract liability balances as each of them fulfilled their obligations to provide service to their customers. Such obligations at December 31, 2018 are expected to be fulfilled within twelve months. Contract liabilities are recorded in Customer deposits and customer prepayments in the consolidated balance sheets. Contract Costs Costs to obtain contracts are generally expensed when incurred. In limited instances, SCE&G provides economic development grants intended to support economic growth within SCE&G’s electric service territory and defers such grants as regulatory assets on the consolidated balance sheet. Whenever these grants are contingent on a customer entering into a long-term electric supply contract with SCE&G, they are considered costs to obtain that underlying contract. Such costs that exceed certain thresholds are deferred and amortized on a straight-line basis over the term of the related service contract, which generally ranges from ten to 15 years. Balances and activity related to contract costs deferred as regulatory assets were as follows: The Company and Consolidated SCE&G Millions of dollars Regulatory Assets January 1, 2018 $ 16.3 Additional costs — Amortization (1.5 ) Impairment — December 31, 2018 $ 14.8

COMMON EQUITY

COMMON EQUITY	12 Months Ended
	Dec. 31, 2018
Schedule of Capitalization, Equity [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	COMMON EQUITY Authorized shares of SCANA common stock were 200 million as of December 31, 2018 and 2017. Authorized shares of SCE&G common stock were 50 million as of December 31, 2018 and 2017. Authorized shares of SCE&G preferred stock were 20 million , of which 1,000 shares, no par value, were held by SCANA as of December 31, 2018 and 2017. As disclosed in Note 1, effective January 1, 2019, all common stock of SCANA is held by Dominion Energy. In 2018, SCANA made equity contributions to GENCO and Fuel Company totaling approximately $23 million and $1 million , respectively. In February 2019, SCANA received an equity contribution of $675 million from Dominion Energy, and SCANA made an equity contribution to SCE&G of $675 million . SCE&G used the funds from this equity contribution to reduce long-term debt. See Note 5. SCANA’s articles of incorporation do not limit the dividends that may be paid on its common stock, and the articles of incorporation of each of SCANA's subsidiaries contain no such limitations on their respective common stock. SCE&G’s bond indenture under which it issues First Mortgage Bonds contains provisions that could limit the payment of cash dividends on its common stock. SCE&G's bond indenture permits the payment of dividends on SCE&G's common stock only either (1) out of its Surplus (as defined in the bond indenture) or (2) in case there is no Surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, the Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At December 31, 2018 and 2017, retained earnings of approximately $115.0 million and $93.9 million , respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock. Pursuant to the Merger Approval Order, the amount of any SCE&G dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry. There is no specific restriction on the payment of dividends by SCE&G. PSNC Energy’s note purchase and debenture purchase agreements contain provisions that could limit the payment of cash distributions, including dividends, on PSNC Energy's common stock. These agreements generally limit the sum of distributions to an amount that does not exceed $30 million plus 85% of Consolidated Net Income (as therein defined) accumulated after December 31, 2008 plus the net proceeds of issuances by PSNC Energy of equity or convertible debt securities (as therein defined). As of December 31, 2018, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million . The NCUC, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by PSNC Energy to (i) the amount of retained earnings at closing of the SCANA Combination plus (ii) any future earnings recorded by PSNC Energy after such date. In addition, notice to the NCUC is required if payment of dividends causes the equity component of PSNC Energy’s capital structure to fall below 45%.
SCE&G
Schedule of Capitalization, Equity [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	. COMMON EQUITY Authorized shares of SCANA common stock were 200 million as of December 31, 2018 and 2017. Authorized shares of SCE&G common stock were 50 million as of December 31, 2018 and 2017. Authorized shares of SCE&G preferred stock were 20 million , of which 1,000 shares, no par value, were held by SCANA as of December 31, 2018 and 2017. As disclosed in Note 1, effective January 1, 2019, all common stock of SCANA is held by Dominion Energy. In 2018, SCANA made equity contributions to GENCO and Fuel Company totaling approximately $23 million and $1 million , respectively. In February 2019, SCANA received an equity contribution of $675 million from Dominion Energy, and SCANA made an equity contribution to SCE&G of $675 million . SCE&G used the funds from this equity contribution to reduce long-term debt. See Note 5. SCANA’s articles of incorporation do not limit the dividends that may be paid on its common stock, and the articles of incorporation of each of SCANA's subsidiaries contain no such limitations on their respective common stock. SCE&G’s bond indenture under which it issues First Mortgage Bonds contains provisions that could limit the payment of cash dividends on its common stock. SCE&G's bond indenture permits the payment of dividends on SCE&G's common stock only either (1) out of its Surplus (as defined in the bond indenture) or (2) in case there is no Surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, the Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At December 31, 2018 and 2017, retained earnings of approximately $115.0 million and $93.9 million , respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock. Pursuant to the Merger Approval Order, the amount of any SCE&G dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry. There is no specific restriction on the payment of dividends by SCE&G. PSNC Energy’s note purchase and debenture purchase agreements contain provisions that could limit the payment of cash distributions, including dividends, on PSNC Energy's common stock. These agreements generally limit the sum of distributions to an amount that does not exceed $30 million plus 85% of Consolidated Net Income (as therein defined) accumulated after December 31, 2008 plus the net proceeds of issuances by PSNC Energy of equity or convertible debt securities (as therein defined). As of December 31, 2018, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million . The NCUC, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by PSNC Energy to (i) the amount of retained earnings at closing of the SCANA Combination plus (ii) any future earnings recorded by PSNC Energy after such date. In addition, notice to the NCUC is required if payment of dividends causes the equity component of PSNC Energy’s capital structure to fall below 45%.

LONG-TERM AND SHORT-TERM DEBT

LONG-TERM AND SHORT-TERM DEBT	12 Months Ended
	Dec. 31, 2018
Debt Instrument [Line Items]
Debt Disclosure [Text Block]	LONG-TERM AND SHORT-TERM DEBT Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows: The Company December 31, 2018 2017 Dollars in millions Maturity Balance Rate Balance Rate SCANA Medium Term Notes (unsecured) 2020 - 2022 $ 800 5.42 % $ 800 5.42 % SCANA Senior Notes (unsecured) (a) 2019 - 2034 70 3.44 % 75 2.18 % SCE&G First Mortgage Bonds (secured) 2021 - 2065 4,990 5.52 % 4,840 5.80 % GENCO Notes (secured) 2019 - 2024 40 5.49 % 207 5.94 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.52 % 122 3.52 % PSNC Energy Senior Debentures and Notes 2020 - 2047 700 5.07 % 600 5.19 % Other 2019 - 2027 73 3.46 % 28 2.83 % Total debt 6,795 6,672 Current maturities of long-term debt (59 ) (727 ) Unamortized discount, net (2 ) (1 ) Unamortized debt issuance costs (39 ) (38 ) Total long-term debt, net $ 6,695 $ 5,906 Consolidated SCE&G December 31, 2018 2017 Dollars in millions Maturity Balance Rate Balance Rate First Mortgage Bonds (secured) 2021 - 2065 $ 4,990 5.52 % $ 4,840 5.80 % GENCO Notes (secured) 2019 - 2024 40 5.49 % 207 5.94 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.52 % 122 3.52 % Other 2019 - 2027 30 2.97 % 28 2.83 % Total debt 5,182 5,197 Current maturities of long-term debt (14 ) (723 ) Unamortized premium (discount), net (1 ) 1 Unamortized debt issuance costs (35 ) (34 ) Total long-term debt, net $ 5,132 $ 4,441 (a) Variable rate notes hedged by a fixed interest rate swap (fixed rate of 6.17% ). (b) Includes variable rate debt of $67.8 million at December 31, 2018 (rate of 1.72% ) and 2017 (rate of 1.85% ) which are hedged by fixed swaps. In September 2018, SCANA borrowed $40 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at December 31, 2018 was 3.87% . This draw was repaid January 10, 2019. Proceeds from the draw had been used to provide contractually required credit support, and this deposit is reflected within other assets on the consolidated balance sheet. In August 2018, SCE&G issued $300 million of 3.50% first mortgage bonds due August 15, 2021, and $400 million of 4.25% first mortgage bonds due August 15, 2028. Proceeds from these sales were used on September 28, 2018, to repay prior to maturity $250 million of 5.25% first mortgage bonds and $300 million of 6.50% first mortgage bonds, each due November 1, 2018. In addition, proceeds were used for general corporate purposes. In June 2018, GENCO redeemed at maturity $160 million of 6.06% secured notes. The repayment was funded using a combination of money pool borrowings and an equity contribution from SCANA. In June 2018, PSNC Energy issued $100 million of 4.33% senior notes due June 15, 2028. In June 2017, PSNC Energy issued $150 million of 4.18% senior notes due June 30, 2047. Proceeds from each of these sales were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes. In March 2018, SCE&G borrowed $100 million under the five-year credit agreement expiring December 2020. The proceeds of this draw were deposited with a natural gas supplier to provide contractually required credit support. In September 2018, SCE&G obtained a surety bond to replace this credit support and, as a result, the deposit was returned and this draw was repaid in September 2018. Also, SCANA obtained letters of credit in favor of natural gas suppliers to provide contractually required credit support. As of December 31, 2018, the Company's long-term debt maturities are $59 million in 2019, $368 million in 2020, $797 million in 2021, $266 million in 2022 and $14 million in 2023. These amounts include, for Consolidated SCE&G, $14 million in 2019, $13 million in 2020, $342 million in 2021, $11 million in 2022 and $9 million in 2023. In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any and all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of approximately $1.0 billion . SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer. Substantially all electric utility plant is pledged as collateral in connection with long-term debt. SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be issued (Bond Ratio). For the year ended December 31, 2018, the Bond Ratio was 4.01 . Adjusted Net Earnings, as therein defined, excludes the impairment loss. Lines of Credit and Short-Term Borrowings At December 31, 2018 and 2017, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC-related obligations and commercial paper borrowings: Millions of dollars Total SCANA SCE&G PSNC Energy December 31, 2018 Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Total committed long-term 1,800.0 400.0 1,200.0 200.0 LOC advances 40.0 40.0 — — Weighted average interest rate 3.87 % Outstanding commercial paper (270 or fewer days) 172.9 2.0 73.2 97.7 Weighted average interest rate 3.65 % 3.82 % 3.49 % Letters of credit supported by LOC 37.6 37.3 0.3 — Available $ 1,549.5 $ 320.7 $ 1,126.5 $ 102.3 December 31, 2017 Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Three-year, expiring December 2018 200.0 — 200.0 — Total committed long-term 2,000.0 400.0 1,400.0 200.0 Outstanding commercial paper (270 or fewer days) 350.3 — 251.6 98.7 Weighted average interest rate 1.92 % 1.93 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,646.4 $ 397.0 $ 1,148.1 $ 101.3 At December 31, 2018, SCANA, SCE&G (including Fuel Company) and PSNC Energy were parties to credit agreements in the amounts and for the terms described above. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N.A. and Morgan Stanley Bank, N.A. each provide 9.5% of the aggregate credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch, UBS Loan Finance LLC, MUFG Union Bank, N.A., and Branch Banking and Trust Company each provide 7.9 %, and Royal Bank of Canada and U.S. Bank National Association each provide 5.5% . Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented. In December 2018, SCE&G's three-year credit facility expired and was not replaced. In February 2019, Fuel Company's commercial paper program and its credit facility were terminated. Fuel Company's financing needs in the future are expected to be met using the money pool described below. SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million . GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2019, which reflects a one-year authorization period rather than the two-year period SCE&G and GENCO had requested. In granting the authorization for a shorter period, FERC cited several matters which, at the time, were ongoing, including proceedings involving the ORS and Act 258, as well as the merger between SCANA and Dominion Energy, that could affect SCE&G's and GENCO's circumstances. Were adverse developments to occur with respect to uncertainties highlighted elsewhere, the ability of SCE&G or GENCO to secure renewal of this short-term borrowing authority may be adversely impacted. In January 2019, SCE&G and GENCO applied to FERC for a two-year short-term borrowing authorization, and that application is pending. Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. The letters of credit expire, subject to renewal, in the fourth quarter of 2019. Consolidated SCE&G participates in a utility money pool with SCANA and another regulated subsidiary of SCANA. Money pool borrowings and investments bear interest at short-term market rates. For the twelve months ended December 31, 2018, Consolidated SCE&G recorded interest income from money pool transactions of $ 4.1 million and interest expense from money pool transactions of $4.1 million , respectively. Interest income and interest expense for periods in 2017 were not significant. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $282 million and investments due from an affiliate of $353 million at December 31, 2018. At December 31, 2017 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $37 million and investments due from an affiliate of $28 million . For each period presented, money pool borrowings were made by Fuel Company and GENCO, and money pool investments were made by SCE&G. On its consolidated balance sheet, Consolidated SCE&G includes money pool borrowings within Affiliated payables and money pool investments within Affiliated companies receivables.
SCE&G
Debt Instrument [Line Items]
Debt Disclosure [Text Block]	LONG-TERM AND SHORT-TERM DEBT Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows: The Company December 31, 2018 2017 Dollars in millions Maturity Balance Rate Balance Rate SCANA Medium Term Notes (unsecured) 2020 - 2022 $ 800 5.42 % $ 800 5.42 % SCANA Senior Notes (unsecured) (a) 2019 - 2034 70 3.44 % 75 2.18 % SCE&G First Mortgage Bonds (secured) 2021 - 2065 4,990 5.52 % 4,840 5.80 % GENCO Notes (secured) 2019 - 2024 40 5.49 % 207 5.94 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.52 % 122 3.52 % PSNC Energy Senior Debentures and Notes 2020 - 2047 700 5.07 % 600 5.19 % Other 2019 - 2027 73 3.46 % 28 2.83 % Total debt 6,795 6,672 Current maturities of long-term debt (59 ) (727 ) Unamortized discount, net (2 ) (1 ) Unamortized debt issuance costs (39 ) (38 ) Total long-term debt, net $ 6,695 $ 5,906 Consolidated SCE&G December 31, 2018 2017 Dollars in millions Maturity Balance Rate Balance Rate First Mortgage Bonds (secured) 2021 - 2065 $ 4,990 5.52 % $ 4,840 5.80 % GENCO Notes (secured) 2019 - 2024 40 5.49 % 207 5.94 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.52 % 122 3.52 % Other 2019 - 2027 30 2.97 % 28 2.83 % Total debt 5,182 5,197 Current maturities of long-term debt (14 ) (723 ) Unamortized premium (discount), net (1 ) 1 Unamortized debt issuance costs (35 ) (34 ) Total long-term debt, net $ 5,132 $ 4,441 (a) Variable rate notes hedged by a fixed interest rate swap (fixed rate of 6.17% ). (b) Includes variable rate debt of $67.8 million at December 31, 2018 (rate of 1.72% ) and 2017 (rate of 1.85% ) which are hedged by fixed swaps. In September 2018, SCANA borrowed $40 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at December 31, 2018 was 3.87% . This draw was repaid January 10, 2019. Proceeds from the draw had been used to provide contractually required credit support, and this deposit is reflected within other assets on the consolidated balance sheet. In August 2018, SCE&G issued $300 million of 3.50% first mortgage bonds due August 15, 2021, and $400 million of 4.25% first mortgage bonds due August 15, 2028. Proceeds from these sales were used on September 28, 2018, to repay prior to maturity $250 million of 5.25% first mortgage bonds and $300 million of 6.50% first mortgage bonds, each due November 1, 2018. In addition, proceeds were used for general corporate purposes. In June 2018, GENCO redeemed at maturity $160 million of 6.06% secured notes. The repayment was funded using a combination of money pool borrowings and an equity contribution from SCANA. In June 2018, PSNC Energy issued $100 million of 4.33% senior notes due June 15, 2028. In June 2017, PSNC Energy issued $150 million of 4.18% senior notes due June 30, 2047. Proceeds from each of these sales were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes. In March 2018, SCE&G borrowed $100 million under the five-year credit agreement expiring December 2020. The proceeds of this draw were deposited with a natural gas supplier to provide contractually required credit support. In September 2018, SCE&G obtained a surety bond to replace this credit support and, as a result, the deposit was returned and this draw was repaid in September 2018. Also, SCANA obtained letters of credit in favor of natural gas suppliers to provide contractually required credit support. As of December 31, 2018, the Company's long-term debt maturities are $59 million in 2019, $368 million in 2020, $797 million in 2021, $266 million in 2022 and $14 million in 2023. These amounts include, for Consolidated SCE&G, $14 million in 2019, $13 million in 2020, $342 million in 2021, $11 million in 2022 and $9 million in 2023. In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any and all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of approximately $1.0 billion . SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer. Substantially all electric utility plant is pledged as collateral in connection with long-term debt. SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be issued (Bond Ratio). For the year ended December 31, 2018, the Bond Ratio was 4.01 . Adjusted Net Earnings, as therein defined, excludes the impairment loss. Lines of Credit and Short-Term Borrowings At December 31, 2018 and 2017, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC-related obligations and commercial paper borrowings: Millions of dollars Total SCANA SCE&G PSNC Energy December 31, 2018 Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Total committed long-term 1,800.0 400.0 1,200.0 200.0 LOC advances 40.0 40.0 — — Weighted average interest rate 3.87 % Outstanding commercial paper (270 or fewer days) 172.9 2.0 73.2 97.7 Weighted average interest rate 3.65 % 3.82 % 3.49 % Letters of credit supported by LOC 37.6 37.3 0.3 — Available $ 1,549.5 $ 320.7 $ 1,126.5 $ 102.3 December 31, 2017 Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Three-year, expiring December 2018 200.0 — 200.0 — Total committed long-term 2,000.0 400.0 1,400.0 200.0 Outstanding commercial paper (270 or fewer days) 350.3 — 251.6 98.7 Weighted average interest rate 1.92 % 1.93 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,646.4 $ 397.0 $ 1,148.1 $ 101.3 At December 31, 2018, SCANA, SCE&G (including Fuel Company) and PSNC Energy were parties to credit agreements in the amounts and for the terms described above. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N.A. and Morgan Stanley Bank, N.A. each provide 9.5% of the aggregate credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch, UBS Loan Finance LLC, MUFG Union Bank, N.A., and Branch Banking and Trust Company each provide 7.9 %, and Royal Bank of Canada and U.S. Bank National Association each provide 5.5% . Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented. In December 2018, SCE&G's three-year credit facility expired and was not replaced. In February 2019, Fuel Company's commercial paper program and its credit facility were terminated. Fuel Company's financing needs in the future are expected to be met using the money pool described below. SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million . GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2019, which reflects a one-year authorization period rather than the two-year period SCE&G and GENCO had requested. In granting the authorization for a shorter period, FERC cited several matters which, at the time, were ongoing, including proceedings involving the ORS and Act 258, as well as the merger between SCANA and Dominion Energy, that could affect SCE&G's and GENCO's circumstances. Were adverse developments to occur with respect to uncertainties highlighted elsewhere, the ability of SCE&G or GENCO to secure renewal of this short-term borrowing authority may be adversely impacted. In January 2019, SCE&G and GENCO applied to FERC for a two-year short-term borrowing authorization, and that application is pending. Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. The letters of credit expire, subject to renewal, in the fourth quarter of 2019. Consolidated SCE&G participates in a utility money pool with SCANA and another regulated subsidiary of SCANA. Money pool borrowings and investments bear interest at short-term market rates. For the twelve months ended December 31, 2018, Consolidated SCE&G recorded interest income from money pool transactions of $ 4.1 million and interest expense from money pool transactions of $4.1 million , respectively. Interest income and interest expense for periods in 2017 were not significant. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $282 million and investments due from an affiliate of $353 million at December 31, 2018. At December 31, 2017 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $37 million and investments due from an affiliate of $28 million . For each period presented, money pool borrowings were made by Fuel Company and GENCO, and money pool investments were made by SCE&G. On its consolidated balance sheet, Consolidated SCE&G includes money pool borrowings within Affiliated payables and money pool investments within Affiliated companies receivables.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2018
income tax [Line Items]
Income Tax Disclosure [Text Block]	INCOME TAXES Components of income tax expense (benefit) are as follows: The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 Current taxes (benefit): Federal $ (8 ) $ (414 ) $ 36 $ (16 ) $ (410 ) $ 50 State 5 18 13 — (18 ) 13 Total current taxes (benefit) (3 ) (396 ) 49 (16 ) (428 ) 63 Deferred tax (benefit) expense, net: Federal (352 ) 323 203 (346 ) 261 167 State (55 ) (37 ) 21 (52 ) (2 ) 20 Total deferred taxes (benefit) (407 ) 286 224 (398 ) 259 187 Investment tax credits: Amortization of amounts deferred-federal (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Total income tax expense (benefit) $ (412 ) $ (112 ) $ 271 $ (416 ) $ (171 ) $ 248 In December 2017, the Tax Act was enacted, resulting in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory tax rate. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in excess deferred income tax balances within regulatory liabilities (see Note 2). Included in the Company’s 2018 federal deferred income tax expense was $53 million for the utilization of operating loss carryforwards. Included in Consolidated SCE&G’s 2018 federal deferred income tax expense was $46 million for the utilization of operating loss carryforwards. The difference between actual income tax expense and the amount calculated from the application of the statutory federal income tax rate to pre-tax income is reconciled as follows: The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 U.S. statutory rate 21 % 35 % 35 % 21 % 35 % 35 % Net income (loss) $ (528 ) $ (119 ) $ 595 $ (614 ) $ (185 ) $ 513 Income tax expense (benefit) (412 ) (112 ) 271 (416 ) (171 ) 248 Noncontrolling interest — — — 25 13 13 Total pre-tax income (loss) $ (940 ) $ (231 ) $ 866 $ (1,005 ) $ (343 ) $ 774 Income taxes (benefit) on above at statutory federal income tax rate $ (197 ) $ (81 ) $ 303 $ (211 ) $ (120 ) $ 271 Increases (decreases) attributed to: State income taxes (less federal income tax effect) (37 ) (7 ) 27 (38 ) (8 ) 26 State investment tax credits (less federal income tax effect) (3 ) (5 ) (5 ) (3 ) (5 ) (5 ) Allowance for equity funds used during construction (4 ) (8 ) (10 ) (2 ) (5 ) (9 ) Deductible dividends—401(k) Retirement Savings Plan (2 ) (9 ) (10 ) — — — Amortization of federal investment tax credits (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Section 45 tax credits (9 ) (8 ) (8 ) (9 ) (8 ) (8 ) Domestic production activities deduction — (18 ) (23 ) — (18 ) (23 ) Remeasurement of deferred taxes in connection with enactment of Tax Act (188 ) 30 — (176 ) (1 ) — Nuclear Project impairment 23 — — 23 — — Nondeductible merger-related costs 5 — — — — — Other differences, net 2 (4 ) (1 ) 2 (4 ) (2 ) Total income tax expense (benefit) $ (412 ) $ (112 ) $ 271 $ (416 ) $ (171 ) $ 248 The Company and Consolidated SCE&G have completed their accounting for the effects of the Tax Act. In connection with the remeasurement of federal deferred income tax assets and liabilities, the Company recorded additional deferred income tax expense of approximately $30 million, and Consolidated SCE&G recorded a deferred income tax benefit of approximately $1 million in their respective statements of operations for the year ended December 31, 2017. As a result of the eventual filing of the Company's 2017 tax return in the fourth quarter of 2018 and the additional impairment charges recorded in 2018, adjustments to such excess deferred income taxes of approximately $188 million at the Company and approximately $176 million at Consolidated SCE&G were recorded. Also in connection with the additional impairment charges, the Company and Consolidated SCE&G recorded additional adjustments to deferred income taxes in the aggregate amount of approximately $23 million. Additional changes could occur as further Tax Act guidance is issued and finalized. In addition, certain states in which the Company and Consolidated SCE&G operate may or may not conform to some or all of the provisions of the Tax Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to results of operations and cash flows, and adjustments to tax-related assets and liabilities, and such impacts or adjustments could be material. The State of North Carolina lowered its corporate income tax rate to 4.0% in 2016, 3.0% in 2017 and 2.5% effective January 1, 2019. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows. The tax effects of significant temporary differences comprising net deferred tax liabilities are as follows: The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Deferred tax assets: Net operating loss and tax credit carryforward $ 539 $ 600 $ 493 $ 541 Toshiba settlement 274 273 274 273 Nondeductible accruals 84 88 40 42 Asset retirement obligation, including nuclear decommissioning 143 141 135 132 Regulatory liability, non-property accumulated deferred income tax — 54 — 54 Financial instruments 10 15 — — Unamortized investment tax credits 7 8 7 8 Other 4 6 5 5 Total deferred tax assets 1,061 1,185 954 1,055 Deferred tax liabilities: Property, plant and equipment 1,227 1,220 1,033 1,035 Regulatory asset, unrecovered nuclear plant costs 668 962 668 962 Deferred employee benefit plan costs 60 60 53 53 Regulatory asset, asset retirement obligation 94 91 88 85 Regulatory asset, other unrecovered plant 24 27 24 27 Demand side management costs 16 16 16 16 Prepayments 21 21 20 19 Other 63 49 41 31 Total deferred tax liabilities 2,173 2,446 1,943 2,228 Net deferred tax liabilities $ 1,112 $ 1,261 $ 989 $ 1,173 The federal and state tax credits and NOL carryforwards are presented below: December 31, 2018 Millions of dollars The Company Consolidated SCE&G Expiration Year Federal NOL Carryforwards $ 1,807 $ 1,642 2037 Federal Tax Credits 83 83 2035 - 2038 State NOL Carryforwards 2,447 2,198 2037 State Tax Credits 30 30 2026 - 2033 Total Tax Credits and NOL Carryforwards $ 4,367 $ 3,953 A valuation allowance is needed when it is more likely than not that all or a portion of a deferred tax asset will not be realized. In determining whether a valuation allowance is required, the Company and Consolidated SCE&G consider such factors as prior earnings history, expected future earnings, carryback and carryforward periods, and tax strategies that could potentially enhance the likelihood of the realization of a deferred tax asset. Based on this evaluation, management has concluded that a valuation allowance is not needed. The Company files consolidated federal income tax returns and certain state returns, including the return for South Carolina, which returns include Consolidated SCE&G. The Company and its subsidiaries file various other applicable state and local income tax returns. Consolidated SCE&G's NOL shown above represents their portion on a stand-alone company basis. There is no material amount due to or from the Company. The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2009 are closed for additional assessment. The IRS is currently examining the Company's open federal returns through 2017 as a result of claims discussed below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010. Changes in Unrecognized Tax Benefits The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 Unrecognized tax benefits, January 1 $ 98 $ 350 $ 49 $ 98 $ 350 $ 49 Gross increases—uncertain tax positions in prior period 8 — 94 8 — 94 Gross decreases—uncertain tax positions in prior period — (273 ) — — (273 ) — Gross increases—current period uncertain tax positions — 21 207 — 21 207 Unrecognized tax benefits, December 31 $ 106 $ 98 $ 350 $ 106 $ 98 $ 350 During 2013 and 2014, the Company amended certain of its income tax returns to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). The Company also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016 and 2017, the Company claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the Nuclear Project, in its 2015 and 2016 income tax returns. The Company claimed similar deductions and credits in its 2017 tax return when it was filed in 2018. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. The IRS examined the claims in the amended returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2017 income tax returns. These IRC Section 174 income tax deductions and IRC Section 41 credits were considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities were recorded as unrecognized tax benefits in the financial statements. Following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G claimed an abandonment loss deduction under IRC Section 165 on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, are instead expected to be deductible in 2017 under IRC Section 165. The Company received a favorable PLR from the IRS stating the Company has a valid tax deduction for abandonment under IRC Section 165. Although the IRS does not verify the amount of the deduction, there is no reserve against these costs. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, Section 41 credits, and certain unrecognized state tax benefits. As of December 31, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $106 million ( $38 million net of the impact of state deductions on federal returns, net of NOL and credit carryforwards, and net of receivables related to the uncertain tax positions). If recognized, $106 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. Due to the merger with Dominion Energy, it is reasonably possible that these unrecognized tax benefits could increase within the next 12 months, although such increase cannot be reasonably estimated. It is reasonably possible that these unrecognized tax benefits may decrease by $11 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through December 31, 2018. The Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses. Amounts recorded for such interest income, interest expense or tax penalties have not been material for any period presented.
SCE&G
income tax [Line Items]
Income Tax Disclosure [Text Block]	INCOME TAXES Components of income tax expense (benefit) are as follows: The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 Current taxes (benefit): Federal $ (8 ) $ (414 ) $ 36 $ (16 ) $ (410 ) $ 50 State 5 18 13 — (18 ) 13 Total current taxes (benefit) (3 ) (396 ) 49 (16 ) (428 ) 63 Deferred tax (benefit) expense, net: Federal (352 ) 323 203 (346 ) 261 167 State (55 ) (37 ) 21 (52 ) (2 ) 20 Total deferred taxes (benefit) (407 ) 286 224 (398 ) 259 187 Investment tax credits: Amortization of amounts deferred-federal (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Total income tax expense (benefit) $ (412 ) $ (112 ) $ 271 $ (416 ) $ (171 ) $ 248 In December 2017, the Tax Act was enacted, resulting in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory tax rate. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in excess deferred income tax balances within regulatory liabilities (see Note 2). Included in the Company’s 2018 federal deferred income tax expense was $53 million for the utilization of operating loss carryforwards. Included in Consolidated SCE&G’s 2018 federal deferred income tax expense was $46 million for the utilization of operating loss carryforwards. The difference between actual income tax expense and the amount calculated from the application of the statutory federal income tax rate to pre-tax income is reconciled as follows: The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 U.S. statutory rate 21 % 35 % 35 % 21 % 35 % 35 % Net income (loss) $ (528 ) $ (119 ) $ 595 $ (614 ) $ (185 ) $ 513 Income tax expense (benefit) (412 ) (112 ) 271 (416 ) (171 ) 248 Noncontrolling interest — — — 25 13 13 Total pre-tax income (loss) $ (940 ) $ (231 ) $ 866 $ (1,005 ) $ (343 ) $ 774 Income taxes (benefit) on above at statutory federal income tax rate $ (197 ) $ (81 ) $ 303 $ (211 ) $ (120 ) $ 271 Increases (decreases) attributed to: State income taxes (less federal income tax effect) (37 ) (7 ) 27 (38 ) (8 ) 26 State investment tax credits (less federal income tax effect) (3 ) (5 ) (5 ) (3 ) (5 ) (5 ) Allowance for equity funds used during construction (4 ) (8 ) (10 ) (2 ) (5 ) (9 ) Deductible dividends—401(k) Retirement Savings Plan (2 ) (9 ) (10 ) — — — Amortization of federal investment tax credits (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Section 45 tax credits (9 ) (8 ) (8 ) (9 ) (8 ) (8 ) Domestic production activities deduction — (18 ) (23 ) — (18 ) (23 ) Remeasurement of deferred taxes in connection with enactment of Tax Act (188 ) 30 — (176 ) (1 ) — Nuclear Project impairment 23 — — 23 — — Nondeductible merger-related costs 5 — — — — — Other differences, net 2 (4 ) (1 ) 2 (4 ) (2 ) Total income tax expense (benefit) $ (412 ) $ (112 ) $ 271 $ (416 ) $ (171 ) $ 248 The Company and Consolidated SCE&G have completed their accounting for the effects of the Tax Act. In connection with the remeasurement of federal deferred income tax assets and liabilities, the Company recorded additional deferred income tax expense of approximately $30 million, and Consolidated SCE&G recorded a deferred income tax benefit of approximately $1 million in their respective statements of operations for the year ended December 31, 2017. As a result of the eventual filing of the Company's 2017 tax return in the fourth quarter of 2018 and the additional impairment charges recorded in 2018, adjustments to such excess deferred income taxes of approximately $188 million at the Company and approximately $176 million at Consolidated SCE&G were recorded. Also in connection with the additional impairment charges, the Company and Consolidated SCE&G recorded additional adjustments to deferred income taxes in the aggregate amount of approximately $23 million. Additional changes could occur as further Tax Act guidance is issued and finalized. In addition, certain states in which the Company and Consolidated SCE&G operate may or may not conform to some or all of the provisions of the Tax Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to results of operations and cash flows, and adjustments to tax-related assets and liabilities, and such impacts or adjustments could be material. The State of North Carolina lowered its corporate income tax rate to 4.0% in 2016, 3.0% in 2017 and 2.5% effective January 1, 2019. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows. The tax effects of significant temporary differences comprising net deferred tax liabilities are as follows: The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Deferred tax assets: Net operating loss and tax credit carryforward $ 539 $ 600 $ 493 $ 541 Toshiba settlement 274 273 274 273 Nondeductible accruals 84 88 40 42 Asset retirement obligation, including nuclear decommissioning 143 141 135 132 Regulatory liability, non-property accumulated deferred income tax — 54 — 54 Financial instruments 10 15 — — Unamortized investment tax credits 7 8 7 8 Other 4 6 5 5 Total deferred tax assets 1,061 1,185 954 1,055 Deferred tax liabilities: Property, plant and equipment 1,227 1,220 1,033 1,035 Regulatory asset, unrecovered nuclear plant costs 668 962 668 962 Deferred employee benefit plan costs 60 60 53 53 Regulatory asset, asset retirement obligation 94 91 88 85 Regulatory asset, other unrecovered plant 24 27 24 27 Demand side management costs 16 16 16 16 Prepayments 21 21 20 19 Other 63 49 41 31 Total deferred tax liabilities 2,173 2,446 1,943 2,228 Net deferred tax liabilities $ 1,112 $ 1,261 $ 989 $ 1,173 The federal and state tax credits and NOL carryforwards are presented below: December 31, 2018 Millions of dollars The Company Consolidated SCE&G Expiration Year Federal NOL Carryforwards $ 1,807 $ 1,642 2037 Federal Tax Credits 83 83 2035 - 2038 State NOL Carryforwards 2,447 2,198 2037 State Tax Credits 30 30 2026 - 2033 Total Tax Credits and NOL Carryforwards $ 4,367 $ 3,953 A valuation allowance is needed when it is more likely than not that all or a portion of a deferred tax asset will not be realized. In determining whether a valuation allowance is required, the Company and Consolidated SCE&G consider such factors as prior earnings history, expected future earnings, carryback and carryforward periods, and tax strategies that could potentially enhance the likelihood of the realization of a deferred tax asset. Based on this evaluation, management has concluded that a valuation allowance is not needed. The Company files consolidated federal income tax returns and certain state returns, including the return for South Carolina, which returns include Consolidated SCE&G. The Company and its subsidiaries file various other applicable state and local income tax returns. Consolidated SCE&G's NOL shown above represents their portion on a stand-alone company basis. There is no material amount due to or from the Company. The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2009 are closed for additional assessment. The IRS is currently examining the Company's open federal returns through 2017 as a result of claims discussed below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010. Changes in Unrecognized Tax Benefits The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 Unrecognized tax benefits, January 1 $ 98 $ 350 $ 49 $ 98 $ 350 $ 49 Gross increases—uncertain tax positions in prior period 8 — 94 8 — 94 Gross decreases—uncertain tax positions in prior period — (273 ) — — (273 ) — Gross increases—current period uncertain tax positions — 21 207 — 21 207 Unrecognized tax benefits, December 31 $ 106 $ 98 $ 350 $ 106 $ 98 $ 350 During 2013 and 2014, the Company amended certain of its income tax returns to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). The Company also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016 and 2017, the Company claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the Nuclear Project, in its 2015 and 2016 income tax returns. The Company claimed similar deductions and credits in its 2017 tax return when it was filed in 2018. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. The IRS examined the claims in the amended returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2017 income tax returns. These IRC Section 174 income tax deductions and IRC Section 41 credits were considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities were recorded as unrecognized tax benefits in the financial statements. Following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G claimed an abandonment loss deduction under IRC Section 165 on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, are instead expected to be deductible in 2017 under IRC Section 165. The Company received a favorable PLR from the IRS stating the Company has a valid tax deduction for abandonment under IRC Section 165. Although the IRS does not verify the amount of the deduction, there is no reserve against these costs. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, Section 41 credits, and certain unrecognized state tax benefits. As of December 31, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $106 million ( $38 million net of the impact of state deductions on federal returns, net of NOL and credit carryforwards, and net of receivables related to the uncertain tax positions). If recognized, $106 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. Due to the merger with Dominion Energy, it is reasonably possible that these unrecognized tax benefits could increase within the next 12 months, although such increase cannot be reasonably estimated. It is reasonably possible that these unrecognized tax benefits may decrease by $11 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through December 31, 2018. The Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses. Amounts recorded for such interest income, interest expense or tax penalties have not been material for any period presented.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2018
Derivative [Line Items]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	. DERIVATIVE FINANCIAL INSTRUMENTS Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. Policies and procedures, and in some cases risk limits, are established to control the level of market, credit, liquidity and operational and administrative risks. Historically, SCANA’s Board of Directors delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which was comprised of certain officers, apprised the Board of Directors with regard to the management of risk and brought to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions. Commodity Derivatives The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions. Cash settlements of commodity derivatives are classified as operating activities in the consolidated statements of cash flows. PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes. Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit. As an accommodation to certain customers, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives. These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes. Interest Rate Swaps Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances. In cases in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense. Forward starting swap agreements designated as cash flow hedges have been used in anticipation of the issuance of debt. Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and its nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 were not designated for accounting purposes as cash flow hedges, and fair value changes and settlement amounts related to them have been recorded as regulatory assets and liabilities. Settlement losses on swaps generally have been amortized over the lives of subsequent debt issuances, and gains have been amortized to interest expense or have been applied as otherwise directed by the SCPSC. See Note 2 and Note 15 regarding the settlement gains realized in the first quarter of 2018. Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes. Quantitative Disclosures Related to Derivatives The Company was party to natural gas derivative contracts outstanding in the following quantities: Commodity and Energy Management Contracts (in bcf) Hedge designation Gas Distribution Gas Marketing Total As of December 31, 2018 Commodity 6.4 12.9 19.3 Energy Management (a) — 46.8 46.8 Total (a) 6.4 59.7 66.1 As of December 31, 2017 Commodity 6.4 13.4 19.8 Energy Management (a) — 41.9 41.9 Total (a) 6.4 55.3 61.7 (a) Includes amounts related to basis swap contracts totaling 5.1 bcf in 2018 and 2.6 bcf in 2017. The aggregate notional amounts of the interest rate swaps were as follows: Interest Rate Swaps The Company Consolidated SCE&G Millions of dollars December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 Designated as hedging instruments $ 106.8 $ 111.2 $ 36.4 $ 36.4 Not designated as hedging instruments 35.0 735.0 35.0 735.0 The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown. Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of December 31, 2018 Designated as hedging instruments Interest rate contracts Other current liabilities — $ 2 — $ 1 Other deferred credits and other liabilities — 19 — 7 Commodity contracts Prepayments — 1 — — Total — $ 22 — $ 8 Not designated as hedging instruments Interest rate contracts Other deferred credits and other liabilities — $ 3 — $ 3 Commodity contracts Prepayments $ 1 — — — Energy management contracts Prepayments 11 12 — — Other current assets 1 — — — Other current liabilities — 1 — — Other deferred debits and other assets 1 — — — Total $ 14 $ 16 — $ 3 As of December 31, 2017 Designated as hedging instruments Interest rate contracts Other current liabilities — $ 3 — $ 1 Other deferred credits and other liabilities — 24 — 9 Commodity contracts Prepayments — 2 — — Other current liabilities — 1 — — Total — $ 30 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets and current liabilities $ 54 $ 1 $ 54 $ 1 Other deferred credits and other liabilities — 4 — 4 Commodity contracts Other current assets 1 — — — Energy management contracts Prepayments — 1 — — Other current assets 3 — — — Other deferred debits and other assets 1 — — — Other current liabilities — 2 — — Total $ 59 $ 8 $ 54 $ 5 Derivatives Designated as Fair Value Hedges The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented. Derivatives in Cash Flow Hedging Relationships The effect of derivative instruments on the consolidated statements of operations is as follows: The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2018 Interest rate contracts $ 1 Interest expense $ (1 ) Year Ended December 31, 2017 Interest rate contracts $ (2 ) Interest expense $ (2 ) Year Ended December 31, 2016 Interest rate contracts — Interest expense $ (2 ) The Company: Gain (Loss) Recognized in OCI, net of tax Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2018 Interest rate contracts $ 1 Interest expense $ (9 ) Commodity contracts (3 ) Gas purchased for resale (7 ) Total $ (2 ) $ (16 ) Year Ended December 31, 2017 Interest rate contracts — Interest expense $ (7 ) Commodity contracts $ (7 ) Gas purchased for resale 1 Total $ (7 ) $ (6 ) Year Ended December 31, 2016 Interest rate contracts $ (1 ) Interest expense $ (7 ) Commodity contracts 5 Gas purchased for resale (6 ) Total $ 4 $ (13 ) As of December 31, 2018, the Company expects that during the next 12 months reclassifications from AOCI (loss) to earnings arising from cash flow hedges will include approximately $0.6 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $8.7 million as an increase to interest expense. Reclassifications related to commodity and energy management contracts are not expected to be significant. All of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2021. As of December 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $0.9 million as an increase as an increase to interest expense. Hedge Ineffectiveness For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant for all periods presented. Derivatives Not Designated as Hedging Instruments The Company and Consolidated SCE&G: Gain (Loss) Deferred in Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars Regulatory Accounts Location Amount Year Ended December 31, 2018 Interest rate contracts $ 64 Interest Expense $ (2 ) Interest rate contracts Other Income 115 Year Ended December 31, 2017 Interest rate contracts $ (32 ) Interest Expense $ (3 ) Interest rate contracts Impairment Loss (173 ) Year Ended December 31, 2016 Interest rate contracts $ (34 ) Other income $ (2 ) Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. Loss reclassified to impairment loss is included in the 2017 impairment described in Note 11. As of December 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $2.8 million as an increase to interest expense. Credit Risk Considerations Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral. Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 24.8 $ 33.7 $ 11.2 $ 14.7 Fair value of collateral already posted 24.3 28.9 11.0 10.1 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ 0.5 $ 4.8 $ 0.2 $ 4.6 in Net Asset Position Aggregate fair value of derivatives in net asset position — $ 53.5 — $ 53.5 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — $ 53.5 — $ 53.5 In addition, at December 31, 2018, the Company could not call on any letters of credit related to the $1.7 million in commodity derivatives that are in a net asset position. At December 31, 2017, the Company could have called on letters of credit in the amount of $1.2 million related to derivatives of $4.0 million if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting derivative assets follows: Derivative Assets The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 2018 Gross Amounts of Recognized Assets — $ 1 $ 13 $ 14 — Gross Amounts Offset in Statement of Financial Position — — (11 ) (11 ) — Net Amounts Presented in Statement of Financial Position — 1 2 3 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 1 $ 2 $ 3 — Balance sheet location Prepayments $ 12 — Other current assets 1 — Other deferred debits and other assets 1 — Total $ 14 — As of December 31, 2017 Gross Amounts of Recognized Assets $ 54 $ 1 $ 4 $ 59 $ 54 Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position 54 1 4 59 54 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 54 $ 1 $ 4 $ 59 $ 54 Balance sheet location Other current assets $ 58 $ 54 Other deferred debits and other assets 1 — Total $ 59 $ 54 Information related to the offsetting of derivative liabilities follows: Derivative Liabilities The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 2018 Gross Amounts of Recognized Liabilities $ 24 $ 1 $ 13 $ 38 $ 11 Gross Amounts Offset in Statement of Financial Position — — (11 ) (11 ) — Net Amounts Presented in Statement of Financial Position 24 1 2 27 11 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (24 ) — — (24 ) (11 ) Net Amount — $ 1 $ 2 $ 3 — Balance sheet location Prepayments $ 13 — Other current liabilities 3 $ 1 Other deferred credits and other liabilities 22 10 Total $ 38 $ 11 Derivative Liabilities The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 2017 Gross Amounts of Recognized Liabilities $ 32 $ 3 $ 3 $ 38 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 32 3 2 37 15 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (28 ) — (1 ) (29 ) — Net Amount $ 4 3 $ 1 $ 8 $ 15 Balance sheet location Other current assets $ 2 — Other current liabilities 7 $ 2 Other deferred credits and other liabilities 28 13 Total $ 37 $ 15
SCE&G
Derivative [Line Items]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	. DERIVATIVE FINANCIAL INSTRUMENTS Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. Policies and procedures, and in some cases risk limits, are established to control the level of market, credit, liquidity and operational and administrative risks. Historically, SCANA’s Board of Directors delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which was comprised of certain officers, apprised the Board of Directors with regard to the management of risk and brought to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions. Commodity Derivatives The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions. Cash settlements of commodity derivatives are classified as operating activities in the consolidated statements of cash flows. PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes. Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit. As an accommodation to certain customers, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives. These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes. Interest Rate Swaps Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances. In cases in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense. Forward starting swap agreements designated as cash flow hedges have been used in anticipation of the issuance of debt. Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and its nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 were not designated for accounting purposes as cash flow hedges, and fair value changes and settlement amounts related to them have been recorded as regulatory assets and liabilities. Settlement losses on swaps generally have been amortized over the lives of subsequent debt issuances, and gains have been amortized to interest expense or have been applied as otherwise directed by the SCPSC. See Note 2 and Note 15 regarding the settlement gains realized in the first quarter of 2018. Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes. Quantitative Disclosures Related to Derivatives The Company was party to natural gas derivative contracts outstanding in the following quantities: Commodity and Energy Management Contracts (in bcf) Hedge designation Gas Distribution Gas Marketing Total As of December 31, 2018 Commodity 6.4 12.9 19.3 Energy Management (a) — 46.8 46.8 Total (a) 6.4 59.7 66.1 As of December 31, 2017 Commodity 6.4 13.4 19.8 Energy Management (a) — 41.9 41.9 Total (a) 6.4 55.3 61.7 (a) Includes amounts related to basis swap contracts totaling 5.1 bcf in 2018 and 2.6 bcf in 2017. The aggregate notional amounts of the interest rate swaps were as follows: Interest Rate Swaps The Company Consolidated SCE&G Millions of dollars December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 Designated as hedging instruments $ 106.8 $ 111.2 $ 36.4 $ 36.4 Not designated as hedging instruments 35.0 735.0 35.0 735.0 The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown. Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of December 31, 2018 Designated as hedging instruments Interest rate contracts Other current liabilities — $ 2 — $ 1 Other deferred credits and other liabilities — 19 — 7 Commodity contracts Prepayments — 1 — — Total — $ 22 — $ 8 Not designated as hedging instruments Interest rate contracts Other deferred credits and other liabilities — $ 3 — $ 3 Commodity contracts Prepayments $ 1 — — — Energy management contracts Prepayments 11 12 — — Other current assets 1 — — — Other current liabilities — 1 — — Other deferred debits and other assets 1 — — — Total $ 14 $ 16 — $ 3 As of December 31, 2017 Designated as hedging instruments Interest rate contracts Other current liabilities — $ 3 — $ 1 Other deferred credits and other liabilities — 24 — 9 Commodity contracts Prepayments — 2 — — Other current liabilities — 1 — — Total — $ 30 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets and current liabilities $ 54 $ 1 $ 54 $ 1 Other deferred credits and other liabilities — 4 — 4 Commodity contracts Other current assets 1 — — — Energy management contracts Prepayments — 1 — — Other current assets 3 — — — Other deferred debits and other assets 1 — — — Other current liabilities — 2 — — Total $ 59 $ 8 $ 54 $ 5 Derivatives Designated as Fair Value Hedges The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented. Derivatives in Cash Flow Hedging Relationships The effect of derivative instruments on the consolidated statements of operations is as follows: The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2018 Interest rate contracts $ 1 Interest expense $ (1 ) Year Ended December 31, 2017 Interest rate contracts $ (2 ) Interest expense $ (2 ) Year Ended December 31, 2016 Interest rate contracts — Interest expense $ (2 ) The Company: Gain (Loss) Recognized in OCI, net of tax Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2018 Interest rate contracts $ 1 Interest expense $ (9 ) Commodity contracts (3 ) Gas purchased for resale (7 ) Total $ (2 ) $ (16 ) Year Ended December 31, 2017 Interest rate contracts — Interest expense $ (7 ) Commodity contracts $ (7 ) Gas purchased for resale 1 Total $ (7 ) $ (6 ) Year Ended December 31, 2016 Interest rate contracts $ (1 ) Interest expense $ (7 ) Commodity contracts 5 Gas purchased for resale (6 ) Total $ 4 $ (13 ) As of December 31, 2018, the Company expects that during the next 12 months reclassifications from AOCI (loss) to earnings arising from cash flow hedges will include approximately $0.6 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $8.7 million as an increase to interest expense. Reclassifications related to commodity and energy management contracts are not expected to be significant. All of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2021. As of December 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $0.9 million as an increase as an increase to interest expense. Hedge Ineffectiveness For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant for all periods presented. Derivatives Not Designated as Hedging Instruments The Company and Consolidated SCE&G: Gain (Loss) Deferred in Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars Regulatory Accounts Location Amount Year Ended December 31, 2018 Interest rate contracts $ 64 Interest Expense $ (2 ) Interest rate contracts Other Income 115 Year Ended December 31, 2017 Interest rate contracts $ (32 ) Interest Expense $ (3 ) Interest rate contracts Impairment Loss (173 ) Year Ended December 31, 2016 Interest rate contracts $ (34 ) Other income $ (2 ) Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. Loss reclassified to impairment loss is included in the 2017 impairment described in Note 11. As of December 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $2.8 million as an increase to interest expense. Credit Risk Considerations Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral. Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 24.8 $ 33.7 $ 11.2 $ 14.7 Fair value of collateral already posted 24.3 28.9 11.0 10.1 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ 0.5 $ 4.8 $ 0.2 $ 4.6 in Net Asset Position Aggregate fair value of derivatives in net asset position — $ 53.5 — $ 53.5 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — $ 53.5 — $ 53.5 In addition, at December 31, 2018, the Company could not call on any letters of credit related to the $1.7 million in commodity derivatives that are in a net asset position. At December 31, 2017, the Company could have called on letters of credit in the amount of $1.2 million related to derivatives of $4.0 million if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting derivative assets follows: Derivative Assets The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 2018 Gross Amounts of Recognized Assets — $ 1 $ 13 $ 14 — Gross Amounts Offset in Statement of Financial Position — — (11 ) (11 ) — Net Amounts Presented in Statement of Financial Position — 1 2 3 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 1 $ 2 $ 3 — Balance sheet location Prepayments $ 12 — Other current assets 1 — Other deferred debits and other assets 1 — Total $ 14 — As of December 31, 2017 Gross Amounts of Recognized Assets $ 54 $ 1 $ 4 $ 59 $ 54 Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position 54 1 4 59 54 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 54 $ 1 $ 4 $ 59 $ 54 Balance sheet location Other current assets $ 58 $ 54 Other deferred debits and other assets 1 — Total $ 59 $ 54 Information related to the offsetting of derivative liabilities follows: Derivative Liabilities The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 2018 Gross Amounts of Recognized Liabilities $ 24 $ 1 $ 13 $ 38 $ 11 Gross Amounts Offset in Statement of Financial Position — — (11 ) (11 ) — Net Amounts Presented in Statement of Financial Position 24 1 2 27 11 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (24 ) — — (24 ) (11 ) Net Amount — $ 1 $ 2 $ 3 — Balance sheet location Prepayments $ 13 — Other current liabilities 3 $ 1 Other deferred credits and other liabilities 22 10 Total $ 38 $ 11 Derivative Liabilities The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 2017 Gross Amounts of Recognized Liabilities $ 32 $ 3 $ 3 $ 38 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 32 3 2 37 15 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (28 ) — (1 ) (29 ) — Net Amount $ 4 3 $ 1 $ 8 $ 15 Balance sheet location Other current assets $ 2 — Other current liabilities 7 $ 2 Other deferred credits and other liabilities 28 13 Total $ 37 $ 15

FAIR VALUE MEASUREMENTS, INCLUD

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES	12 Months Ended
	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosures [Text Block]	. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES The Company and Consolidated SCE&G value available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, on which the securities are actively traded or are open-ended mutual funds registered with the SEC and maintain a stable NAV and are invested in government money market agreements or fully collateralized repurchase agreements. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: As of December 31, 2018 As of December 31, 2017 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 1 Level 2 Level 1 Level 2 Level 1 Level 2 Assets: Available for sale securities — — — — $ 119 — $ 100 — Held to maturity securities — $ 6 — — — $ 6 — — Interest rate contracts — — — — — 54 — $ 54 Commodity contracts $ 1 — — — 1 — — — Energy management contracts 11 2 — — — 4 — — Liabilities: Interest rate contracts — 24 — $ 11 — 32 — 15 Commodity contracts 1 — — — 2 1 — — Energy management contracts 12 3 — — 1 4 — — The Company and Consolidated SCE&G had no Level 3 fair value measurements during either period presented. Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2018 and December 31, 2017 were as follows: As of December 31, 2018 As of December 31, 2017 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,753.9 $ 7,180.8 $ 6,632.9 $ 7,399.7 Consolidated SCE&G 5,145.6 5,469.7 5,163.3 5,790.3 Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent. Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2. In connection with the impairment loss described in Note 11, the Company and Consolidated SCE&G determined that the fair value of certain of their nuclear fuel was lower than its carrying amount. At December 31, 2018, this nuclear fuel had an estimated fair value of $40.2 million. This estimate is based on quoted prices received from vendors of nuclear fuel, which are considered to be Level 3 fair value measurements. The Company and Consolidated SCE&G assess the fair value of nuclear fuel in connection with the analysis of impairment described in Note 11 on a quarterly basis.
SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosures [Text Block]	. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES The Company and Consolidated SCE&G value available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, on which the securities are actively traded or are open-ended mutual funds registered with the SEC and maintain a stable NAV and are invested in government money market agreements or fully collateralized repurchase agreements. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: As of December 31, 2018 As of December 31, 2017 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 1 Level 2 Level 1 Level 2 Level 1 Level 2 Assets: Available for sale securities — — — — $ 119 — $ 100 — Held to maturity securities — $ 6 — — — $ 6 — — Interest rate contracts — — — — — 54 — $ 54 Commodity contracts $ 1 — — — 1 — — — Energy management contracts 11 2 — — — 4 — — Liabilities: Interest rate contracts — 24 — $ 11 — 32 — 15 Commodity contracts 1 — — — 2 1 — — Energy management contracts 12 3 — — 1 4 — — The Company and Consolidated SCE&G had no Level 3 fair value measurements during either period presented. Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2018 and December 31, 2017 were as follows: As of December 31, 2018 As of December 31, 2017 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,753.9 $ 7,180.8 $ 6,632.9 $ 7,399.7 Consolidated SCE&G 5,145.6 5,469.7 5,163.3 5,790.3 Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent. Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2. In connection with the impairment loss described in Note 11, the Company and Consolidated SCE&G determined that the fair value of certain of their nuclear fuel was lower than its carrying amount. At December 31, 2018, this nuclear fuel had an estimated fair value of $40.2 million. This estimate is based on quoted prices received from vendors of nuclear fuel, which are considered to be Level 3 fair value measurements. The Company and Consolidated SCE&G assess the fair value of nuclear fuel in connection with the analysis of impairment described in Note 11 on a quarterly basis.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2018
Pension and Other Postretirement Benefit Plans
Pension and Other Postretirement Benefits Disclosure [Text Block]	EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN Pension and Other Postretirement Benefit Plans SCANA sponsors a noncontributory defined benefit pension plan covering regular, full-time employees hired before January 1, 2014. SCE&G participates in SCANA's pension plan. SCANA’s policy has been to fund the plan as permitted by applicable federal income tax regulations, as determined by an independent actuary. The pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and all eligible employees hired subsequently. Under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits. Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment. Benefits under the cash balance formula will continue to accrue through December 31, 2020, after which date no benefits will be accrued except that participants under the cash balance formula will continue to earn interest credits. Benefits under the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued. Once the benefits under SCANA's pension plan no longer accrue, eligible participants will accrue benefits under a cash balance plan sponsored by Dominion Energy. In addition to pension benefits, SCANA provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. SCE&G participates in these programs. Retirees hired before January 1, 2011 share in a portion of their medical care cost, while employees hired subsequently are responsible for the full cost of retiree medical benefits elected by them. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits. The same benefit formula applies to all SCANA subsidiaries participating in the parent sponsored plans and, with regard to the pension plan, there are no legally separate asset pools. The postretirement benefit plans are accounted for as multiple employer plans. Changes in Benefit Obligations The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below. The Company Consolidated SCE&G Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2018 2017 2018 2017 2018 2017 Benefit obligation, January 1 $ 933.2 $ 904.3 $ 289.2 $ 274.7 $ 793.0 $ 768.4 $ 216.6 $ 207.2 Service cost 21.0 21.7 4.6 4.5 17.1 18.1 3.6 3.7 Interest cost 34.1 37.4 10.1 11.5 29.0 31.9 8.0 9.5 Plan participants’ contributions — — 1.4 1.3 — — 1.1 1.1 Actuarial (gain) loss (53.1 ) 42.2 (38.4 ) 9.7 (45.5 ) 36.6 (30.7 ) 6.8 Benefits paid (71.7 ) (72.4 ) (13.2 ) (12.5 ) (61.3 ) (62.0 ) (10.4 ) (10.3 ) Amounts funded to parent n/a n/a n/a n/a — — (0.8 ) (1.4 ) Benefit obligation, December 31 $ 863.5 $ 933.2 $ 253.7 $ 289.2 $ 732.3 $ 793.0 $ 187.4 $ 216.6 The accumulated benefit obligation for pension benefits for the Company was $ 842.4 million at the end of 2018 and $ 905.8 million at the end of 2017. The accumulated benefit obligation for pension benefits for Consolidated SCE&G was $714.3 million at the end of 2018 and $769.7 million at the end of 2017. The accumulated pension benefit obligation differs from the projected pension benefit obligation above in that it reflects no assumptions about future compensation levels. Significant assumptions used to determine the above benefit obligations are as follows: Pension Benefits Other Postretirement Benefits 2018 2017 2018 2017 Annual discount rate used to determine benefit obligation 4.35 % 3.71 % 4.38 % 3.74 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 % A 6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018. The rate was assumed to decrease gradually to 5.0% for 2023 and to remain at that level thereafter. A one percent increase in the assumed health care cost trend rate for the Company would increase the postretirement benefit obligation by $0.7 million at December 31, 2018 and by $1.6 million at December 31, 2017. A one percent decrease in the assumed health care cost trend rate for the Company would decrease the postretirement benefit obligation by $0.6 million at December 31, 2018 and by $1.4 million at December 31, 2017. A one percent increase in the assumed health care cost trend rate for Consolidated SCE&G would increase the postretirement benefit obligation by $0.6 million at December 31, 2018 and by $1.3 million at December 31, 2017. A one percent decrease in the assumed health care cost trend rate for Consolidated SCE&G would decrease the postretirement benefit obligation by $0.5 million at December 31, 2018 and by $1.1 million at December 31, 2017. Funded Status The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Fair value of plan assets $ 727.3 $ 849.6 — — $ 676.7 $ 781.3 — — Benefit obligation 863.5 933.2 $ 253.7 $ 289.2 732.3 793.0 $ 187.4 $ 216.6 Funded status $ (136.2 ) $ (83.6 ) $ (253.7 ) $ (289.2 ) $ (55.6 ) $ (11.7 ) $ (187.4 ) $ (216.6 ) Amounts recognized on the consolidated balance sheets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Current liability — — $ (13.3 ) $ (13.5 ) — — $ (10.5 ) $ (10.8 ) Noncurrent liability $ (136.2 ) $ (83.6 ) (240.4 ) (275.7 ) $ (55.6 ) $ (11.7 ) (176.9 ) (205.8 ) Amounts recognized in accumulated other comprehensive loss were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Net actuarial loss $ 12.8 $ 8.8 $ 1.1 $ 3.5 $ 3.4 $ 2.1 $ 0.5 $ 1.5 Prior service cost 0.1 0.1 — — — — — — Total $ 12.9 $ 8.9 $ 1.1 $ 3.5 $ 3.4 $ 2.1 $ 0.5 $ 1.5 Amounts recognized in regulatory assets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Net actuarial loss $ 230.4 $ 194.8 $ 10.9 $ 43.3 $ 202.4 $ 171.4 $ 9.0 $ 35.9 Prior service cost 0.7 1.2 — — 0.6 1.0 — — Total $ 231.1 $ 196.0 $ 10.9 $ 43.3 $ 203.0 $ 172.4 $ 9.0 $ 35.9 In connection with the joint ownership of Summer Station, costs related to the pension benefit obligation attributable to Santee Cooper as of December 31, 2018 and 2017 totaled $24.9 million and $21.4 million, respectively, and were recorded within deferred debits. The unfunded postretirement benefit obligation attributable to Santee Cooper as of December 31, 2018 and 2017 totaled $12.4 million and $14.7 million, respectively, and was recorded within deferred debits. Changes in Fair Value of Plan Assets Pension Benefits The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Fair value of plan assets, January 1 $ 849.6 $ 793.6 $ 781.3 $ 732.9 Actual return (loss) on plan assets (50.6 ) 128.4 (43.3 ) 110.4 Benefits paid (71.7 ) (72.4 ) (61.3 ) (62.0 ) Fair value of plan assets, December 31 $ 727.3 $ 849.6 $ 676.7 $ 781.3 Investment Policies and Strategies The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the obligations of the pension plan, (2) overseeing the plan's investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and liabilities, and overall risk associated with assets as compared to liabilities, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. SCANA uses a dynamic investment strategy for the management of the pension plan assets. This strategy will lead to a reduction in equities and an increase in long duration fixed income allocations over time with the intention of reducing volatility of funded status and pension costs. The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, levels of diversification, investment managers and performance expectations. The total portfolio is constructed and maintained to provide prudent diversification with regard to the concentration of holdings in individual issues, corporations, or industries. Transactions involving certain types of investments are prohibited. These include, except where utilized by a hedge fund manager, any form of private equity; commodities or commodity contracts (except for unleveraged stock or bond index futures and currency futures and options); ownership of real estate in any form other than publicly traded securities; short sales, warrants or margin transactions, or any leveraged investments; and natural resource properties. Investments made for the purpose of engaging in speculative trading are also prohibited. The pension plan asset allocation at December 31, 2018 and 2017 and the target allocation for 2019 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2019 2018 2017 Equity Securities 58 % 55 % 58 % Fixed Income 33 % 34 % 31 % Hedge Funds 9 % 11 % 11 % For 2019, the expected long-term rate of return on assets will be 7% . In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, considers the expected active and passive returns across various asset classes and assumes the target allocation is achieved. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment strategy described previously. Fair Value Measurements Assets held by the pension plan are measured at fair value and are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2018 and 2017, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Investments with fair value measure at Level 2: Mutual funds $ 107 $ 120 $ 99 $ 110 Short-term investment vehicles 20 17 19 16 US Treasury securities 7 15 7 14 Corporate debt instruments 92 91 86 84 Government and other debt instruments 18 17 16 15 Total assets in the fair value hierarchy 244 260 227 239 Investments at net asset value: Common collective trust 400 498 373 458 Joint venture interests 83 92 77 84 Total investments at fair value $ 727 $ 850 $ 677 $ 781 For all periods presented, assets with fair value measurements classified as Level 1 were insignificant, and there were no assets with fair value measurements classified as Level 3. There were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during 2018 or 2017. Mutual funds held by the plan are open-end mutual funds registered with the SEC. The price of the mutual funds' shares is based on its NAV, which is determined by dividing the total value of portfolio investments, less any liabilities, by the total number of shares outstanding. For purposes of calculating NAV, portfolio securities and other assets for which market quotes are readily available are valued at market value. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. US Treasury securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt instruments and government and other debt instruments are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Common collective trust assets and limited partnerships are valued at NAV, which has been determined based on the unit values of the trust funds. Unit values are determined by the organization sponsoring such trust funds by dividing the trust funds’ net assets at fair value by the units outstanding at each valuation date. Joint venture interests are invested in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and not traded on a daily basis. The valuation of such multi-strategy hedge fund of funds is estimated based on the NAV of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may influence their fair value. Expected Cash Flows Total benefits expected to be paid from the pension plan or company assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows: Expected Benefit Payments The Company Consolidated SCE&G Millions of dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits 2019 $ 71.5 $ 13.6 $ 71.5 $ 10.8 2020 62.4 14.3 62.4 11.4 2021 65.6 14.9 65.6 11.8 2022 69.6 15.4 69.6 12.2 2023 66.6 15.8 66.6 12.6 2024-2028 284.9 82.3 284.9 65.4 Pension Plan Contributions The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and as a result of closing the plan to new entrants and freezing benefit accruals at the end of 2023, no significant contributions to the pension trust are expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply. Net Periodic Benefit Cost Net periodic benefit cost is recorded utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables. Components of Net Periodic Benefit Cost The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Service cost $ 21.0 $ 21.7 $ 20.7 $ 4.6 $ 4.5 $ 4.4 Interest cost 34.1 37.4 39.4 10.1 11.5 12.1 Expected return on assets (56.7 ) (54.7 ) (55.9 ) n/a n/a n/a Prior service cost amortization 0.5 1.6 3.9 — — 0.3 Amortization of actuarial losses 12.8 16.3 14.8 0.7 1.0 0.5 Net periodic benefit cost $ 11.7 $ 22.3 $ 22.9 $ 15.4 $ 17.0 $ 17.3 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Service cost $ 17.1 $ 18.1 $ 16.9 $ 3.6 $ 3.7 $ 3.6 Interest cost 29.0 31.9 33.4 8.0 9.5 9.9 Expected return on assets (48.1 ) (46.7 ) (47.4 ) n/a n/a n/a Prior service cost amortization 0.4 1.4 3.4 — — 0.3 Amortization of actuarial losses 10.9 13.9 12.5 0.6 0.8 0.4 Net periodic benefit cost $ 9.3 $ 18.6 $ 18.8 $ 12.2 $ 14.0 $ 14.2 In connection with regulatory orders, SCE&G recovers current pension costs through a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. PSNC Energy recovers pension costs through cost of service rates. For retail electric operations, current pension expense is recognized based on amounts collected through a rate rider, and differences between actual pension expense and amounts recognized pursuant to the rider are deferred as a regulatory asset (for under-collections) or regulatory liability (for over-collections) as applicable. In addition, SCE&G amortizes certain previously deferred pension costs. See Note 2. Other changes in plan assets and benefit obligations recognized in OCI (net of tax) were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Current year actuarial (gain) loss $ 4.5 $ (1.0 ) $ 0.6 $ (2.4 ) $ 1.1 $ 0.8 Amortization of actuarial losses (0.5 ) (0.6 ) (0.6 ) — (0.1 ) — Amortization of prior service cost — — (0.1 ) — — — Total recognized in OCI $ 4.0 $ (1.6 ) $ (0.1 ) $ (2.4 ) $ 1.0 $ 0.8 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Current year actuarial loss $ 1.4 $ 0.3 — $ (1.0 ) $ 0.5 $ 0.3 Amortization of actuarial losses (0.1 ) (0.1 ) $ (0.1 ) — — — Total recognized in OCI $ 1.3 $ 0.2 $ (0.1 ) $ (1.0 ) $ 0.5 $ 0.3 Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Current year actuarial (gain) loss $ 46.7 $ (27.1 ) $ 29.4 $ (31.8 ) $ 9.4 $ 11.1 Amortization of actuarial losses (11.1 ) (14.1 ) (12.7 ) (0.6 ) (0.8 ) (0.4 ) Amortization of prior service cost (0.5 ) (1.4 ) (3.4 ) — — (0.3 ) Total recognized in regulatory assets $ 35.1 $ (42.6 ) $ 13.3 $ (32.4 ) $ 8.6 $ 10.4 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Current year actuarial (gain) loss $ 40.7 $ (24.8 ) $ 26.3 $ (26.4 ) $ 7.3 $ 9.2 Amortization of actuarial losses (9.7 ) (12.5 ) (11.2 ) (0.5 ) (0.7 ) (0.3 ) Amortization of prior service cost (0.4 ) (1.3 ) (3.0 ) — — (0.2 ) Total recognized in regulatory assets $ 30.6 $ (38.6 ) $ 12.1 $ (26.9 ) $ 6.6 $ 8.7 Significant Assumptions Used in Determining Net Periodic Benefit Cost Pension Benefits Other Postretirement Benefits 2018 2017 2016 2018 2017 2016 Discount rate 3.71 % 4.22 % 4.68 % 3.74 % 4.30 % 4.78 % Expected return on plan assets 7.00 % 7.25 % 7.50 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % Health care cost trend rate n/a n/a n/a 7.00 % 6.60 % 7.00 % Ultimate health care cost trend rate n/a n/a n/a 5.00 % 5.00 % 5.00 % Year achieved n/a n/a n/a 2023 2021 2021 The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2019 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant : Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 0.8 — The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2019 are as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Actuarial loss $ 14.7 — $ 12.9 — Prior service cost 0.3 — 0.3 — Total $ 15.0 — $ 13.2 — Other postretirement benefit costs are subject to annual per capita limits pursuant to the plan's design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is not significant. 401(k) Retirement Savings Plan SCANA sponsors a defined contribution plan in which eligible employees may defer up to 75% of eligible earnings subject to certain limits and may diversify their investments. SCE&G participates in this plan. Contributions are matched 100% up to 6% of an employee’s eligible earnings. Such matching contributions made by the Company totaled $24.1 million in 2018, $27.9 million in 2017 and $27.5 million in 2016. These matching contributions included those made by Consolidated SCE&G, which totaled $19.6 million in 2018, $23.4 million in 2017 and $22.9 million in 2016. Employee deferrals, matching contributions, and earnings on all contributions are fully vested and non-forfeitable at all times.
SCE&G
Pension and Other Postretirement Benefit Plans
Pension and Other Postretirement Benefits Disclosure [Text Block]	EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN Pension and Other Postretirement Benefit Plans SCANA sponsors a noncontributory defined benefit pension plan covering regular, full-time employees hired before January 1, 2014. SCE&G participates in SCANA's pension plan. SCANA’s policy has been to fund the plan as permitted by applicable federal income tax regulations, as determined by an independent actuary. The pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and all eligible employees hired subsequently. Under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits. Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment. Benefits under the cash balance formula will continue to accrue through December 31, 2020, after which date no benefits will be accrued except that participants under the cash balance formula will continue to earn interest credits. Benefits under the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued. Once the benefits under SCANA's pension plan no longer accrue, eligible participants will accrue benefits under a cash balance plan sponsored by Dominion Energy. In addition to pension benefits, SCANA provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. SCE&G participates in these programs. Retirees hired before January 1, 2011 share in a portion of their medical care cost, while employees hired subsequently are responsible for the full cost of retiree medical benefits elected by them. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits. The same benefit formula applies to all SCANA subsidiaries participating in the parent sponsored plans and, with regard to the pension plan, there are no legally separate asset pools. The postretirement benefit plans are accounted for as multiple employer plans. Changes in Benefit Obligations The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below. The Company Consolidated SCE&G Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2018 2017 2018 2017 2018 2017 Benefit obligation, January 1 $ 933.2 $ 904.3 $ 289.2 $ 274.7 $ 793.0 $ 768.4 $ 216.6 $ 207.2 Service cost 21.0 21.7 4.6 4.5 17.1 18.1 3.6 3.7 Interest cost 34.1 37.4 10.1 11.5 29.0 31.9 8.0 9.5 Plan participants’ contributions — — 1.4 1.3 — — 1.1 1.1 Actuarial (gain) loss (53.1 ) 42.2 (38.4 ) 9.7 (45.5 ) 36.6 (30.7 ) 6.8 Benefits paid (71.7 ) (72.4 ) (13.2 ) (12.5 ) (61.3 ) (62.0 ) (10.4 ) (10.3 ) Amounts funded to parent n/a n/a n/a n/a — — (0.8 ) (1.4 ) Benefit obligation, December 31 $ 863.5 $ 933.2 $ 253.7 $ 289.2 $ 732.3 $ 793.0 $ 187.4 $ 216.6 The accumulated benefit obligation for pension benefits for the Company was $ 842.4 million at the end of 2018 and $ 905.8 million at the end of 2017. The accumulated benefit obligation for pension benefits for Consolidated SCE&G was $714.3 million at the end of 2018 and $769.7 million at the end of 2017. The accumulated pension benefit obligation differs from the projected pension benefit obligation above in that it reflects no assumptions about future compensation levels. Significant assumptions used to determine the above benefit obligations are as follows: Pension Benefits Other Postretirement Benefits 2018 2017 2018 2017 Annual discount rate used to determine benefit obligation 4.35 % 3.71 % 4.38 % 3.74 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 % A 6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018. The rate was assumed to decrease gradually to 5.0% for 2023 and to remain at that level thereafter. A one percent increase in the assumed health care cost trend rate for the Company would increase the postretirement benefit obligation by $0.7 million at December 31, 2018 and by $1.6 million at December 31, 2017. A one percent decrease in the assumed health care cost trend rate for the Company would decrease the postretirement benefit obligation by $0.6 million at December 31, 2018 and by $1.4 million at December 31, 2017. A one percent increase in the assumed health care cost trend rate for Consolidated SCE&G would increase the postretirement benefit obligation by $0.6 million at December 31, 2018 and by $1.3 million at December 31, 2017. A one percent decrease in the assumed health care cost trend rate for Consolidated SCE&G would decrease the postretirement benefit obligation by $0.5 million at December 31, 2018 and by $1.1 million at December 31, 2017. Funded Status The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Fair value of plan assets $ 727.3 $ 849.6 — — $ 676.7 $ 781.3 — — Benefit obligation 863.5 933.2 $ 253.7 $ 289.2 732.3 793.0 $ 187.4 $ 216.6 Funded status $ (136.2 ) $ (83.6 ) $ (253.7 ) $ (289.2 ) $ (55.6 ) $ (11.7 ) $ (187.4 ) $ (216.6 ) Amounts recognized on the consolidated balance sheets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Current liability — — $ (13.3 ) $ (13.5 ) — — $ (10.5 ) $ (10.8 ) Noncurrent liability $ (136.2 ) $ (83.6 ) (240.4 ) (275.7 ) $ (55.6 ) $ (11.7 ) (176.9 ) (205.8 ) Amounts recognized in accumulated other comprehensive loss were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Net actuarial loss $ 12.8 $ 8.8 $ 1.1 $ 3.5 $ 3.4 $ 2.1 $ 0.5 $ 1.5 Prior service cost 0.1 0.1 — — — — — — Total $ 12.9 $ 8.9 $ 1.1 $ 3.5 $ 3.4 $ 2.1 $ 0.5 $ 1.5 Amounts recognized in regulatory assets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Net actuarial loss $ 230.4 $ 194.8 $ 10.9 $ 43.3 $ 202.4 $ 171.4 $ 9.0 $ 35.9 Prior service cost 0.7 1.2 — — 0.6 1.0 — — Total $ 231.1 $ 196.0 $ 10.9 $ 43.3 $ 203.0 $ 172.4 $ 9.0 $ 35.9 In connection with the joint ownership of Summer Station, costs related to the pension benefit obligation attributable to Santee Cooper as of December 31, 2018 and 2017 totaled $24.9 million and $21.4 million, respectively, and were recorded within deferred debits. The unfunded postretirement benefit obligation attributable to Santee Cooper as of December 31, 2018 and 2017 totaled $12.4 million and $14.7 million, respectively, and was recorded within deferred debits. Changes in Fair Value of Plan Assets Pension Benefits The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Fair value of plan assets, January 1 $ 849.6 $ 793.6 $ 781.3 $ 732.9 Actual return (loss) on plan assets (50.6 ) 128.4 (43.3 ) 110.4 Benefits paid (71.7 ) (72.4 ) (61.3 ) (62.0 ) Fair value of plan assets, December 31 $ 727.3 $ 849.6 $ 676.7 $ 781.3 Investment Policies and Strategies The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the obligations of the pension plan, (2) overseeing the plan's investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and liabilities, and overall risk associated with assets as compared to liabilities, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. SCANA uses a dynamic investment strategy for the management of the pension plan assets. This strategy will lead to a reduction in equities and an increase in long duration fixed income allocations over time with the intention of reducing volatility of funded status and pension costs. The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, levels of diversification, investment managers and performance expectations. The total portfolio is constructed and maintained to provide prudent diversification with regard to the concentration of holdings in individual issues, corporations, or industries. Transactions involving certain types of investments are prohibited. These include, except where utilized by a hedge fund manager, any form of private equity; commodities or commodity contracts (except for unleveraged stock or bond index futures and currency futures and options); ownership of real estate in any form other than publicly traded securities; short sales, warrants or margin transactions, or any leveraged investments; and natural resource properties. Investments made for the purpose of engaging in speculative trading are also prohibited. The pension plan asset allocation at December 31, 2018 and 2017 and the target allocation for 2019 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2019 2018 2017 Equity Securities 58 % 55 % 58 % Fixed Income 33 % 34 % 31 % Hedge Funds 9 % 11 % 11 % For 2019, the expected long-term rate of return on assets will be 7% . In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, considers the expected active and passive returns across various asset classes and assumes the target allocation is achieved. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment strategy described previously. Fair Value Measurements Assets held by the pension plan are measured at fair value and are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2018 and 2017, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Investments with fair value measure at Level 2: Mutual funds $ 107 $ 120 $ 99 $ 110 Short-term investment vehicles 20 17 19 16 US Treasury securities 7 15 7 14 Corporate debt instruments 92 91 86 84 Government and other debt instruments 18 17 16 15 Total assets in the fair value hierarchy 244 260 227 239 Investments at net asset value: Common collective trust 400 498 373 458 Joint venture interests 83 92 77 84 Total investments at fair value $ 727 $ 850 $ 677 $ 781 For all periods presented, assets with fair value measurements classified as Level 1 were insignificant, and there were no assets with fair value measurements classified as Level 3. There were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during 2018 or 2017. Mutual funds held by the plan are open-end mutual funds registered with the SEC. The price of the mutual funds' shares is based on its NAV, which is determined by dividing the total value of portfolio investments, less any liabilities, by the total number of shares outstanding. For purposes of calculating NAV, portfolio securities and other assets for which market quotes are readily available are valued at market value. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. US Treasury securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt instruments and government and other debt instruments are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Common collective trust assets and limited partnerships are valued at NAV, which has been determined based on the unit values of the trust funds. Unit values are determined by the organization sponsoring such trust funds by dividing the trust funds’ net assets at fair value by the units outstanding at each valuation date. Joint venture interests are invested in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and not traded on a daily basis. The valuation of such multi-strategy hedge fund of funds is estimated based on the NAV of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may influence their fair value. Expected Cash Flows Total benefits expected to be paid from the pension plan or company assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows: Expected Benefit Payments The Company Consolidated SCE&G Millions of dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits 2019 $ 71.5 $ 13.6 $ 71.5 $ 10.8 2020 62.4 14.3 62.4 11.4 2021 65.6 14.9 65.6 11.8 2022 69.6 15.4 69.6 12.2 2023 66.6 15.8 66.6 12.6 2024-2028 284.9 82.3 284.9 65.4 Pension Plan Contributions The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and as a result of closing the plan to new entrants and freezing benefit accruals at the end of 2023, no significant contributions to the pension trust are expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply. Net Periodic Benefit Cost Net periodic benefit cost is recorded utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables. Components of Net Periodic Benefit Cost The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Service cost $ 21.0 $ 21.7 $ 20.7 $ 4.6 $ 4.5 $ 4.4 Interest cost 34.1 37.4 39.4 10.1 11.5 12.1 Expected return on assets (56.7 ) (54.7 ) (55.9 ) n/a n/a n/a Prior service cost amortization 0.5 1.6 3.9 — — 0.3 Amortization of actuarial losses 12.8 16.3 14.8 0.7 1.0 0.5 Net periodic benefit cost $ 11.7 $ 22.3 $ 22.9 $ 15.4 $ 17.0 $ 17.3 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Service cost $ 17.1 $ 18.1 $ 16.9 $ 3.6 $ 3.7 $ 3.6 Interest cost 29.0 31.9 33.4 8.0 9.5 9.9 Expected return on assets (48.1 ) (46.7 ) (47.4 ) n/a n/a n/a Prior service cost amortization 0.4 1.4 3.4 — — 0.3 Amortization of actuarial losses 10.9 13.9 12.5 0.6 0.8 0.4 Net periodic benefit cost $ 9.3 $ 18.6 $ 18.8 $ 12.2 $ 14.0 $ 14.2 In connection with regulatory orders, SCE&G recovers current pension costs through a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. PSNC Energy recovers pension costs through cost of service rates. For retail electric operations, current pension expense is recognized based on amounts collected through a rate rider, and differences between actual pension expense and amounts recognized pursuant to the rider are deferred as a regulatory asset (for under-collections) or regulatory liability (for over-collections) as applicable. In addition, SCE&G amortizes certain previously deferred pension costs. See Note 2. Other changes in plan assets and benefit obligations recognized in OCI (net of tax) were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Current year actuarial (gain) loss $ 4.5 $ (1.0 ) $ 0.6 $ (2.4 ) $ 1.1 $ 0.8 Amortization of actuarial losses (0.5 ) (0.6 ) (0.6 ) — (0.1 ) — Amortization of prior service cost — — (0.1 ) — — — Total recognized in OCI $ 4.0 $ (1.6 ) $ (0.1 ) $ (2.4 ) $ 1.0 $ 0.8 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Current year actuarial loss $ 1.4 $ 0.3 — $ (1.0 ) $ 0.5 $ 0.3 Amortization of actuarial losses (0.1 ) (0.1 ) $ (0.1 ) — — — Total recognized in OCI $ 1.3 $ 0.2 $ (0.1 ) $ (1.0 ) $ 0.5 $ 0.3 Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Current year actuarial (gain) loss $ 46.7 $ (27.1 ) $ 29.4 $ (31.8 ) $ 9.4 $ 11.1 Amortization of actuarial losses (11.1 ) (14.1 ) (12.7 ) (0.6 ) (0.8 ) (0.4 ) Amortization of prior service cost (0.5 ) (1.4 ) (3.4 ) — — (0.3 ) Total recognized in regulatory assets $ 35.1 $ (42.6 ) $ 13.3 $ (32.4 ) $ 8.6 $ 10.4 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Current year actuarial (gain) loss $ 40.7 $ (24.8 ) $ 26.3 $ (26.4 ) $ 7.3 $ 9.2 Amortization of actuarial losses (9.7 ) (12.5 ) (11.2 ) (0.5 ) (0.7 ) (0.3 ) Amortization of prior service cost (0.4 ) (1.3 ) (3.0 ) — — (0.2 ) Total recognized in regulatory assets $ 30.6 $ (38.6 ) $ 12.1 $ (26.9 ) $ 6.6 $ 8.7 Significant Assumptions Used in Determining Net Periodic Benefit Cost Pension Benefits Other Postretirement Benefits 2018 2017 2016 2018 2017 2016 Discount rate 3.71 % 4.22 % 4.68 % 3.74 % 4.30 % 4.78 % Expected return on plan assets 7.00 % 7.25 % 7.50 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % Health care cost trend rate n/a n/a n/a 7.00 % 6.60 % 7.00 % Ultimate health care cost trend rate n/a n/a n/a 5.00 % 5.00 % 5.00 % Year achieved n/a n/a n/a 2023 2021 2021 The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2019 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant : Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 0.8 — The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2019 are as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Actuarial loss $ 14.7 — $ 12.9 — Prior service cost 0.3 — 0.3 — Total $ 15.0 — $ 13.2 — Other postretirement benefit costs are subject to annual per capita limits pursuant to the plan's design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is not significant. 401(k) Retirement Savings Plan SCANA sponsors a defined contribution plan in which eligible employees may defer up to 75% of eligible earnings subject to certain limits and may diversify their investments. SCE&G participates in this plan. Contributions are matched 100% up to 6% of an employee’s eligible earnings. Such matching contributions made by the Company totaled $24.1 million in 2018, $27.9 million in 2017 and $27.5 million in 2016. These matching contributions included those made by Consolidated SCE&G, which totaled $19.6 million in 2018, $23.4 million in 2017 and $22.9 million in 2016. Employee deferrals, matching contributions, and earnings on all contributions are fully vested and non-forfeitable at all times.

SHARE-BASED COMPENSATION

SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2018
Share-Based Compensation
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	SHARE-BASED COMPENSATION The LTECP provided for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The LTECP authorized the issuance of up to five million shares of SCANA’s common stock, no more than one million of which could be granted in the form of restricted stock. Compensation cost was measured based on the grant-date fair value of the instruments issued and was recognized over the period that an employee provided service in exchange for the award. Share-based payment awards did not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves did not vest, dividends or dividend equivalents which would have been paid on those awards did not vest. For all periods presented, performance cycles provided for performance measurement and award determination based on performance over a single three -year cycle, with payment of awards being deferred until after the end of the three -year performance cycle. In each of these performance cycles, 30% of the performance awards were granted in the form of restricted share units, which were liability awards payable in cash, and 70% of the awards were granted in performance shares, each of which had a value equal to, and changed with, the value of a share of SCANA common stock. Dividend equivalents were accrued on the performance shares and the restricted share units. Performance awards and related dividend equivalents were subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to certain exceptions. Payouts of performance share awards were determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50% ) and growth in GAAP-adjusted net earnings per share (weighted 50% ). Compensation cost of liability awards was recognized over their respective three -year performance periods based on the estimated fair value of the award, which was periodically updated based on expected ultimate cash payout, and was reduced by estimated forfeitures. Cash-settled liabilities related to performance cycles totaled approximately $ 5.5 million in 2018, $ 28.0 million in 2017 and $ 18.4 million in 2016 for the Company and approximately $ 3.5 million in 2018, $ 20.2 million in 2017 and $ 13.2 million in 2016 for Consolidated SCE&G. Fair value adjustments for all performance cycles resulted in compensation expense (benefit) recognized in the statements of operations totaling approximately $ (1.7) million in 2018, $ (9.0) million in 2017 and $ 25.6 million in 2016 for the Company and approximately $ (0.9) million in 2018, $ (6.3) million in 2017 and $ 17.3 million in 2016 for Consolidated SCE&G (including amounts allocated from SCANA Services). Such fair value adjustments also resulted in no capitalized compensation costs in 2018, $ (1.3) million in 2017 and $ 3.3 million in 2016 for the Company and no capitalized compensation costs in 2018, $ (0.9) million in 2017 and $ 3.1 million in 2016 for Consolidated SCE&G. In connection with the SCANA Combination, effective January 1, 2019, all grants discussed above were deemed to be vested at their target levels and were converted into the right to receive lump sum amounts based on the value of Dominion Energy stock at that time. As such, additional compensation cost of $28.6 million will be recorded in the first quarter of 2019 as a result of the merger. Related cash-settlement payments totaling $19.6 million were made in January 2019, and further lump sum amounts of $6.7 million and $9.1 million are expected to be paid in 2020 and 2021, respectively, to the extent that those later payments are not accelerated in connection with employee retirements or other separations prior to those dates.
SCE&G
Share-Based Compensation
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	. SHARE-BASED COMPENSATION The LTECP provided for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The LTECP authorized the issuance of up to five million shares of SCANA’s common stock, no more than one million of which could be granted in the form of restricted stock. Compensation cost was measured based on the grant-date fair value of the instruments issued and was recognized over the period that an employee provided service in exchange for the award. Share-based payment awards did not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves did not vest, dividends or dividend equivalents which would have been paid on those awards did not vest. For all periods presented, performance cycles provided for performance measurement and award determination based on performance over a single three -year cycle, with payment of awards being deferred until after the end of the three -year performance cycle. In each of these performance cycles, 30% of the performance awards were granted in the form of restricted share units, which were liability awards payable in cash, and 70% of the awards were granted in performance shares, each of which had a value equal to, and changed with, the value of a share of SCANA common stock. Dividend equivalents were accrued on the performance shares and the restricted share units. Performance awards and related dividend equivalents were subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to certain exceptions. Payouts of performance share awards were determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50% ) and growth in GAAP-adjusted net earnings per share (weighted 50% ). Compensation cost of liability awards was recognized over their respective three -year performance periods based on the estimated fair value of the award, which was periodically updated based on expected ultimate cash payout, and was reduced by estimated forfeitures. Cash-settled liabilities related to performance cycles totaled approximately $ 5.5 million in 2018, $ 28.0 million in 2017 and $ 18.4 million in 2016 for the Company and approximately $ 3.5 million in 2018, $ 20.2 million in 2017 and $ 13.2 million in 2016 for Consolidated SCE&G. Fair value adjustments for all performance cycles resulted in compensation expense (benefit) recognized in the statements of operations totaling approximately $ (1.7) million in 2018, $ (9.0) million in 2017 and $ 25.6 million in 2016 for the Company and approximately $ (0.9) million in 2018, $ (6.3) million in 2017 and $ 17.3 million in 2016 for Consolidated SCE&G (including amounts allocated from SCANA Services). Such fair value adjustments also resulted in no capitalized compensation costs in 2018, $ (1.3) million in 2017 and $ 3.3 million in 2016 for the Company and no capitalized compensation costs in 2018, $ (0.9) million in 2017 and $ 3.1 million in 2016 for Consolidated SCE&G. In connection with the SCANA Combination, effective January 1, 2019, all grants discussed above were deemed to be vested at their target levels and were converted into the right to receive lump sum amounts based on the value of Dominion Energy stock at that time. As such, additional compensation cost of $28.6 million will be recorded in the first quarter of 2019 as a result of the merger. Related cash-settlement payments totaling $19.6 million were made in January 2019, and further lump sum amounts of $6.7 million and $9.1 million are expected to be paid in 2020 and 2021, respectively, to the extent that those later payments are not accelerated in connection with employee retirements or other separations prior to those dates.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2018
Commitment [Line Items]
Legal Matters and Contingencies [Text Block]	COMMITMENTS AND CONTINGENCIES Abandoned Nuclear Project SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. SCE&G's ownership share in these units is 55% . Various difficulties were encountered in connection with the project. The ability of the Consortium to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters preceded the filing for bankruptcy protection by the Consortium on March 29, 2017 (see Contractor Bankruptcy Proceedings and Related Uncertainties below), and were the subject of comprehensive analyses performed by the Company and Santee Cooper. Based on the results of the Company's analysis, and in light of Santee Cooper's decision to suspend construction on Unit 2 and Unit 3, on July 31, 2017, the Company determined to stop the construction of the units and to pursue recovery of costs incurred in connection with the construction under the abandonment provisions of the BLRA or through other means. This decision by the Company became the focus of numerous legislative, regulatory and legal proceedings, and led to SCE&G recording pre-tax impairment charges in 2017 totaling approximately $1.118 billion (approximately $690 million net of tax). An additional pre-tax impairment loss was recorded in the first quarter of 2018 of approximately $3.6 million (approximately $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. See further discussion below under Impairment Considerations . These proceedings continued in 2018, and some of them remain unresolved and are described below and/or in Claims and Litigation. On January 2, 2018, SCANA and Dominion Energy entered into the Merger Agreement and sought the consents and approvals from governmental entities and the shareholders of SCANA required to consummate the merger. After all consents and approvals were obtained, the SCANA Combination was effective January 1, 2019. Merger Approval Order On December 21, 2018, the SCPSC issued the Merger Approval Order. The order adopted Dominion Energy's Plan-B Levelized Customer Benefits Plan whereby the average bill for an SCE&G residential electric customer would approximate that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the SCPSC in August 2018. Among other things, the order also sets forth the following findings and merger conditions: • No capital costs related to the Nuclear Project incurred after March 12, 2015 will be recoverable by SCE&G, which results in rate base associated with the Nuclear Project of $2.768 billion after recording an impairment charge of $1.372 billion (pre-tax, and incremental to impairment losses recorded in 2017). • SCE&G will provide refunds and restitution to customers from prior years' revenues totaling an aggregate $2.039 billion , comprised of $1.032 billion to be credited to customers over 20 years and $1.007 billion credited to customers over approximately 11 years. These refunds include amounts to be refunded to customers related to the monetization of guaranty settlement described in Note 2. • Except for rate adjustments for fuel and environmental costs, demand side management costs, and other rates routinely adjusted on an annual or biannual basis, SCE&G will freeze retail electric base rates at current levels until January 1, 2021. • SCE&G's natural gas customers will receive refunds totaling $2.45 million in 2019, 2020 and 2021 combined. • Corporate giving will increase by $1 million per year for at least five years above historical levels. • SCE&G will not seek to pass on to ratepayers its initial capital investment in CEC, a 540-MW combined-cycle natural gas-fired generating facility, and will not seek to pass on to ratepayers any acquisition premium costs, transition costs, or transaction cost associated with the merger. SCE&G's decision to not seek recovery of the initial capital investment in CEC was included in the determination of impairment charges recorded in 2017. In addition, the SCPSC order approved the removal of SCE&G's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of December 31, 2018, such investment in these assets included approximately $367 million within utility plant, net and approximately $15 million within regulatory assets, which amount represents certain deferred operating costs. The SCPSC also approved deferral of certain operating costs related to the investment. Recovery of the transmission capital costs and associated deferred operating costs will be addressed in a future rate proceeding. Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. On February 12, 2019, the SCPSC issued a ruling (1) finding that SCE&G was imprudent in its actions by not disclosing material information to the ORS and the SCPSC, and (2) denying the petitions for rehearing or reconsideration as to other issues raised in the various petitions. The Merger Approval Order and the ruling are subject to appeal by various parties. The Company and Consolidated SCE&G cannot predict the outcome of these matters. Contractor Bankruptcy Proceedings and Related Uncertainties On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the Nuclear Project and similar units being built for an unaffiliated company as a material factor that caused WEC and WECTEC to seek protection under the bankruptcy laws. As part of such filing, WEC and WECTEC publicly announced their inability to complete Unit 2 and Unit 3 under the terms of the EPC Contract. On September 1, 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of WEC and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by the Consortium of the EPC Contract, and asserted against WEC and WECTEC any and all claims that were based thereon or that may have been related thereto. These claims were sold to Citibank on September 27, 2017 as part of a monetization transaction discussed below. Notwithstanding the sale of the claims, SCE&G and Santee Cooper remain responsible for any claims that may be made by WEC and WECTEC against them relating to the EPC Contract. WEC’s Reorganization Plan was confirmed by the Bankruptcy Court on March 28, 2018, and became effective August 1, 2018. In connection with the effectiveness of the Reorganization Plan, the EPC Contract was deemed rejected. Initially, WEC had projected that its Reorganization Plan would pay in full or nearly in full its pre-petition trade creditors, including several of the WEC Subcontractors which have alleged non-payment by the Consortium for amounts owed for work performed on the Nuclear Project and have filed liens on property in Fairfield County, South Carolina, where Unit 2 and Unit 3 were to be located (Unit 2/3 Property). SCE&G is contesting approximately $285 million of filed liens in Fairfield County. Most of these asserted liens are “pre-petition” claims that relate to work performed by WEC Subcontractors before the WEC bankruptcy, although some of them are “post-petition” claims arising from work performed after the WEC bankruptcy. WEC has indicated that some unsecured creditors have sought or may seek amounts beyond what WEC allocated when it submitted the Reorganization Plan. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the Reorganization Plan allocated by WEC, it is possible that the Reorganization Plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant. See also discussion below regarding limitations with respect to SCE&G’s pre-petition lien obligations arising from its monetization of the Toshiba Settlement. SCE&G and Santee Cooper are responsible for amounts owed to WEC for valid work performed by WEC Subcontractors on the Nuclear Project after the WEC bankruptcy filing (i.e., post-petition) until termination of the IAA (the IAA Period). While SCE&G and Santee Cooper funded amounts to WEC for such IAA Period obligations on a weekly basis, SCE&G and Santee Cooper undertook a reconciliation to ensure that amounts advanced to WEC for such purposes while the IAA was in effect were paid to WEC Subcontractors. That reconciliation remains ongoing. In the WEC bankruptcy proceeding, deadlines were established for creditors of WEC (including the WEC Subcontractors on the Nuclear Project) to assert the amounts owed to such creditors prior to the WEC bankruptcy filing and during the IAA Period. Many of the WEC Subcontractors have filed such claims. SCE&G does not believe that the claims asserted related to the IAA Period will exceed the amounts previously funded for the currently asserted IAA-related claims, whether relating to claims already paid or those remaining to be paid. SCE&G intends to oppose any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the IAA. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof. Further, some WEC Subcontractors who have made claims against WEC in the bankruptcy proceeding also filed against SCE&G and Santee Cooper in South Carolina state court for damages. The WEC Subcontractor claims in South Carolina state court include common law claims for pre-petition work, IAA Period work, and work after the termination of the IAA. Many of these claimants have also asserted construction liens against the Nuclear Project site. SCE&G also intends to oppose these claims and liens. With respect to claims of WEC Subcontractors during the IAA Period, SCE&G believes there were sufficient amounts previously funded during the IAA Period to pay such validly asserted claims. With respect to the WEC Subcontractor claims which relate to other periods, SCE&G understands that such claims will be paid pursuant to WEC’s confirmed Reorganization Plan. SCE&G further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, SCE&G believes that the WEC Subcontractors may be paid substantially (and potentially in full) from WEC. While SCE&G cannot be assured that it will not have any exposure on account of unpaid WEC Subcontractor claims, which claims SCE&G is presently disputing, SCE&G believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof. Toshiba Settlement and Subsequent Monetization Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC. In 2015 Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. In satisfaction of such guaranty obligations, on July 27, 2017, the Toshiba Settlement was executed under which Toshiba was to make periodic settlement payments beginning in October 2017 in the total amount of approximately $2.2 billion ( $1.2 billion for SCE&G’s 55% share), subject to certain offsets for payments by WEC in bankruptcy that would have the effect of satisfying the liens discussed above and below. In September and October 2017, proceeds totaling approximately $1.997 billion were received in full satisfaction of the Toshiba Settlement ( $1.098 billion for SCE&G's 55% share). The proceeds were obtained through the receipt of a payment from Toshiba and a payment from Citibank arising from its purchase of all other scheduled payments, including amounts related to the contractor liens discussed above. The purchase agreement with Citibank provides that SCE&G and Santee Cooper (each according to its pro rata share) would indemnify Citibank for its losses arising from misrepresentations or covenant defaults under the purchase agreement. SCE&G and Santee Cooper also assigned their claims under the WEC bankruptcy process to Citibank, and agreed to use commercially reasonable efforts to cooperate with Citibank and provide reasonable support necessary for its enforcement of those claims. Proceeds received from the Toshiba Settlement are recorded as a regulatory liability on the accompanying consolidated balance sheets, as the net value of the proceeds will be credited to customer bills over 20 years (see Merger Approval Order above). Several WEC Subcontractors have filed liens against the Unit 2/3 Property, which SCE&G is contesting. Payments under the Toshiba Settlement are subject to reduction if WEC pays WEC Subcontractors holding pre-petition liens directly. Under these circumstances, SCE&G and Santee Cooper, each in its pro rata share, would be required to make Citibank whole for reductions related to valid subcontractor and vendor pre-petition liens up to $60 million ( $33 million for SCE&G's 55% share). Regulatory, Political and Legal Developments In connection with the abandonment of the Nuclear Project, various state and local governmental authorities have attempted and may further attempt to challenge, reverse or revoke previously-approved tax or economic development incentives, benefits or exemptions and have attempted and may further attempt to apply such actions retroactively. No assurance can be given as to the timing or outcome of these matters. See Claims and Litigation for a description of specific challenges. In July 2018, the SCPSC issued orders implementing a June 2018 legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from its electric utility customers under the BLRA and altering certain provisions previously applicable under the BLRA, including redefining the standard of care required by the associated regulations and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the Nuclear Project. These orders reduced the portion of SCE&G’s retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer’s bill, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. These lower rates remained in effect until February 2019, when the new rates pursuant to the Merger Approval Order became effective. In June 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of the rate reductions under the BLRA. In the lawsuit, which was subsequently amended, SCE&G sought a declaration that the new laws were unconstitutional. On January 8, 2019, SCE&G voluntarily dismissed this lawsuit without prejudice. Impairment Considerations In 2017, the Company and Consolidated SC&G recognized pre-tax impairment losses of approximately $1.118 billion (approximately $690 million net of tax) related to the Nuclear Project. In the first quarter of 2018, the Company and Consolidated SCE&G recognized a pre-tax impairment loss of approximately $3.6 million (approximately $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. On December 21, 2018, the SCPSC issued the Merger Approval Order which, among other things, limited recovery of capital costs related to the Nuclear Project to $2.768 billion . As a result, the Company and Consolidated SCE&G concluded that Nuclear Project capital costs exceeding the amount established in the Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed, and recorded an impairment charge of approximately $1.372 billion (approximately $870.1 million net of tax) in the fourth quarter of 2018. In addition, the Company and Consolidated SCE&G expect to record additional impairment charges and establish additional liabilities in the first quarter of 2019. These additional amounts arise from or are related to provisions in the Merger Approval Order and an order by the NCUC approving the SCANA Combination that required the successful consummation of the merger before they would become effective. Accordingly, the following impairment charges and liabilities are expected to be recorded by the Company and Consolidated SCE&G (unless otherwise indicated) in the first quarter of 2019: • A pre-tax impairment charge of approximately $105 million (approximately $79 million net of tax) related to certain assets that had been constructed in connection with the Nuclear Project that were not abandoned but were instead transferred to Unit 1. • A regulatory liability for refunds and restitution to electric customers of approximately $ 1.007 billion pre-tax (approximately $755 million net of tax). • A regulatory liability for refunds to natural gas customers totaling $2.45 million pre-tax (approximately $1.8 million net of tax). • A liability related to charitable contributions in South Carolina of approximately $22 million pre-tax (approximately $16 million net of tax). It is expected that an additional liability related to charitable contributions in North Carolina of approximately $0.7 million pre-tax (approximately $0.5 million net of tax) would be recorded by the Company. • A write-off of excess deferred taxes of approximately $145 million related to the regulatory liability for the monetization of guaranty settlement. In addition, the SCPSC order approved the removal of SCE&G's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of December 31, 2018, such investment in these assets included approximately $367 million within utility plant, net and approximately $15 million within regulatory assets, which amount represents certain deferred operating costs. The SCPSC also approved deferral of certain operating costs related to the investment. Recovery of the transmission capital costs and associated deferred operating costs will be addressed in a future rate proceeding. The Company and Consolidated SCE&G believe these transmission capital and deferred operating costs are probable of recovery; however, if the SCPSC were to disallow recovery of or a reasonable return on all or a portion of them, an impairment charge equal to the disallowed costs may be required. Claims and Litigation Ratepayer Class Actions In May 2018, a consolidated complaint was filed in the State Court of Common Pleas in Hampton County, South Carolina (the Hampton County Court) against SCE&G, SCANA, and the State of South Carolina (the SCE&G Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that SCE&G was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the Nuclear Project, and that SCE&G committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that SCE&G may not charge its customers for any past or continuing costs of the Nuclear Project, sought to have SCANA and SCE&G’s assets frozen and all monies recovered from Toshiba and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the Nuclear Project. In December 2018, the judge entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the SCE&G Ratepayer Case. The settlement agreement provides that SCANA and SCE&G would establish an escrow account (the Common Benefit Fund), and proceeds from the Common Benefit Fund would be distributed to the class members, after payment of certain taxes, attorneys' fees and other expenses and administrative costs. The Common Benefit Fund would include (1) the sum of $2.0 billion , net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the Common Benefit Fund in favor of class members over a period of time established by the SCPSC in its order related to the Concurrent Dockets, (2) a cash payment of $115 million , and (3) the transfer of certain SCE&G-owned real estate or sales proceeds from the sale of such properties, which counsel for the SCE&G Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and SCE&G have funded this escrow account. The court has scheduled a fairness hearing on the settlement in May 2019. Any distribution from the Common Benefit Fund is subject to court approval. As a result, the Company and Consolidated SCE&G expect to reflect an approximately $157 million ( $118 million after-tax) charge in the first quarter of 2019. In addition to court approval, this settlement was contingent on the consummation of the SCANA Combination, which became effective January 1, 2019. Therefore, as of December 31, 2018, no accrual for this potential loss has been included in the consolidated financial statements, but is expected to be recorded by the Company and Consolidated SCE&G in the first quarter of 2019. In September 2017, a purported class action was filed against Santee Cooper, SCE&G, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the Hampton County Court (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the SCE&G Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the Nuclear Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina. In December 2018, Santee Cooper filed its answer to the plaintiffs' fourth amended complaint and filed cross claims against SCE&G. These cross claims include breach of contract accompanied by a fraudulent act, gross negligence, breach of fiduciary duty, breach of contract accompanied by bad faith, waste and equitable indemnification. In January 2019, SCE&G filed a motion to dismiss Santee Cooper's cross claims or in the alternative to compel arbitration and a stay. A hearing has not been scheduled on this motion. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. In January 2018, a purported class action was filed, and subsequently amended, against SCANA, SCE&G and certain former executive officers in the District Court. The plaintiffs allege, among other things, that SCANA, SCE&G and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. The SCE&G Ratepayer Case settlement described previously contemplates dismissal of claims by SCE&G ratepayers in this case against SCE&G, SCANA and their former officers. In January 2019, the plaintiffs filed an amended complaint which continues to make allegations on behalf of Santee Cooper ratepayers against SCANA, SCE&G and the individual former executive officers. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. State Court Shareholder Actions In September 2017, a purported shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina (the Richland County Court). In September 2018, this action was consolidated with another action in the Business Court Pilot Program in Richland County. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the Nuclear Project, and that certain of the defendants were unjustly enriched by bonuses they were paid in connection with the project. The defendants have filed a motion to dismiss the consolidated action in favor of the pending federal derivative action. On January 7, 2019, the defendants filed a motion for judgment on the pleadings, asserting the shareholders in this action lost standing to assert derivative claims as a result of the SCANA Combination. These motions are pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the District Court and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County, South Carolina. Dominion Energy appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with a similar appeal and remains pending. Motions to stay and to consolidate this case are being held in abeyance. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. In February 2018, a purported class action was filed against certain former executive officers and directors of SCANA and SCE&G and Dominion Energy in the Richland County Court. The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the City of Warren Lawsuit. In February 2018, Dominion Energy removed the case to the District Court and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the Richland County Court. Dominion Energy appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with the City of Warren Lawsuit. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. Federal Court Shareholder Actions In November 2017, a purported shareholder derivative action was filed against SCANA and certain former executive officers and directors in the District Court. Another purported shareholder derivative action was filed against nearly all of these defendants. In January 2018, the District Court consolidated these suits, and the plaintiffs filed a consolidated amended complaint. The plaintiffs allege, among other things, that the defendants violated their fiduciary duties to shareholders by disseminating false and misleading information about the Nuclear Project, failing to maintain proper internal controls, failing to properly oversee and manage SCANA and that the individual defendants were unjustly enriched in their compensation. In June 2018, the court denied the defendants' motions to dismiss and in October 2018, the court denied SCANA's motion to stay all proceedings pending investigation by a Special Litigation Committee of its Board of Directors, with leave to refile after the SCPSC's decision on the merger between Dominion Energy and SCANA. On January 7, 2019, the defendants filed a motion for judgment on the pleadings, asserting the shareholders in this action lost standing to assert derivative claims as a result of the SCANA Combination. This motion is pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. In September 2017, a purported class action was filed against SCANA and certain former executive officers in the District Court. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants. In January 2018, the District Court consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and that the individually named defendants are liable under §20(a) of the Exchange Act. The defendants' motions to dismiss are pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. Employment Class Action and Indemnification In July 2018, a case filed in the District Court was certified as a class action on behalf of persons who formerly worked at the Nuclear Project. The plaintiffs allege, among other things, that SCANA, Fluor Corporation and Fluor Enterprises, Inc. violated the WARN Act in connection with the decision to stop construction at the Nuclear Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment. While SCANA and SCE&G intend to contest this case, it is reasonably possible that a loss estimated to be as much as $75 million could be incurred, of which SCE&G's proportionate share as a co-owner of the Nuclear Project would be 55%. This potential loss could arise due to the Fluor Defendants seeking indemnification from SCE&G. In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina (the Fairfield County Court) by the Fluor Defendants against SCE&G and Santee Cooper. The Fluor Defendants make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants' alleged failure and refusal to defend and indemnify the Fluor Defendants in the aforementioned case. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of these cases, but there could be a material impact to their results of operations, financial condition and/or cash flows. FILOT Litigation In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against SCE&G in the Fairfield County Court. The complaint makes allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty and unfair trade practices related to SCE&G’s termination of the FILOT agreement between SCE&G and Fairfield County related to the Nuclear Project. The plaintiff withdrew the motion for temporary injunction in December 2017. This case is pending. The Company and Consolidated SCE&G are currently unable to make an estimate of the potential
SCE&G
Commitment [Line Items]
Legal Matters and Contingencies [Text Block]	COMMITMENTS AND CONTINGENCIES Abandoned Nuclear Project SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. SCE&G's ownership share in these units is 55% . Various difficulties were encountered in connection with the project. The ability of the Consortium to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters preceded the filing for bankruptcy protection by the Consortium on March 29, 2017 (see Contractor Bankruptcy Proceedings and Related Uncertainties below), and were the subject of comprehensive analyses performed by the Company and Santee Cooper. Based on the results of the Company's analysis, and in light of Santee Cooper's decision to suspend construction on Unit 2 and Unit 3, on July 31, 2017, the Company determined to stop the construction of the units and to pursue recovery of costs incurred in connection with the construction under the abandonment provisions of the BLRA or through other means. This decision by the Company became the focus of numerous legislative, regulatory and legal proceedings, and led to SCE&G recording pre-tax impairment charges in 2017 totaling approximately $1.118 billion (approximately $690 million net of tax). An additional pre-tax impairment loss was recorded in the first quarter of 2018 of approximately $3.6 million (approximately $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. See further discussion below under Impairment Considerations . These proceedings continued in 2018, and some of them remain unresolved and are described below and/or in Claims and Litigation. On January 2, 2018, SCANA and Dominion Energy entered into the Merger Agreement and sought the consents and approvals from governmental entities and the shareholders of SCANA required to consummate the merger. After all consents and approvals were obtained, the SCANA Combination was effective January 1, 2019. Merger Approval Order On December 21, 2018, the SCPSC issued the Merger Approval Order. The order adopted Dominion Energy's Plan-B Levelized Customer Benefits Plan whereby the average bill for an SCE&G residential electric customer would approximate that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the SCPSC in August 2018. Among other things, the order also sets forth the following findings and merger conditions: • No capital costs related to the Nuclear Project incurred after March 12, 2015 will be recoverable by SCE&G, which results in rate base associated with the Nuclear Project of $2.768 billion after recording an impairment charge of $1.372 billion (pre-tax, and incremental to impairment losses recorded in 2017). • SCE&G will provide refunds and restitution to customers from prior years' revenues totaling an aggregate $2.039 billion , comprised of $1.032 billion to be credited to customers over 20 years and $1.007 billion credited to customers over approximately 11 years. These refunds include amounts to be refunded to customers related to the monetization of guaranty settlement described in Note 2. • Except for rate adjustments for fuel and environmental costs, demand side management costs, and other rates routinely adjusted on an annual or biannual basis, SCE&G will freeze retail electric base rates at current levels until January 1, 2021. • SCE&G's natural gas customers will receive refunds totaling $2.45 million in 2019, 2020 and 2021 combined. • Corporate giving will increase by $1 million per year for at least five years above historical levels. • SCE&G will not seek to pass on to ratepayers its initial capital investment in CEC, a 540-MW combined-cycle natural gas-fired generating facility, and will not seek to pass on to ratepayers any acquisition premium costs, transition costs, or transaction cost associated with the merger. SCE&G's decision to not seek recovery of the initial capital investment in CEC was included in the determination of impairment charges recorded in 2017. In addition, the SCPSC order approved the removal of SCE&G's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of December 31, 2018, such investment in these assets included approximately $367 million within utility plant, net and approximately $15 million within regulatory assets, which amount represents certain deferred operating costs. The SCPSC also approved deferral of certain operating costs related to the investment. Recovery of the transmission capital costs and associated deferred operating costs will be addressed in a future rate proceeding. Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. On February 12, 2019, the SCPSC issued a ruling (1) finding that SCE&G was imprudent in its actions by not disclosing material information to the ORS and the SCPSC, and (2) denying the petitions for rehearing or reconsideration as to other issues raised in the various petitions. The Merger Approval Order and the ruling are subject to appeal by various parties. The Company and Consolidated SCE&G cannot predict the outcome of these matters. Contractor Bankruptcy Proceedings and Related Uncertainties On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the Nuclear Project and similar units being built for an unaffiliated company as a material factor that caused WEC and WECTEC to seek protection under the bankruptcy laws. As part of such filing, WEC and WECTEC publicly announced their inability to complete Unit 2 and Unit 3 under the terms of the EPC Contract. On September 1, 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of WEC and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by the Consortium of the EPC Contract, and asserted against WEC and WECTEC any and all claims that were based thereon or that may have been related thereto. These claims were sold to Citibank on September 27, 2017 as part of a monetization transaction discussed below. Notwithstanding the sale of the claims, SCE&G and Santee Cooper remain responsible for any claims that may be made by WEC and WECTEC against them relating to the EPC Contract. WEC’s Reorganization Plan was confirmed by the Bankruptcy Court on March 28, 2018, and became effective August 1, 2018. In connection with the effectiveness of the Reorganization Plan, the EPC Contract was deemed rejected. Initially, WEC had projected that its Reorganization Plan would pay in full or nearly in full its pre-petition trade creditors, including several of the WEC Subcontractors which have alleged non-payment by the Consortium for amounts owed for work performed on the Nuclear Project and have filed liens on property in Fairfield County, South Carolina, where Unit 2 and Unit 3 were to be located (Unit 2/3 Property). SCE&G is contesting approximately $285 million of filed liens in Fairfield County. Most of these asserted liens are “pre-petition” claims that relate to work performed by WEC Subcontractors before the WEC bankruptcy, although some of them are “post-petition” claims arising from work performed after the WEC bankruptcy. WEC has indicated that some unsecured creditors have sought or may seek amounts beyond what WEC allocated when it submitted the Reorganization Plan. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the Reorganization Plan allocated by WEC, it is possible that the Reorganization Plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant. See also discussion below regarding limitations with respect to SCE&G’s pre-petition lien obligations arising from its monetization of the Toshiba Settlement. SCE&G and Santee Cooper are responsible for amounts owed to WEC for valid work performed by WEC Subcontractors on the Nuclear Project after the WEC bankruptcy filing (i.e., post-petition) until termination of the IAA (the IAA Period). While SCE&G and Santee Cooper funded amounts to WEC for such IAA Period obligations on a weekly basis, SCE&G and Santee Cooper undertook a reconciliation to ensure that amounts advanced to WEC for such purposes while the IAA was in effect were paid to WEC Subcontractors. That reconciliation remains ongoing. In the WEC bankruptcy proceeding, deadlines were established for creditors of WEC (including the WEC Subcontractors on the Nuclear Project) to assert the amounts owed to such creditors prior to the WEC bankruptcy filing and during the IAA Period. Many of the WEC Subcontractors have filed such claims. SCE&G does not believe that the claims asserted related to the IAA Period will exceed the amounts previously funded for the currently asserted IAA-related claims, whether relating to claims already paid or those remaining to be paid. SCE&G intends to oppose any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the IAA. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof. Further, some WEC Subcontractors who have made claims against WEC in the bankruptcy proceeding also filed against SCE&G and Santee Cooper in South Carolina state court for damages. The WEC Subcontractor claims in South Carolina state court include common law claims for pre-petition work, IAA Period work, and work after the termination of the IAA. Many of these claimants have also asserted construction liens against the Nuclear Project site. SCE&G also intends to oppose these claims and liens. With respect to claims of WEC Subcontractors during the IAA Period, SCE&G believes there were sufficient amounts previously funded during the IAA Period to pay such validly asserted claims. With respect to the WEC Subcontractor claims which relate to other periods, SCE&G understands that such claims will be paid pursuant to WEC’s confirmed Reorganization Plan. SCE&G further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, SCE&G believes that the WEC Subcontractors may be paid substantially (and potentially in full) from WEC. While SCE&G cannot be assured that it will not have any exposure on account of unpaid WEC Subcontractor claims, which claims SCE&G is presently disputing, SCE&G believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof. Toshiba Settlement and Subsequent Monetization Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC. In 2015 Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. In satisfaction of such guaranty obligations, on July 27, 2017, the Toshiba Settlement was executed under which Toshiba was to make periodic settlement payments beginning in October 2017 in the total amount of approximately $2.2 billion ( $1.2 billion for SCE&G’s 55% share), subject to certain offsets for payments by WEC in bankruptcy that would have the effect of satisfying the liens discussed above and below. In September and October 2017, proceeds totaling approximately $1.997 billion were received in full satisfaction of the Toshiba Settlement ( $1.098 billion for SCE&G's 55% share). The proceeds were obtained through the receipt of a payment from Toshiba and a payment from Citibank arising from its purchase of all other scheduled payments, including amounts related to the contractor liens discussed above. The purchase agreement with Citibank provides that SCE&G and Santee Cooper (each according to its pro rata share) would indemnify Citibank for its losses arising from misrepresentations or covenant defaults under the purchase agreement. SCE&G and Santee Cooper also assigned their claims under the WEC bankruptcy process to Citibank, and agreed to use commercially reasonable efforts to cooperate with Citibank and provide reasonable support necessary for its enforcement of those claims. Proceeds received from the Toshiba Settlement are recorded as a regulatory liability on the accompanying consolidated balance sheets, as the net value of the proceeds will be credited to customer bills over 20 years (see Merger Approval Order above). Several WEC Subcontractors have filed liens against the Unit 2/3 Property, which SCE&G is contesting. Payments under the Toshiba Settlement are subject to reduction if WEC pays WEC Subcontractors holding pre-petition liens directly. Under these circumstances, SCE&G and Santee Cooper, each in its pro rata share, would be required to make Citibank whole for reductions related to valid subcontractor and vendor pre-petition liens up to $60 million ( $33 million for SCE&G's 55% share). Regulatory, Political and Legal Developments In connection with the abandonment of the Nuclear Project, various state and local governmental authorities have attempted and may further attempt to challenge, reverse or revoke previously-approved tax or economic development incentives, benefits or exemptions and have attempted and may further attempt to apply such actions retroactively. No assurance can be given as to the timing or outcome of these matters. See Claims and Litigation for a description of specific challenges. In July 2018, the SCPSC issued orders implementing a June 2018 legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from its electric utility customers under the BLRA and altering certain provisions previously applicable under the BLRA, including redefining the standard of care required by the associated regulations and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the Nuclear Project. These orders reduced the portion of SCE&G’s retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer’s bill, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. These lower rates remained in effect until February 2019, when the new rates pursuant to the Merger Approval Order became effective. In June 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of the rate reductions under the BLRA. In the lawsuit, which was subsequently amended, SCE&G sought a declaration that the new laws were unconstitutional. On January 8, 2019, SCE&G voluntarily dismissed this lawsuit without prejudice. Impairment Considerations In 2017, the Company and Consolidated SC&G recognized pre-tax impairment losses of approximately $1.118 billion (approximately $690 million net of tax) related to the Nuclear Project. In the first quarter of 2018, the Company and Consolidated SCE&G recognized a pre-tax impairment loss of approximately $3.6 million (approximately $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. On December 21, 2018, the SCPSC issued the Merger Approval Order which, among other things, limited recovery of capital costs related to the Nuclear Project to $2.768 billion . As a result, the Company and Consolidated SCE&G concluded that Nuclear Project capital costs exceeding the amount established in the Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed, and recorded an impairment charge of approximately $1.372 billion (approximately $870.1 million net of tax) in the fourth quarter of 2018. In addition, the Company and Consolidated SCE&G expect to record additional impairment charges and establish additional liabilities in the first quarter of 2019. These additional amounts arise from or are related to provisions in the Merger Approval Order and an order by the NCUC approving the SCANA Combination that required the successful consummation of the merger before they would become effective. Accordingly, the following impairment charges and liabilities are expected to be recorded by the Company and Consolidated SCE&G (unless otherwise indicated) in the first quarter of 2019: • A pre-tax impairment charge of approximately $105 million (approximately $79 million net of tax) related to certain assets that had been constructed in connection with the Nuclear Project that were not abandoned but were instead transferred to Unit 1. • A regulatory liability for refunds and restitution to electric customers of approximately $ 1.007 billion pre-tax (approximately $755 million net of tax). • A regulatory liability for refunds to natural gas customers totaling $2.45 million pre-tax (approximately $1.8 million net of tax). • A liability related to charitable contributions in South Carolina of approximately $22 million pre-tax (approximately $16 million net of tax). It is expected that an additional liability related to charitable contributions in North Carolina of approximately $0.7 million pre-tax (approximately $0.5 million net of tax) would be recorded by the Company. • A write-off of excess deferred taxes of approximately $145 million related to the regulatory liability for the monetization of guaranty settlement. In addition, the SCPSC order approved the removal of SCE&G's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of December 31, 2018, such investment in these assets included approximately $367 million within utility plant, net and approximately $15 million within regulatory assets, which amount represents certain deferred operating costs. The SCPSC also approved deferral of certain operating costs related to the investment. Recovery of the transmission capital costs and associated deferred operating costs will be addressed in a future rate proceeding. The Company and Consolidated SCE&G believe these transmission capital and deferred operating costs are probable of recovery; however, if the SCPSC were to disallow recovery of or a reasonable return on all or a portion of them, an impairment charge equal to the disallowed costs may be required. Claims and Litigation Ratepayer Class Actions In May 2018, a consolidated complaint was filed in the State Court of Common Pleas in Hampton County, South Carolina (the Hampton County Court) against SCE&G, SCANA, and the State of South Carolina (the SCE&G Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that SCE&G was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the Nuclear Project, and that SCE&G committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that SCE&G may not charge its customers for any past or continuing costs of the Nuclear Project, sought to have SCANA and SCE&G’s assets frozen and all monies recovered from Toshiba and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the Nuclear Project. In December 2018, the judge entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the SCE&G Ratepayer Case. The settlement agreement provides that SCANA and SCE&G would establish an escrow account (the Common Benefit Fund), and proceeds from the Common Benefit Fund would be distributed to the class members, after payment of certain taxes, attorneys' fees and other expenses and administrative costs. The Common Benefit Fund would include (1) the sum of $2.0 billion , net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the Common Benefit Fund in favor of class members over a period of time established by the SCPSC in its order related to the Concurrent Dockets, (2) a cash payment of $115 million , and (3) the transfer of certain SCE&G-owned real estate or sales proceeds from the sale of such properties, which counsel for the SCE&G Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and SCE&G have funded this escrow account. The court has scheduled a fairness hearing on the settlement in May 2019. Any distribution from the Common Benefit Fund is subject to court approval. As a result, the Company and Consolidated SCE&G expect to reflect an approximately $157 million ( $118 million after-tax) charge in the first quarter of 2019. In addition to court approval, this settlement was contingent on the consummation of the SCANA Combination, which became effective January 1, 2019. Therefore, as of December 31, 2018, no accrual for this potential loss has been included in the consolidated financial statements, but is expected to be recorded by the Company and Consolidated SCE&G in the first quarter of 2019. In September 2017, a purported class action was filed against Santee Cooper, SCE&G, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the Hampton County Court (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the SCE&G Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the Nuclear Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina. In December 2018, Santee Cooper filed its answer to the plaintiffs' fourth amended complaint and filed cross claims against SCE&G. These cross claims include breach of contract accompanied by a fraudulent act, gross negligence, breach of fiduciary duty, breach of contract accompanied by bad faith, waste and equitable indemnification. In January 2019, SCE&G filed a motion to dismiss Santee Cooper's cross claims or in the alternative to compel arbitration and a stay. A hearing has not been scheduled on this motion. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. In January 2018, a purported class action was filed, and subsequently amended, against SCANA, SCE&G and certain former executive officers in the District Court. The plaintiffs allege, among other things, that SCANA, SCE&G and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. The SCE&G Ratepayer Case settlement described previously contemplates dismissal of claims by SCE&G ratepayers in this case against SCE&G, SCANA and their former officers. In January 2019, the plaintiffs filed an amended complaint which continues to make allegations on behalf of Santee Cooper ratepayers against SCANA, SCE&G and the individual former executive officers. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. State Court Shareholder Actions In September 2017, a purported shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina (the Richland County Court). In September 2018, this action was consolidated with another action in the Business Court Pilot Program in Richland County. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the Nuclear Project, and that certain of the defendants were unjustly enriched by bonuses they were paid in connection with the project. The defendants have filed a motion to dismiss the consolidated action in favor of the pending federal derivative action. On January 7, 2019, the defendants filed a motion for judgment on the pleadings, asserting the shareholders in this action lost standing to assert derivative claims as a result of the SCANA Combination. These motions are pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the District Court and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County, South Carolina. Dominion Energy appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with a similar appeal and remains pending. Motions to stay and to consolidate this case are being held in abeyance. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. In February 2018, a purported class action was filed against certain former executive officers and directors of SCANA and SCE&G and Dominion Energy in the Richland County Court. The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the City of Warren Lawsuit. In February 2018, Dominion Energy removed the case to the District Court and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the Richland County Court. Dominion Energy appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with the City of Warren Lawsuit. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. Federal Court Shareholder Actions In November 2017, a purported shareholder derivative action was filed against SCANA and certain former executive officers and directors in the District Court. Another purported shareholder derivative action was filed against nearly all of these defendants. In January 2018, the District Court consolidated these suits, and the plaintiffs filed a consolidated amended complaint. The plaintiffs allege, among other things, that the defendants violated their fiduciary duties to shareholders by disseminating false and misleading information about the Nuclear Project, failing to maintain proper internal controls, failing to properly oversee and manage SCANA and that the individual defendants were unjustly enriched in their compensation. In June 2018, the court denied the defendants' motions to dismiss and in October 2018, the court denied SCANA's motion to stay all proceedings pending investigation by a Special Litigation Committee of its Board of Directors, with leave to refile after the SCPSC's decision on the merger between Dominion Energy and SCANA. On January 7, 2019, the defendants filed a motion for judgment on the pleadings, asserting the shareholders in this action lost standing to assert derivative claims as a result of the SCANA Combination. This motion is pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. In September 2017, a purported class action was filed against SCANA and certain former executive officers in the District Court. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants. In January 2018, the District Court consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and that the individually named defendants are liable under §20(a) of the Exchange Act. The defendants' motions to dismiss are pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows. Employment Class Action and Indemnification In July 2018, a case filed in the District Court was certified as a class action on behalf of persons who formerly worked at the Nuclear Project. The plaintiffs allege, among other things, that SCANA, Fluor Corporation and Fluor Enterprises, Inc. violated the WARN Act in connection with the decision to stop construction at the Nuclear Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment. While SCANA and SCE&G intend to contest this case, it is reasonably possible that a loss estimated to be as much as $75 million could be incurred, of which SCE&G's proportionate share as a co-owner of the Nuclear Project would be 55%. This potential loss could arise due to the Fluor Defendants seeking indemnification from SCE&G. In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina (the Fairfield County Court) by the Fluor Defendants against SCE&G and Santee Cooper. The Fluor Defendants make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants' alleged failure and refusal to defend and indemnify the Fluor Defendants in the aforementioned case. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of these cases, but there could be a material impact to their results of operations, financial condition and/or cash flows. FILOT Litigation In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against SCE&G in the Fairfield County Court. The complaint makes allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty and unfair trade practices related to SCE&G’s termination of the FILOT agreement between SCE&G and Fairfield County related to the Nuclear Project. The plaintiff withdrew the motion for temporary injunction in December 2017. This case is pending. The Company and Consolidated SCE&G are currently unable to make an estimate of the potential

SEGMENT OF BUSINESS INFORMATION

SEGMENT OF BUSINESS INFORMATION	12 Months Ended
	Dec. 31, 2018
Segment Reporting Information [Line Items]
Segment Reporting Disclosure [Text Block]	SEGMENT OF BUSINESS INFORMATION Reportable segments, which are described below, follow the same accounting policies as those described in Note 1. Intersegment sales and transfers of electricity and gas are recorded based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices. Electric Operations primarily generates, transmits and distributes electricity, and is regulated by the SCPSC and FERC. Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, purchases and sells natural gas, primarily at retail. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively. Gas Marketing is comprised of the marketing operations of SCANA Energy, which markets natural gas to retail customers in Georgia and to industrial and large commercial customers and municipalities in the Southeast. All Other includes the parent company and a services company. Regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations’ product differs from the other segments, as does its generation process and method of distribution. Gas Marketing operates in a deregulated environment. Management uses operating income (loss) to measure segment profitability for its regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, no allocation is made to segments for interest charges, income tax expense (benefit) or assets other than utility plant. For nonregulated operations, management uses net income (loss) as the measure of segment profitability and evaluates total assets for financial position. Intersegment revenue for SCE&G was not significant. Interest income is not reported by segment and is not material. Deferred tax assets are netted with deferred tax liabilities for consolidated reporting purposes. The consolidated financial statements report operating revenues which are comprised of the energy-related and regulated segments. Revenues from non-reportable and nonregulated segments are included in Other Income. Therefore, the adjustments to total operating revenues remove revenues from non-reportable segments. Adjustments to net income (loss) consist of the unallocated net income (loss) of regulated reportable segments. Segment Assets include utility plant, net for SCE&G’s Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G. Adjustments to Interest Expense, Income Tax Expense (Benefit), Expenditures for Assets and Deferred Tax Assets include primarily the amounts that are not allocated to the segments. Interest Expense is also adjusted to eliminate charges between affiliates. Adjustments to Depreciation and Amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Expenditures for Assets are adjusted for AFC and revisions to estimated cash flows related to AROs, and totals not allocated to other segments. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis. Disclosure of Reportable Segments The Company: Millions of dollars Electric Operations Gas Distribution Gas Marketing All Other Adjustments/ Eliminations Consolidated Total 2018 External Revenue $ 2,322 $ 934 $ 796 — — $ 4,052 Intersegment Revenue 5 1 139 $ 470 $ (615 ) — Operating Income (Loss) (894 ) 173 n/a — (8 ) (729 ) Interest Expense 18 37 1 — 328 384 Depreciation and Amortization 307 94 2 15 (15 ) 403 Income Tax Expense (Benefit) 9 26 15 (25 ) (437 ) (412 ) Net Income (Loss) n/a n/a 43 (90 ) (481 ) (528 ) Segment Assets 7,988 3,517 305 1,212 4,632 17,654 Expenditures for Assets 973 345 2 8 (438 ) 890 Deferred Tax Assets 4 17 2 — (23 ) — 2017 External Revenue $ 2,659 $ 874 $ 874 — — $ 4,407 Intersegment Revenue 5 2 127 $ 389 $ (523 ) — Operating Income (Loss) (154 ) 187 n/a — 52 85 Interest Expense 19 28 1 — 315 363 Depreciation and Amortization 295 85 2 16 (16 ) 382 Income Tax Expense (Benefit) 8 41 25 (7 ) (179 ) (112 ) Net Income (Loss) n/a n/a 27 (46 ) (100 ) (119 ) Segment Assets 11,979 3,259 230 1,042 2,229 18,739 Expenditures for Assets 216 417 2 7 583 1,225 Deferred Tax Assets 6 25 9 — (40 ) — 2016 External Revenue $ 2,614 $ 788 $ 825 — — $ 4,227 Intersegment Revenue 5 2 111 $ 414 $ (532 ) — Operating Income 969 149 n/a — 49 1,167 Interest Expense 17 25 1 — 299 342 Depreciation and Amortization 287 82 2 16 (16 ) 371 Income Tax Expense 8 32 19 — 212 271 Net Income (Loss) n/a n/a 30 (18 ) 583 595 Segment Assets 11,929 2,892 230 1,124 2,532 18,707 Expenditures for Assets 1,275 276 2 11 15 1,579 Deferred Tax Assets 9 32 11 — (52 ) — Consolidated SCE&G: Millions of dollars Electric Gas Adjustments/ Consolidated 2018 External Revenue $ 2,327 $ 435 — $ 2,762 Operating Income (Loss) (894 ) 63 — (831 ) Interest Expense 18 — $ 285 303 Depreciation and Amortization 307 32 (12 ) 327 Segment Assets 7,988 934 6,041 14,963 Expenditures for Assets 973 90 (430 ) 633 Deferred Tax Assets 4 n/a (4 ) — 2017 External Revenue $ 2,664 $ 406 — $ 3,070 Operating Income (Loss) (154 ) 71 — (83 ) Interest Expense 19 — $ 269 288 Depreciation and Amortization 295 30 (13 ) 312 Segment Assets 11,979 869 3,098 15,946 Expenditures for Assets 216 65 647 928 Deferred Tax Assets 6 n/a (6 ) — 2016 External Revenue $ 2,619 $ 367 — $ 2,986 Operating Income 969 56 — 1,025 Interest Expense 17 — $ 253 270 Depreciation and Amortization 287 28 (13 ) 302 Segment Assets 11,929 825 3,337 16,091 Expenditures for Assets 1,275 78 46 1,399 Deferred Tax Assets 9 n/a (9 ) —
SCE&G
Segment Reporting Information [Line Items]
Segment Reporting Disclosure [Text Block]	SEGMENT OF BUSINESS INFORMATION Reportable segments, which are described below, follow the same accounting policies as those described in Note 1. Intersegment sales and transfers of electricity and gas are recorded based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices. Electric Operations primarily generates, transmits and distributes electricity, and is regulated by the SCPSC and FERC. Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, purchases and sells natural gas, primarily at retail. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively. Gas Marketing is comprised of the marketing operations of SCANA Energy, which markets natural gas to retail customers in Georgia and to industrial and large commercial customers and municipalities in the Southeast. All Other includes the parent company and a services company. Regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations’ product differs from the other segments, as does its generation process and method of distribution. Gas Marketing operates in a deregulated environment. Management uses operating income (loss) to measure segment profitability for its regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, no allocation is made to segments for interest charges, income tax expense (benefit) or assets other than utility plant. For nonregulated operations, management uses net income (loss) as the measure of segment profitability and evaluates total assets for financial position. Intersegment revenue for SCE&G was not significant. Interest income is not reported by segment and is not material. Deferred tax assets are netted with deferred tax liabilities for consolidated reporting purposes. The consolidated financial statements report operating revenues which are comprised of the energy-related and regulated segments. Revenues from non-reportable and nonregulated segments are included in Other Income. Therefore, the adjustments to total operating revenues remove revenues from non-reportable segments. Adjustments to net income (loss) consist of the unallocated net income (loss) of regulated reportable segments. Segment Assets include utility plant, net for SCE&G’s Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G. Adjustments to Interest Expense, Income Tax Expense (Benefit), Expenditures for Assets and Deferred Tax Assets include primarily the amounts that are not allocated to the segments. Interest Expense is also adjusted to eliminate charges between affiliates. Adjustments to Depreciation and Amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Expenditures for Assets are adjusted for AFC and revisions to estimated cash flows related to AROs, and totals not allocated to other segments. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis. Disclosure of Reportable Segments The Company: Millions of dollars Electric Operations Gas Distribution Gas Marketing All Other Adjustments/ Eliminations Consolidated Total 2018 External Revenue $ 2,322 $ 934 $ 796 — — $ 4,052 Intersegment Revenue 5 1 139 $ 470 $ (615 ) — Operating Income (Loss) (894 ) 173 n/a — (8 ) (729 ) Interest Expense 18 37 1 — 328 384 Depreciation and Amortization 307 94 2 15 (15 ) 403 Income Tax Expense (Benefit) 9 26 15 (25 ) (437 ) (412 ) Net Income (Loss) n/a n/a 43 (90 ) (481 ) (528 ) Segment Assets 7,988 3,517 305 1,212 4,632 17,654 Expenditures for Assets 973 345 2 8 (438 ) 890 Deferred Tax Assets 4 17 2 — (23 ) — 2017 External Revenue $ 2,659 $ 874 $ 874 — — $ 4,407 Intersegment Revenue 5 2 127 $ 389 $ (523 ) — Operating Income (Loss) (154 ) 187 n/a — 52 85 Interest Expense 19 28 1 — 315 363 Depreciation and Amortization 295 85 2 16 (16 ) 382 Income Tax Expense (Benefit) 8 41 25 (7 ) (179 ) (112 ) Net Income (Loss) n/a n/a 27 (46 ) (100 ) (119 ) Segment Assets 11,979 3,259 230 1,042 2,229 18,739 Expenditures for Assets 216 417 2 7 583 1,225 Deferred Tax Assets 6 25 9 — (40 ) — 2016 External Revenue $ 2,614 $ 788 $ 825 — — $ 4,227 Intersegment Revenue 5 2 111 $ 414 $ (532 ) — Operating Income 969 149 n/a — 49 1,167 Interest Expense 17 25 1 — 299 342 Depreciation and Amortization 287 82 2 16 (16 ) 371 Income Tax Expense 8 32 19 — 212 271 Net Income (Loss) n/a n/a 30 (18 ) 583 595 Segment Assets 11,929 2,892 230 1,124 2,532 18,707 Expenditures for Assets 1,275 276 2 11 15 1,579 Deferred Tax Assets 9 32 11 — (52 ) — Consolidated SCE&G: Millions of dollars Electric Gas Adjustments/ Consolidated 2018 External Revenue $ 2,327 $ 435 — $ 2,762 Operating Income (Loss) (894 ) 63 — (831 ) Interest Expense 18 — $ 285 303 Depreciation and Amortization 307 32 (12 ) 327 Segment Assets 7,988 934 6,041 14,963 Expenditures for Assets 973 90 (430 ) 633 Deferred Tax Assets 4 n/a (4 ) — 2017 External Revenue $ 2,664 $ 406 — $ 3,070 Operating Income (Loss) (154 ) 71 — (83 ) Interest Expense 19 — $ 269 288 Depreciation and Amortization 295 30 (13 ) 312 Segment Assets 11,979 869 3,098 15,946 Expenditures for Assets 216 65 647 928 Deferred Tax Assets 6 n/a (6 ) — 2016 External Revenue $ 2,619 $ 367 — $ 2,986 Operating Income 969 56 — 1,025 Interest Expense 17 — $ 253 270 Depreciation and Amortization 287 28 (13 ) 302 Segment Assets 11,929 825 3,337 16,091 Expenditures for Assets 1,275 78 46 1,399 Deferred Tax Assets 9 n/a (9 ) —

UTILITY PLANT AND NONUTILITY PR

UTILITY PLANT AND NONUTILITY PROPERTY (Notes)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment Disclosure [Text Block]	UTILITY PLANT AND NONUTILITY PROPERTY Major classes of utility plant and other property and their respective balances at December 31, 2018 were as follows: Millions of dollars The Company Consolidated SCE&G Gross Utility Plant: Generation $ 5,751 $ 5,751 Transmission 2,417 1,758 Distribution 6,032 4,456 Storage 99 74 General and other 631 535 Intangible 241 229 Construction work in progress 527 350 Nuclear Fuel 611 611 Total Gross Utility Plant $ 16,309 $ 13,764 Gross Nonutility Property $ 410 $ 73 Jointly Owned Utility Plant SCE&G jointly owns and is the operator of Unit 1. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. Unit 2 and Unit 3 have been reclassified from construction work in progress to a regulatory asset as a result of the decision to stop their construction. See additional discussion at Note 2. As of December 31, 2018 2017 Unit 1 Unit 1 Percent owned 66.7% 66.7% Plant in service $ 1.5 billion $ 1.5 billion Accumulated depreciation $ 643.9 million $ 637.6 million Construction work in progress $ 127.5 million $ 110.1 million Included within other receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses. These amounts totaled $46.3 million at December 31, 2018 and $53.8 million at December 31, 2017.
SCE&G
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment Disclosure [Text Block]	UTILITY PLANT AND NONUTILITY PROPERTY Major classes of utility plant and other property and their respective balances at December 31, 2018 were as follows: Millions of dollars The Company Consolidated SCE&G Gross Utility Plant: Generation $ 5,751 $ 5,751 Transmission 2,417 1,758 Distribution 6,032 4,456 Storage 99 74 General and other 631 535 Intangible 241 229 Construction work in progress 527 350 Nuclear Fuel 611 611 Total Gross Utility Plant $ 16,309 $ 13,764 Gross Nonutility Property $ 410 $ 73 Jointly Owned Utility Plant SCE&G jointly owns and is the operator of Unit 1. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. Unit 2 and Unit 3 have been reclassified from construction work in progress to a regulatory asset as a result of the decision to stop their construction. See additional discussion at Note 2. As of December 31, 2018 2017 Unit 1 Unit 1 Percent owned 66.7% 66.7% Plant in service $ 1.5 billion $ 1.5 billion Accumulated depreciation $ 643.9 million $ 637.6 million Construction work in progress $ 127.5 million $ 110.1 million Included within other receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses. These amounts totaled $46.3 million at December 31, 2018 and $53.8 million at December 31, 2017.

AFFILIATED TRANSACTIONS (Notes)

AFFILIATED TRANSACTIONS (Notes)	12 Months Ended
	Dec. 31, 2018
Related Party Transaction [Line Items]
Related Party Transactions Disclosure [Text Block]	14. AFFILIATED TRANSACTIONS The Company: The Company received cash distributions from equity-method investees of $2.3 million in 2018, $2.8 million in 2017 and $3.7 million in 2016. The Company made investments in equity-method investees of $4.2 million in 2018, $4.6 million in 2017 and $5.5 million in 2016. The Company and Consolidated SCE&G: SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of operations (for the Company) and of comprehensive income (for Consolidated SCE&G). Millions of Dollars 2018 2017 2016 Purchases from Canadys Refined Coal, LLC $ 149.9 $ 162.1 $ 161.8 Sales to Canadys Refined Coal, LLC 149.0 161.1 160.8 Millions of Dollars 2018 2017 Receivable from Canadys Refined Coal, LLC $ 6.8 $ 4.9 Payable to Canadys Refined Coal, LLC 6.8 4.9 Consolidated SCE&G: SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in Other operation and maintenance - nonconsolidated affiliate and Other Income (Expense), net on the consolidated statements of comprehensive income. Millions of Dollars 2018 2017 2016 Purchases from SCANA Energy $ 139.0 $ 127.4 $ 111.5 Direct and Allocated Costs from SCANA Services 283.3 302.8 337.7 Millions of Dollars 2018 2017 Payable to SCANA Energy $ 14.1 $ 10.0 Payable to SCANA Services 37.7 42.0 Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 5. Certain disclosures regarding SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 9.
SCE&G
Related Party Transaction [Line Items]
Related Party Transactions Disclosure [Text Block]	14. AFFILIATED TRANSACTIONS The Company: The Company received cash distributions from equity-method investees of $2.3 million in 2018, $2.8 million in 2017 and $3.7 million in 2016. The Company made investments in equity-method investees of $4.2 million in 2018, $4.6 million in 2017 and $5.5 million in 2016. The Company and Consolidated SCE&G: SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of operations (for the Company) and of comprehensive income (for Consolidated SCE&G). Millions of Dollars 2018 2017 2016 Purchases from Canadys Refined Coal, LLC $ 149.9 $ 162.1 $ 161.8 Sales to Canadys Refined Coal, LLC 149.0 161.1 160.8 Millions of Dollars 2018 2017 Receivable from Canadys Refined Coal, LLC $ 6.8 $ 4.9 Payable to Canadys Refined Coal, LLC 6.8 4.9 Consolidated SCE&G: SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in Other operation and maintenance - nonconsolidated affiliate and Other Income (Expense), net on the consolidated statements of comprehensive income. Millions of Dollars 2018 2017 2016 Purchases from SCANA Energy $ 139.0 $ 127.4 $ 111.5 Direct and Allocated Costs from SCANA Services 283.3 302.8 337.7 Millions of Dollars 2018 2017 Payable to SCANA Energy $ 14.1 $ 10.0 Payable to SCANA Services 37.7 42.0 Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 5. Certain disclosures regarding SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 9.

OTHER INCOME (EXPENSE), NET (No

OTHER INCOME (EXPENSE), NET (Notes)	12 Months Ended
	Dec. 31, 2018
Other Income and Other Expense Disclosure [Text Block]	OTHER INCOME (EXPENSE), NET Components of other income (expense), net are as follows: The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 Revenues from contracts with customers $ 20 — — $ 5 — — Other income 180 $ 79 $ 64 141 $ 45 $ 29 Other expense (46 ) (55 ) (52 ) (28 ) (32 ) (36 ) Allowance for equity funds used during construction 19 23 29 11 15 26 Other income (expense), net $ 173 $ 47 $ 41 $ 129 $ 28 $ 19 The recording of revenue from contracts with customers within other income (expense) arose upon the adoption of related accounting guidance described in Note 1 and Note 3, and as permitted, prior periods have not been restated. For the Company and Consolidated SCE&G, other income in 2018 includes gains from the settlement of interest rate derivatives of approximately $114 million (see Note 7). For the Company and Consolidated SCE&G, non-service cost components of pension and other postretirement benefits are included in other expense.
SCE&G
Other Income and Other Expense Disclosure [Text Block]	OTHER INCOME (EXPENSE), NET Components of other income (expense), net are as follows: The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 Revenues from contracts with customers $ 20 — — $ 5 — — Other income 180 $ 79 $ 64 141 $ 45 $ 29 Other expense (46 ) (55 ) (52 ) (28 ) (32 ) (36 ) Allowance for equity funds used during construction 19 23 29 11 15 26 Other income (expense), net $ 173 $ 47 $ 41 $ 129 $ 28 $ 19 The recording of revenue from contracts with customers within other income (expense) arose upon the adoption of related accounting guidance described in Note 1 and Note 3, and as permitted, prior periods have not been restated. For the Company and Consolidated SCE&G, other income in 2018 includes gains from the settlement of interest rate derivatives of approximately $114 million (see Note 7). For the Company and Consolidated SCE&G, non-service cost components of pension and other postretirement benefits are included in other expense.

QUARTERLY FINANCIAL INFORMATION

QUARTERLY FINANCIAL INFORMATION (Notes)	12 Months Ended
	Dec. 31, 2018
Entity Information [Line Items]
Quarterly Financial Information [Text Block]	QUARTERLY FINANCIAL DATA (UNAUDITED) The Company First Quarter Second Quarter Third Quarter Fourth Quarter Annual 2018 Total Operating Revenues $ 1,180 $ 843 $ 926 $ 1,103 $ 4,052 Operating Income (Loss) 189 103 183 (1,204 ) (729 ) Net Income (Loss) 169 8 67 (772 ) (528 ) Earnings (Loss) Per Share of Common Stock 1.18 0.06 0.47 (5.41 ) (3.70 ) 2017 Total Operating Revenues $ 1,173 $ 1,001 $ 1,076 $ 1,157 $ 4,407 Operating Income (Loss) 320 251 122 (608 ) 85 Net Income (Loss) 171 121 34 (445 ) (119 ) Earnings (Loss) Per Share of Common Stock 1.19 0.85 0.24 (3.11 ) (0.83 ) Consolidated SCE&G Millions of dollars First Quarter Second Quarter Third Quarter Fourth Quarter Annual 2018 Total Operating Revenues $ 702 $ 632 $ 739 $ 689 $ 2,762 Operating Income (Loss) 121 107 212 (1,271 ) (831 ) Total Comprehensive Income (Loss) 128 31 104 (852 ) (589 ) Comprehensive Income Available (Loss Attributable) to Common Shareholder 124 26 98 (861 ) (613 ) 2017 Total Operating Revenues $ 719 $ 756 $ 856 $ 739 $ 3,070 Operating Income (Loss) 226 247 124 (680 ) (83 ) Total Comprehensive Income (Loss) 112 126 42 (452 ) (172 ) Comprehensive Income Available (Loss Attributable) to Common Shareholder 109 123 39 (456 ) (185 ) See Note 11 for a discussion of impairment losses booked in the third and fourth quarter of 2017 and the first and fourth quarter of 2018.
SCE&G
Entity Information [Line Items]
Quarterly Financial Information [Text Block]	16. QUARTERLY FINANCIAL DATA (UNAUDITED) The Company First Quarter Second Quarter Third Quarter Fourth Quarter Annual 2018 Total Operating Revenues $ 1,180 $ 843 $ 926 $ 1,103 $ 4,052 Operating Income (Loss) 189 103 183 (1,204 ) (729 ) Net Income (Loss) 169 8 67 (772 ) (528 ) Earnings (Loss) Per Share of Common Stock 1.18 0.06 0.47 (5.41 ) (3.70 ) 2017 Total Operating Revenues $ 1,173 $ 1,001 $ 1,076 $ 1,157 $ 4,407 Operating Income (Loss) 320 251 122 (608 ) 85 Net Income (Loss) 171 121 34 (445 ) (119 ) Earnings (Loss) Per Share of Common Stock 1.19 0.85 0.24 (3.11 ) (0.83 ) Consolidated SCE&G Millions of dollars First Quarter Second Quarter Third Quarter Fourth Quarter Annual 2018 Total Operating Revenues $ 702 $ 632 $ 739 $ 689 $ 2,762 Operating Income (Loss) 121 107 212 (1,271 ) (831 ) Total Comprehensive Income (Loss) 128 31 104 (852 ) (589 ) Comprehensive Income Available (Loss Attributable) to Common Shareholder 124 26 98 (861 ) (613 ) 2017 Total Operating Revenues $ 719 $ 756 $ 856 $ 739 $ 3,070 Operating Income (Loss) 226 247 124 (680 ) (83 ) Total Comprehensive Income (Loss) 112 126 42 (452 ) (172 ) Comprehensive Income Available (Loss Attributable) to Common Shareholder 109 123 39 (456 ) (185 ) See Note 11 for a discussion of impairment losses booked in the third and fourth quarter of 2017 and the first and fourth quarter of 2018.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2018
Significant Accounting Policies
Consolidation, Policy [Policy Text Block]	Organization and Principles of Consolidation Effective January 1, 2019, SCANA became a wholly-owned subsidiary of Dominion Energy under the terms of the Merger Agreement. See additional discussion in Note 2 and Note 11. The Company SCANA, a South Carolina corporation, is a holding company created in 1984. The Company primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina, and the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia. The accompanying consolidated financial statements reflect the accounts of SCANA and the following wholly-owned subsidiaries. Regulated businesses Nonregulated businesses South Carolina Electric & Gas Company SCANA Energy Marketing, Inc. South Carolina Fuel Company, Inc. SCANA Services, Inc. South Carolina Generating Company, Inc. SCANA Corporate Security Services, Inc. Public Service Company of North Carolina, Incorporated SCANA Communications Holdings, Inc. SCANA reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. Discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. Consolidated SCE&G SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA. Consolidated SCE&G primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina. SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $500 million ) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Property, Plant and Equipment, Planned Major Maintenance Activities, Policy [Policy Text Block]	Major Maintenance Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred. SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2018, and 2017, SCE&G incurred $16.3 million and $26.1 million , respectively, for turbine maintenance. Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 million annually for its portion of the nuclear refueling outages scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which SCE&G was responsible totaled
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]	Goodwill The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company has tested goodwill for impairment annually as of January 1, unless indicators, events or circumstances required interim testing to be performed. The Company performed its test on January 1, 2019 and intends to test goodwill annually on April 1, effective April 1, 2019. Under current accounting guidance, the Company may perform a qualitative assessment of impairment. Based on this assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to make a quantitative estimate of the fair value of the reporting unit and to compare that amount to its carrying value. If the Company is required to make a quantitative assessment or if it chooses to do so without first performing a qualitative one, and if the quantitative assessment indicates a carrying value in excess of fair value, an impairment charge would be required. Any such charge would be treated as an operating expense. For each period presented, assets with a carrying value of $210 million for PSNC Energy (Gas Distribution segment), net of a writedown of $230 million taken in 2002, were classified as goodwill. The Company performed a quantitative assessment of goodwill in its evaluation as of January 1, 2019 and performed a qualitative assessment of goodwill in its evaluation as of January 1, 2018. No impairment of goodwill was required based on these evaluations.
Nuclear Decommissiong [Policy Text Block]	Nuclear Decommissioning Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $625.8 million , stated in 2018 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. Under SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ( $3.2 million pre-tax in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. The asset balance held in trust reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Unit 1 on an after-tax basis.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds.
Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block]	Receivables Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described in Note 3. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $217.5 million at December 31, 2018 and $220.9 million at December 31, 2017 for the Company. Unbilled revenues totaled $129.3 million at December 31, 2018 and $140.3 million at December 31, 2017 for Consolidated SCE&G. Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station.
Inventory, Policy [Policy Text Block]	Inventories Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable.
Asset Management and Supply Service Agreements [Policy Text Block]	PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 46% and 39% of PSNC Energy’s natural gas inventory at December 31, 2018 and December 31, 2017, respectively, with a carrying value of $13.9 million and $11.5 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to customers. This agreement has been extended and expires October 31, 2020.
Income Tax, Policy [Policy Text Block]	Income Taxes SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 6 for a discussion of the impact of adjustments recorded in connection with enactment of the Tax Act. Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA for all periods presented. Also, under provisions of an income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions.
regulatory assets and regulatory liabilities [Policy Text Block]	Regulatory Assets and Regulatory Liabilities The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods that differ from those in which the costs would be charged to expense, or record revenues in periods that differ from those in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified on the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively.
Debt Premium, Discount, and Expense [Policy Text Block]	Debt Issuance Premiums, Discounts and Other Costs Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred credits or debits and are amortized over the term of the replacement debt, also as interest charges.
Environmental Costs, Policy [Policy Text Block]	Environmental An environmental assessment program is maintained to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred.
Income Statement policy [Policy Text Block]	Statement of Operations Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense).
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed. Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings. SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews. Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of operations.
Earnings Per Share, Policy [Policy Text Block]	Earnings (Loss) Per Share The Company computes basic earnings (loss) per share by dividing net income (loss) by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings (loss) per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.
New Accounting Matters [Policy Text Block]	New Accounting Matters Recently Adopted In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact or no significant impact on their respective financial statements except as indicated. • Goodwill impairment guidance, issued in January 2017, removed Step 2 of the goodwill impairment test. • Guidance for revenue arising from contracts with customers uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods were not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3. • The required presentation of net periodic pension and postretirement benefit costs has been changed to distinguish between service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees. Non-service cost components are now excluded from operating income. This guidance has been applied retrospectively for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017 and 2016. Increase (Decrease) Millions of dollars The Company Consolidated SCE&G Year Ended December 31 2017 2016 2017 2016 Other operation and maintenance $ (9 ) $ (14 ) $ (7 ) $ (12 ) Total Operating Expenses (9 ) (14 ) (7 ) (12 ) Operating Income 9 14 7 12 Other Income (Expense), Net (9 ) (14 ) (7 ) (12 ) In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost component, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs. Effective January 1, 2018, amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets. • Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things. • Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented. • Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented. Pending Adoption The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below. In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases currently classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged. The guidance is effective for the Company's and Consolidated SCE&G's interim and annual reporting periods beginning January 1, 2019. This revised accounting guidance will be adopted using a modified-retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Company and Consolidated SCE&G are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Company and Consolidated SCE&G will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. The Company and Consolidated SCE&G anticipate that the adoption of this guidance will result in approximately $30 million to $35 million and $15 million to $20 million , respectively, of offsetting right-of-use assets and liabilities added to their consolidated balance sheets for operating leases in effect at the adoption date. No material changes are expected to the Company's and Consolidated SCE&G's results of operations. In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 and do not expect it to have a significant impact on their respective financial statements. In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 on a prospective basis. Upon adoption, the Company and Consolidated SCE&G expect to record cumulative effect adjustments to retained earnings and AOCI in their statements of changes in common equity (in the amount of $8 million and $1 million at the Company and Consolidated SCE&G, respectively) and do not expect any other significant impact on their financial statements. The amounts to be reclassified reflect the impact of the reduction in the federal income tax rate arising from the Tax Act, and the related federal benefit of state income taxes, on the components of the Company’s and Consolidated SCE&G’s AOCI. In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. A modified-retrospective approach is required upon adoption, whereby a cumulative-effect adjustment to retained earnings is made as of the beginning of the first reporting period in which the guidance is effective. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements. In August 2018, the FASB issued accounting guidance to modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance must be applied retrospectively to all periods presented. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position.
SCE&G
Significant Accounting Policies
Consolidation, Policy [Policy Text Block]	Consolidated SCE&G SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA. Consolidated SCE&G primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina. SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $500 million ) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Property, Plant and Equipment, Planned Major Maintenance Activities, Policy [Policy Text Block]	Major Maintenance Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred. SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2018, and 2017, SCE&G incurred $16.3 million and $26.1 million , respectively, for turbine maintenance. Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 million annually for its portion of the nuclear refueling outages scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which SCE&G was responsible totaled
Nuclear Decommissiong [Policy Text Block]	Nuclear Decommissioning Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $625.8 million , stated in 2018 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. Under SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ( $3.2 million pre-tax in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. The asset balance held in trust reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Unit 1 on an after-tax basis.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds.
Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block]	Receivables Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described in Note 3. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $217.5 million at December 31, 2018 and $220.9 million at December 31, 2017 for the Company. Unbilled revenues totaled $129.3 million at December 31, 2018 and $140.3 million at December 31, 2017 for Consolidated SCE&G. Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station.
Inventory, Policy [Policy Text Block]	Inventories Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable.
Income Tax, Policy [Policy Text Block]	Income Taxes SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 6 for a discussion of the impact of adjustments recorded in connection with enactment of the Tax Act. Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA for all periods presented. Also, under provisions of an income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions.
regulatory assets and regulatory liabilities [Policy Text Block]	Regulatory Assets and Regulatory Liabilities The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods that differ from those in which the costs would be charged to expense, or record revenues in periods that differ from those in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified on the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively.
Debt Premium, Discount, and Expense [Policy Text Block]	Debt Issuance Premiums, Discounts and Other Costs Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred credits or debits and are amortized over the term of the replacement debt, also as interest charges.
Environmental Costs, Policy [Policy Text Block]	Environmental An environmental assessment program is maintained to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred.
Income Statement policy [Policy Text Block]	Statement of Operations Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense).
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed. Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings. SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews. Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of operations.
New Accounting Matters [Policy Text Block]	New Accounting Matters Recently Adopted In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact or no significant impact on their respective financial statements except as indicated. • Goodwill impairment guidance, issued in January 2017, removed Step 2 of the goodwill impairment test. • Guidance for revenue arising from contracts with customers uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods were not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3. • The required presentation of net periodic pension and postretirement benefit costs has been changed to distinguish between service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees. Non-service cost components are now excluded from operating income. This guidance has been applied retrospectively for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017 and 2016. Increase (Decrease) Millions of dollars The Company Consolidated SCE&G Year Ended December 31 2017 2016 2017 2016 Other operation and maintenance $ (9 ) $ (14 ) $ (7 ) $ (12 ) Total Operating Expenses (9 ) (14 ) (7 ) (12 ) Operating Income 9 14 7 12 Other Income (Expense), Net (9 ) (14 ) (7 ) (12 ) In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost component, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs. Effective January 1, 2018, amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets. • Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things. • Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented. • Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented. Pending Adoption The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below. In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases currently classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged. The guidance is effective for the Company's and Consolidated SCE&G's interim and annual reporting periods beginning January 1, 2019. This revised accounting guidance will be adopted using a modified-retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Company and Consolidated SCE&G are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Company and Consolidated SCE&G will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. The Company and Consolidated SCE&G anticipate that the adoption of this guidance will result in approximately $30 million to $35 million and $15 million to $20 million , respectively, of offsetting right-of-use assets and liabilities added to their consolidated balance sheets for operating leases in effect at the adoption date. No material changes are expected to the Company's and Consolidated SCE&G's results of operations. In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 and do not expect it to have a significant impact on their respective financial statements. In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 on a prospective basis. Upon adoption, the Company and Consolidated SCE&G expect to record cumulative effect adjustments to retained earnings and AOCI in their statements of changes in common equity (in the amount of $8 million and $1 million at the Company and Consolidated SCE&G, respectively) and do not expect any other significant impact on their financial statements. The amounts to be reclassified reflect the impact of the reduction in the federal income tax rate arising from the Tax Act, and the related federal benefit of state income taxes, on the components of the Company’s and Consolidated SCE&G’s AOCI. In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. A modified-retrospective approach is required upon adoption, whereby a cumulative-effect adjustment to retained earnings is made as of the beginning of the first reporting period in which the guidance is effective. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements. In August 2018, the FASB issued accounting guidance to modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance must be applied retrospectively to all periods presented. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2018
Significant Accounting Policies
Reclassifications [Text Block]	Increase (Decrease) Millions of dollars The Company Consolidated SCE&G Year Ended December 31 2017 2016 2017 2016 Other operation and maintenance $ (9 ) $ (14 ) $ (7 ) $ (12 ) Total Operating Expenses (9 ) (14 ) (7 ) (12 ) Operating Income 9 14 7 12 Other Income (Expense), Net (9 ) (14 ) (7 ) (12 )
Schedule of weighted avg depreciation rates [Table Text Block]	The Company Consolidated SCE&G Generation 2.61 % 2.61 % Transmission 2.47 % 2.74 % Distribution 2.48 % 2.41 % Storage 2.48 % 2.71 % General and other 5.64 % 3.18 %
SCE&G
Significant Accounting Policies
Reclassifications [Text Block]	Increase (Decrease) Millions of dollars The Company Consolidated SCE&G Year Ended December 31 2017 2016 2017 2016 Other operation and maintenance $ (9 ) $ (14 ) $ (7 ) $ (12 ) Total Operating Expenses (9 ) (14 ) (7 ) (12 ) Operating Income 9 14 7 12 Other Income (Expense), Net (9 ) (14 ) (7 ) (12 )
Schedule of weighted avg depreciation rates [Table Text Block]	The Company Consolidated SCE&G Generation 2.61 % 2.61 % Transmission 2.47 % 2.74 % Distribution 2.48 % 2.41 % Storage 2.48 % 2.71 % General and other 5.64 % 3.18 %

RATE AND OTHER REGULATORY MAT_2

RATE AND OTHER REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2018
Public Utilities, General Disclosures
Pipeline integrity management revenue requirement [Table Text Block]	Rates Effective 2018 2017 March 1 $14.7 million $1.9 million September 1 $1.1 million $0.7 million
Demand reduction programs [Table Text Block]	Year Effective Amount 2018 First billing cycle of May $33.0 million 2017 First billing cycle of May $37.0 million 2016 First billing cycle of May $37.6 million
Schedule of Changes in Gas Rate RSA [Table Text Block]	Year Action Amount 2018 4.6 % Decrease $19.7 million * 2017 2.2 % Increase $8.6 million 2016 1.2 % Increase $4.1 million
Schedule of Regulatory Assets [Table Text Block]	The Company Consolidated SCE&G December 31, December 31, Millions of dollars 2018 2017 2018 2017 Regulatory Assets: Unrecovered Nuclear Project costs $ 2,768 3,976 $ 2,768 3,976 AROs and related funding 406 434 380 410 Deferred employee benefit plan costs 302 305 272 273 Deferred losses on interest rate derivatives 448 456 448 456 Other unrecovered plant 93 105 93 105 DSM Programs 65 59 65 59 Pipeline integrity management costs 73 51 9 8 Environmental remediation costs 27 30 24 25 Deferred storm damage costs 35 24 35 24 Deferred transmission operating costs 15 — 15 — Other 148 140 147 140 Total Regulatory Assets $ 4,380 $ 5,580 $ 4,256 $ 5,476
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities: Monetization of guaranty settlement $ 1,098 1,095 $ 1,098 1,095 Accumulated deferred income taxes 814 1,076 659 914 Asset removal costs 779 757 541 527 Deferred gains on interest rate derivatives 77 131 77 131 Other 21 — 5 — Total Regulatory Liabilities $ 2,789 $ 3,059 $ 2,380 $ 2,667
SCE&G
Public Utilities, General Disclosures
Demand reduction programs [Table Text Block]	Year Effective Amount 2018 First billing cycle of May $33.0 million 2017 First billing cycle of May $37.0 million 2016 First billing cycle of May $37.6 million
Schedule of Changes in Gas Rate RSA [Table Text Block]	Year Action Amount 2018 4.6 % Decrease $19.7 million * 2017 2.2 % Increase $8.6 million 2016 1.2 % Increase $4.1 million
Schedule of Regulatory Assets [Table Text Block]	The Company Consolidated SCE&G December 31, December 31, Millions of dollars 2018 2017 2018 2017 Regulatory Assets: Unrecovered Nuclear Project costs $ 2,768 3,976 $ 2,768 3,976 AROs and related funding 406 434 380 410 Deferred employee benefit plan costs 302 305 272 273 Deferred losses on interest rate derivatives 448 456 448 456 Other unrecovered plant 93 105 93 105 DSM Programs 65 59 65 59 Pipeline integrity management costs 73 51 9 8 Environmental remediation costs 27 30 24 25 Deferred storm damage costs 35 24 35 24 Deferred transmission operating costs 15 — 15 — Other 148 140 147 140 Total Regulatory Assets $ 4,380 $ 5,580 $ 4,256 $ 5,476
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities: Monetization of guaranty settlement $ 1,098 1,095 $ 1,098 1,095 Accumulated deferred income taxes 814 1,076 659 914 Asset removal costs 779 757 541 527 Deferred gains on interest rate derivatives 77 131 77 131 Other 21 — 5 — Total Regulatory Liabilities $ 2,789 $ 3,059 $ 2,380 $ 2,667
PSNC Energy [Member]
Public Utilities, General Disclosures
Pipeline integrity management revenue requirement [Table Text Block]	Rates Effective 2018 2017 March 1 $14.7 million $1.9 million September 1 $1.1 million $0.7 million

REVENUE RECOGNITION Disaggregat

REVENUE RECOGNITION Disaggregation of Revenue and Capitalized Costs (Tables)	12 Months Ended
	Dec. 31, 2018
Capitalized Contract Cost [Table Text Block]	The Company and Consolidated SCE&G Millions of dollars Regulatory Assets January 1, 2018 $ 16.3 Additional costs — Amortization (1.5 ) Impairment — December 31, 2018 $ 14.8
Disaggregation Revenue [Table Text Block]	The Company Consolidated SCE&G PSNC Energy Total Gas-regulated Gas-nonregulated Millions of dollars Electric Gas-regulated Gas-regulated 2018 Customer class: Residential $ 1,054 $ 208 $ 325 $ 533 $ 244 Commercial 744 117 125 242 92 Industrial 385 92 15 107 422 Transportation — 13 32 45 — Other 132 4 — 4 38 Revenues from contracts with customers 2,315 434 497 931 796 Other operating revenues 12 1 3 4 — Total Operating Revenues $ 2,327 $ 435 $ 500 $ 935 $ 796
SCE&G
Capitalized Contract Cost [Table Text Block]	The Company and Consolidated SCE&G Millions of dollars Regulatory Assets January 1, 2018 $ 16.3 Additional costs — Amortization (1.5 ) Impairment — December 31, 2018 $ 14.8
Disaggregation Revenue [Table Text Block]	The Company Consolidated SCE&G PSNC Energy Total Gas-regulated Gas-nonregulated Millions of dollars Electric Gas-regulated Gas-regulated 2018 Customer class: Residential $ 1,054 $ 208 $ 325 $ 533 $ 244 Commercial 744 117 125 242 92 Industrial 385 92 15 107 422 Transportation — 13 32 45 — Other 132 4 — 4 38 Revenues from contracts with customers 2,315 434 497 931 796 Other operating revenues 12 1 3 4 — Total Operating Revenues $ 2,327 $ 435 $ 500 $ 935 $ 796

LONG-TERM AND SHORT-TERM DEBT (

LONG-TERM AND SHORT-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Instrument [Line Items]
Schedule of Debt [Table Text Block]	: The Company December 31, 2018 2017 Dollars in millions Maturity Balance Rate Balance Rate SCANA Medium Term Notes (unsecured) 2020 - 2022 $ 800 5.42 % $ 800 5.42 % SCANA Senior Notes (unsecured) (a) 2019 - 2034 70 3.44 % 75 2.18 % SCE&G First Mortgage Bonds (secured) 2021 - 2065 4,990 5.52 % 4,840 5.80 % GENCO Notes (secured) 2019 - 2024 40 5.49 % 207 5.94 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.52 % 122 3.52 % PSNC Energy Senior Debentures and Notes 2020 - 2047 700 5.07 % 600 5.19 % Other 2019 - 2027 73 3.46 % 28 2.83 % Total debt 6,795 6,672 Current maturities of long-term debt (59 ) (727 ) Unamortized discount, net (2 ) (1 ) Unamortized debt issuance costs (39 ) (38 ) Total long-term debt, net $ 6,695 $ 5,906
Schedule of Line of Credit Facilities [Text Block]	December 31, 2017 Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Three-year, expiring December 2018 200.0 — 200.0 — Total committed long-term 2,000.0 400.0 1,400.0 200.0 Outstanding commercial paper (270 or fewer days) 350.3 — 251.6 98.7 Weighted average interest rate 1.92 % 1.93 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,646.4 $ 397.0 $ 1,148.1 $ 101.3 : Millions of dollars Total SCANA SCE&G PSNC Energy December 31, 2018 Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Total committed long-term 1,800.0 400.0 1,200.0 200.0 LOC advances 40.0 40.0 — — Weighted average interest rate 3.87 % Outstanding commercial paper (270 or fewer days) 172.9 2.0 73.2 97.7 Weighted average interest rate 3.65 % 3.82 % 3.49 % Letters of credit supported by LOC 37.6 37.3 0.3 — Available $ 1,549.5 $ 320.7 $ 1,126.5 $ 102.3
SCE&G
Debt Instrument [Line Items]
Schedule of Debt [Table Text Block]	Consolidated SCE&G December 31, 2018 2017 Dollars in millions Maturity Balance Rate Balance Rate First Mortgage Bonds (secured) 2021 - 2065 $ 4,990 5.52 % $ 4,840 5.80 % GENCO Notes (secured) 2019 - 2024 40 5.49 % 207 5.94 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.52 % 122 3.52 % Other 2019 - 2027 30 2.97 % 28 2.83 % Total debt 5,182 5,197 Current maturities of long-term debt (14 ) (723 ) Unamortized premium (discount), net (1 ) 1 Unamortized debt issuance costs (35 ) (34 ) Total long-term debt, net $ 5,132 $ 4,441
Schedule of Line of Credit Facilities [Text Block]	Millions of dollars Total SCANA SCE&G PSNC Energy December 31, 2018 Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Total committed long-term 1,800.0 400.0 1,200.0 200.0 LOC advances 40.0 40.0 — — Weighted average interest rate 3.87 % Outstanding commercial paper (270 or fewer days) 172.9 2.0 73.2 97.7 Weighted average interest rate 3.65 % 3.82 % 3.49 % Letters of credit supported by LOC 37.6 37.3 0.3 — Available $ 1,549.5 $ 320.7 $ 1,126.5 $ 102.3 December 31, 2017 Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Three-year, expiring December 2018 200.0 — 200.0 — Total committed long-term 2,000.0 400.0 1,400.0 200.0 Outstanding commercial paper (270 or fewer days) 350.3 — 251.6 98.7 Weighted average interest rate 1.92 % 1.93 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,646.4 $ 397.0 $ 1,148.1 $ 101.3

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2018
Investments, Owned, Federal Income Tax Note [Line Items]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	: The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 Current taxes (benefit): Federal $ (8 ) $ (414 ) $ 36 $ (16 ) $ (410 ) $ 50 State 5 18 13 — (18 ) 13 Total current taxes (benefit) (3 ) (396 ) 49 (16 ) (428 ) 63 Deferred tax (benefit) expense, net: Federal (352 ) 323 203 (346 ) 261 167 State (55 ) (37 ) 21 (52 ) (2 ) 20 Total deferred taxes (benefit) (407 ) 286 224 (398 ) 259 187 Investment tax credits: Amortization of amounts deferred-federal (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Total income tax expense (benefit) $ (412 ) $ (112 ) $ 271 $ (416 ) $ (171 ) $ 248
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	: The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 U.S. statutory rate 21 % 35 % 35 % 21 % 35 % 35 % Net income (loss) $ (528 ) $ (119 ) $ 595 $ (614 ) $ (185 ) $ 513 Income tax expense (benefit) (412 ) (112 ) 271 (416 ) (171 ) 248 Noncontrolling interest — — — 25 13 13 Total pre-tax income (loss) $ (940 ) $ (231 ) $ 866 $ (1,005 ) $ (343 ) $ 774 Income taxes (benefit) on above at statutory federal income tax rate $ (197 ) $ (81 ) $ 303 $ (211 ) $ (120 ) $ 271 Increases (decreases) attributed to: State income taxes (less federal income tax effect) (37 ) (7 ) 27 (38 ) (8 ) 26 State investment tax credits (less federal income tax effect) (3 ) (5 ) (5 ) (3 ) (5 ) (5 ) Allowance for equity funds used during construction (4 ) (8 ) (10 ) (2 ) (5 ) (9 ) Deductible dividends—401(k) Retirement Savings Plan (2 ) (9 ) (10 ) — — — Amortization of federal investment tax credits (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Section 45 tax credits (9 ) (8 ) (8 ) (9 ) (8 ) (8 ) Domestic production activities deduction — (18 ) (23 ) — (18 ) (23 ) Remeasurement of deferred taxes in connection with enactment of Tax Act (188 ) 30 — (176 ) (1 ) — Nuclear Project impairment 23 — — 23 — — Nondeductible merger-related costs 5 — — — — — Other differences, net 2 (4 ) (1 ) 2 (4 ) (2 ) Total income tax expense (benefit) $ (412 ) $ (112 ) $ 271 $ (416 ) $ (171 ) $ 248
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	: The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Deferred tax assets: Net operating loss and tax credit carryforward $ 539 $ 600 $ 493 $ 541 Toshiba settlement 274 273 274 273 Nondeductible accruals 84 88 40 42 Asset retirement obligation, including nuclear decommissioning 143 141 135 132 Regulatory liability, non-property accumulated deferred income tax — 54 — 54 Financial instruments 10 15 — — Unamortized investment tax credits 7 8 7 8 Other 4 6 5 5 Total deferred tax assets 1,061 1,185 954 1,055 Deferred tax liabilities: Property, plant and equipment 1,227 1,220 1,033 1,035 Regulatory asset, unrecovered nuclear plant costs 668 962 668 962 Deferred employee benefit plan costs 60 60 53 53 Regulatory asset, asset retirement obligation 94 91 88 85 Regulatory asset, other unrecovered plant 24 27 24 27 Demand side management costs 16 16 16 16 Prepayments 21 21 20 19 Other 63 49 41 31 Total deferred tax liabilities 2,173 2,446 1,943 2,228 Net deferred tax liabilities $ 1,112 $ 1,261 $ 989 $ 1,173
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 Unrecognized tax benefits, January 1 $ 98 $ 350 $ 49 $ 98 $ 350 $ 49 Gross increases—uncertain tax positions in prior period 8 — 94 8 — 94 Gross decreases—uncertain tax positions in prior period — (273 ) — — (273 ) — Gross increases—current period uncertain tax positions — 21 207 — 21 207 Unrecognized tax benefits, December 31 $ 106 $ 98 $ 350 $ 106 $ 98 $ 350
Summary of Tax Credit Carryforwards [Table Text Block]	The federal and state tax credits and NOL carryforwards are presented below: December 31, 2018 Millions of dollars The Company Consolidated SCE&G Expiration Year Federal NOL Carryforwards $ 1,807 $ 1,642 2037 Federal Tax Credits 83 83 2035 - 2038 State NOL Carryforwards 2,447 2,198 2037 State Tax Credits 30 30 2026 - 2033 Total Tax Credits and NOL Carryforwards $ 4,367 $ 3,953
SCE&G
Investments, Owned, Federal Income Tax Note [Line Items]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	: The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 Current taxes (benefit): Federal $ (8 ) $ (414 ) $ 36 $ (16 ) $ (410 ) $ 50 State 5 18 13 — (18 ) 13 Total current taxes (benefit) (3 ) (396 ) 49 (16 ) (428 ) 63 Deferred tax (benefit) expense, net: Federal (352 ) 323 203 (346 ) 261 167 State (55 ) (37 ) 21 (52 ) (2 ) 20 Total deferred taxes (benefit) (407 ) 286 224 (398 ) 259 187 Investment tax credits: Amortization of amounts deferred-federal (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Total income tax expense (benefit) $ (412 ) $ (112 ) $ 271 $ (416 ) $ (171 ) $ 248
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 U.S. statutory rate 21 % 35 % 35 % 21 % 35 % 35 % Net income (loss) $ (528 ) $ (119 ) $ 595 $ (614 ) $ (185 ) $ 513 Income tax expense (benefit) (412 ) (112 ) 271 (416 ) (171 ) 248 Noncontrolling interest — — — 25 13 13 Total pre-tax income (loss) $ (940 ) $ (231 ) $ 866 $ (1,005 ) $ (343 ) $ 774 Income taxes (benefit) on above at statutory federal income tax rate $ (197 ) $ (81 ) $ 303 $ (211 ) $ (120 ) $ 271 Increases (decreases) attributed to: State income taxes (less federal income tax effect) (37 ) (7 ) 27 (38 ) (8 ) 26 State investment tax credits (less federal income tax effect) (3 ) (5 ) (5 ) (3 ) (5 ) (5 ) Allowance for equity funds used during construction (4 ) (8 ) (10 ) (2 ) (5 ) (9 ) Deductible dividends—401(k) Retirement Savings Plan (2 ) (9 ) (10 ) — — — Amortization of federal investment tax credits (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Section 45 tax credits (9 ) (8 ) (8 ) (9 ) (8 ) (8 ) Domestic production activities deduction — (18 ) (23 ) — (18 ) (23 ) Remeasurement of deferred taxes in connection with enactment of Tax Act (188 ) 30 — (176 ) (1 ) — Nuclear Project impairment 23 — — 23 — — Nondeductible merger-related costs 5 — — — — — Other differences, net 2 (4 ) (1 ) 2 (4 ) (2 ) Total income tax expense (benefit) $ (412 ) $ (112 ) $ 271 $ (416 ) $ (171 ) $ 248
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Deferred tax assets: Net operating loss and tax credit carryforward $ 539 $ 600 $ 493 $ 541 Toshiba settlement 274 273 274 273 Nondeductible accruals 84 88 40 42 Asset retirement obligation, including nuclear decommissioning 143 141 135 132 Regulatory liability, non-property accumulated deferred income tax — 54 — 54 Financial instruments 10 15 — — Unamortized investment tax credits 7 8 7 8 Other 4 6 5 5 Total deferred tax assets 1,061 1,185 954 1,055 Deferred tax liabilities: Property, plant and equipment 1,227 1,220 1,033 1,035 Regulatory asset, unrecovered nuclear plant costs 668 962 668 962 Deferred employee benefit plan costs 60 60 53 53 Regulatory asset, asset retirement obligation 94 91 88 85 Regulatory asset, other unrecovered plant 24 27 24 27 Demand side management costs 16 16 16 16 Prepayments 21 21 20 19 Other 63 49 41 31 Total deferred tax liabilities 2,173 2,446 1,943 2,228 Net deferred tax liabilities $ 1,112 $ 1,261 $ 989 $ 1,173
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 Unrecognized tax benefits, January 1 $ 98 $ 350 $ 49 $ 98 $ 350 $ 49 Gross increases—uncertain tax positions in prior period 8 — 94 8 — 94 Gross decreases—uncertain tax positions in prior period — (273 ) — — (273 ) — Gross increases—current period uncertain tax positions — 21 207 — 21 207 Unrecognized tax benefits, December 31 $ 106 $ 98 $ 350 $ 106 $ 98 $ 350
Summary of Tax Credit Carryforwards [Table Text Block]	The federal and state tax credits and NOL carryforwards are presented below: December 31, 2018 Millions of dollars The Company Consolidated SCE&G Expiration Year Federal NOL Carryforwards $ 1,807 $ 1,642 2037 Federal Tax Credits 83 83 2035 - 2038 State NOL Carryforwards 2,447 2,198 2037 State Tax Credits 30 30 2026 - 2033 Total Tax Credits and NOL Carryforwards $ 4,367 $ 3,953

DERIVATIVE FINANCIAL INSTRUME_2

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative [Line Items]
Schedule of Nonmonetary Notional Amounts of Outstanding Derivative Positions [Table Text Block]	The Company was party to natural gas derivative contracts outstanding in the following quantities: Commodity and Energy Management Contracts (in bcf) Hedge designation Gas Distribution Gas Marketing Total As of December 31, 2018 Commodity 6.4 12.9 19.3 Energy Management (a) — 46.8 46.8 Total (a) 6.4 59.7 66.1 As of December 31, 2017 Commodity 6.4 13.4 19.8 Energy Management (a) — 41.9 41.9 Total (a) 6.4 55.3 61.7 (a) Includes amounts related to basis swap contracts totaling 5.1 bcf in 2018 and 2.6 bcf in 2017.
Schedule of Derivative Instruments [Table Text Block]	The aggregate notional amounts of the interest rate swaps were as follows: Interest Rate Swaps The Company Consolidated SCE&G Millions of dollars December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 Designated as hedging instruments $ 106.8 $ 111.2 $ 36.4 $ 36.4 Not designated as hedging instruments 35.0 735.0 35.0 735.0
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of December 31, 2018 Designated as hedging instruments Interest rate contracts Other current liabilities — $ 2 — $ 1 Other deferred credits and other liabilities — 19 — 7 Commodity contracts Prepayments — 1 — — Total — $ 22 — $ 8 Not designated as hedging instruments Interest rate contracts Other deferred credits and other liabilities — $ 3 — $ 3 Commodity contracts Prepayments $ 1 — — — Energy management contracts Prepayments 11 12 — — Other current assets 1 — — — Other current liabilities — 1 — — Other deferred debits and other assets 1 — — — Total $ 14 $ 16 — $ 3 As of December 31, 2017 Designated as hedging instruments Interest rate contracts Other current liabilities — $ 3 — $ 1 Other deferred credits and other liabilities — 24 — 9 Commodity contracts Prepayments — 2 — — Other current liabilities — 1 — — Total — $ 30 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets and current liabilities $ 54 $ 1 $ 54 $ 1 Other deferred credits and other liabilities — 4 — 4 Commodity contracts Other current assets 1 — — — Energy management contracts Prepayments — 1 — — Other current assets 3 — — — Other deferred debits and other assets 1 — — — Other current liabilities — 2 — — Total $ 59 $ 8 $ 54 $ 5
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	The effect of derivative instruments on the consolidated statements of operations is as follows: The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2018 Interest rate contracts $ 1 Interest expense $ (1 ) Year Ended December 31, 2017 Interest rate contracts $ (2 ) Interest expense $ (2 ) Year Ended December 31, 2016 Interest rate contracts — Interest expense $ (2 ) The Company: Gain (Loss) Recognized in OCI, net of tax Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2018 Interest rate contracts $ 1 Interest expense $ (9 ) Commodity contracts (3 ) Gas purchased for resale (7 ) Total $ (2 ) $ (16 ) Year Ended December 31, 2017 Interest rate contracts — Interest expense $ (7 ) Commodity contracts $ (7 ) Gas purchased for resale 1 Total $ (7 ) $ (6 ) Year Ended December 31, 2016 Interest rate contracts $ (1 ) Interest expense $ (7 ) Commodity contracts 5 Gas purchased for resale (6 ) Total $ 4 $ (13 )
Derivatives Not Designated as Hedging Instruments [Table Text Block]	Derivatives Not Designated as Hedging Instruments The Company and Consolidated SCE&G: Gain (Loss) Deferred in Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars Regulatory Accounts Location Amount Year Ended December 31, 2018 Interest rate contracts $ 64 Interest Expense $ (2 ) Interest rate contracts Other Income 115 Year Ended December 31, 2017 Interest rate contracts $ (32 ) Interest Expense $ (3 ) Interest rate contracts Impairment Loss (173 ) Year Ended December 31, 2016 Interest rate contracts $ (34 ) Other income $ (2 )
Disclosure of Credit Derivatives [Table Text Block]	The Company Consolidated SCE&G Millions of dollars December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 24.8 $ 33.7 $ 11.2 $ 14.7 Fair value of collateral already posted 24.3 28.9 11.0 10.1 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ 0.5 $ 4.8 $ 0.2 $ 4.6 in Net Asset Position Aggregate fair value of derivatives in net asset position — $ 53.5 — $ 53.5 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — $ 53.5 — $ 53.5
Offsetting Assets [Table Text Block]	Information related to the offsetting derivative assets follows: Derivative Assets The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 2018 Gross Amounts of Recognized Assets — $ 1 $ 13 $ 14 — Gross Amounts Offset in Statement of Financial Position — — (11 ) (11 ) — Net Amounts Presented in Statement of Financial Position — 1 2 3 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 1 $ 2 $ 3 — Balance sheet location Prepayments $ 12 — Other current assets 1 — Other deferred debits and other assets 1 — Total $ 14 — As of December 31, 2017 Gross Amounts of Recognized Assets $ 54 $ 1 $ 4 $ 59 $ 54 Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position 54 1 4 59 54 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 54 $ 1 $ 4 $ 59 $ 54 Balance sheet location Other current assets $ 58 $ 54 Other deferred debits and other assets 1 — Total $ 59 $ 54
Offsetting Liabilities [Table Text Block]	Information related to the offsetting of derivative liabilities follows: Derivative Liabilities The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 2018 Gross Amounts of Recognized Liabilities $ 24 $ 1 $ 13 $ 38 $ 11 Gross Amounts Offset in Statement of Financial Position — — (11 ) (11 ) — Net Amounts Presented in Statement of Financial Position 24 1 2 27 11 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (24 ) — — (24 ) (11 ) Net Amount — $ 1 $ 2 $ 3 — Balance sheet location Prepayments $ 13 — Other current liabilities 3 $ 1 Other deferred credits and other liabilities 22 10 Total $ 38 $ 11 Derivative Liabilities The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 2017 Gross Amounts of Recognized Liabilities $ 32 $ 3 $ 3 $ 38 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 32 3 2 37 15 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (28 ) — (1 ) (29 ) — Net Amount $ 4 3 $ 1 $ 8 $ 15 Balance sheet location Other current assets $ 2 — Other current liabilities 7 $ 2 Other deferred credits and other liabilities 28 13 Total $ 37 $ 15
SCE&G
Derivative [Line Items]
Schedule of Derivative Instruments [Table Text Block]	The aggregate notional amounts of the interest rate swaps were as follows: Interest Rate Swaps The Company Consolidated SCE&G Millions of dollars December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 Designated as hedging instruments $ 106.8 $ 111.2 $ 36.4 $ 36.4 Not designated as hedging instruments 35.0 735.0 35.0 735.0
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of December 31, 2018 Designated as hedging instruments Interest rate contracts Other current liabilities — $ 2 — $ 1 Other deferred credits and other liabilities — 19 — 7 Commodity contracts Prepayments — 1 — — Total — $ 22 — $ 8 Not designated as hedging instruments Interest rate contracts Other deferred credits and other liabilities — $ 3 — $ 3 Commodity contracts Prepayments $ 1 — — — Energy management contracts Prepayments 11 12 — — Other current assets 1 — — — Other current liabilities — 1 — — Other deferred debits and other assets 1 — — — Total $ 14 $ 16 — $ 3 As of December 31, 2017 Designated as hedging instruments Interest rate contracts Other current liabilities — $ 3 — $ 1 Other deferred credits and other liabilities — 24 — 9 Commodity contracts Prepayments — 2 — — Other current liabilities — 1 — — Total — $ 30 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets and current liabilities $ 54 $ 1 $ 54 $ 1 Other deferred credits and other liabilities — 4 — 4 Commodity contracts Other current assets 1 — — — Energy management contracts Prepayments — 1 — — Other current assets 3 — — — Other deferred debits and other assets 1 — — — Other current liabilities — 2 — — Total $ 59 $ 8 $ 54 $ 5
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	The effect of derivative instruments on the consolidated statements of operations is as follows: The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2018 Interest rate contracts $ 1 Interest expense $ (1 ) Year Ended December 31, 2017 Interest rate contracts $ (2 ) Interest expense $ (2 ) Year Ended December 31, 2016 Interest rate contracts — Interest expense $ (2 )
Derivatives Not Designated as Hedging Instruments [Table Text Block]	Derivatives Not Designated as Hedging Instruments The Company and Consolidated SCE&G: Gain (Loss) Deferred in Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars Regulatory Accounts Location Amount Year Ended December 31, 2018 Interest rate contracts $ 64 Interest Expense $ (2 ) Interest rate contracts Other Income 115 Year Ended December 31, 2017 Interest rate contracts $ (32 ) Interest Expense $ (3 ) Interest rate contracts Impairment Loss (173 ) Year Ended December 31, 2016 Interest rate contracts $ (34 ) Other income $ (2 )
Disclosure of Credit Derivatives [Table Text Block]	The Company Consolidated SCE&G Millions of dollars December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 24.8 $ 33.7 $ 11.2 $ 14.7 Fair value of collateral already posted 24.3 28.9 11.0 10.1 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ 0.5 $ 4.8 $ 0.2 $ 4.6 in Net Asset Position Aggregate fair value of derivatives in net asset position — $ 53.5 — $ 53.5 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — $ 53.5 — $ 53.5
Offsetting Assets [Table Text Block]	Information related to the offsetting derivative assets follows: Derivative Assets The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 2018 Gross Amounts of Recognized Assets — $ 1 $ 13 $ 14 — Gross Amounts Offset in Statement of Financial Position — — (11 ) (11 ) — Net Amounts Presented in Statement of Financial Position — 1 2 3 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 1 $ 2 $ 3 — Balance sheet location Prepayments $ 12 — Other current assets 1 — Other deferred debits and other assets 1 — Total $ 14 — As of December 31, 2017 Gross Amounts of Recognized Assets $ 54 $ 1 $ 4 $ 59 $ 54 Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position 54 1 4 59 54 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 54 $ 1 $ 4 $ 59 $ 54 Balance sheet location Other current assets $ 58 $ 54 Other deferred debits and other assets 1 — Total $ 59 $ 54
Offsetting Liabilities [Table Text Block]	Information related to the offsetting of derivative liabilities follows: Derivative Liabilities The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 2018 Gross Amounts of Recognized Liabilities $ 24 $ 1 $ 13 $ 38 $ 11 Gross Amounts Offset in Statement of Financial Position — — (11 ) (11 ) — Net Amounts Presented in Statement of Financial Position 24 1 2 27 11 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (24 ) — — (24 ) (11 ) Net Amount — $ 1 $ 2 $ 3 — Balance sheet location Prepayments $ 13 — Other current liabilities 3 $ 1 Other deferred credits and other liabilities 22 10 Total $ 38 $ 11 Derivative Liabilities The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 2017 Gross Amounts of Recognized Liabilities $ 32 $ 3 $ 3 $ 38 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 32 3 2 37 15 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (28 ) — (1 ) (29 ) — Net Amount $ 4 3 $ 1 $ 8 $ 15 Balance sheet location Other current assets $ 2 — Other current liabilities 7 $ 2 Other deferred credits and other liabilities 28 13 Total $ 37 $ 15

FAIR VALUE MEASUREMENTS, INCL_2

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Measurement Inputs, Disclosure [Table Text Block]	As of December 31, 2018 As of December 31, 2017 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 1 Level 2 Level 1 Level 2 Level 1 Level 2 Assets: Available for sale securities — — — — $ 119 — $ 100 — Held to maturity securities — $ 6 — — — $ 6 — — Interest rate contracts — — — — — 54 — $ 54 Commodity contracts $ 1 — — — 1 — — — Energy management contracts 11 2 — — — 4 — — Liabilities: Interest rate contracts — 24 — $ 11 — 32 — 15 Commodity contracts 1 — — — 2 1 — — Energy management contracts 12 3 — — 1 4 — —
Fair Value, by Balance Sheet Grouping [Table Text Block]	As of December 31, 2018 As of December 31, 2017 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,753.9 $ 7,180.8 $ 6,632.9 $ 7,399.7 Consolidated SCE&G 5,145.6 5,469.7 5,163.3 5,790.3
SCE&G
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Measurement Inputs, Disclosure [Table Text Block]	As of December 31, 2018 As of December 31, 2017 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 1 Level 2 Level 1 Level 2 Level 1 Level 2 Assets: Available for sale securities — — — — $ 119 — $ 100 — Held to maturity securities — $ 6 — — — $ 6 — — Interest rate contracts — — — — — 54 — $ 54 Commodity contracts $ 1 — — — 1 — — — Energy management contracts 11 2 — — — 4 — — Liabilities: Interest rate contracts — 24 — $ 11 — 32 — 15 Commodity contracts 1 — — — 2 1 — — Energy management contracts 12 3 — — 1 4 — —
Fair Value, by Balance Sheet Grouping [Table Text Block]	As of December 31, 2018 As of December 31, 2017 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,753.9 $ 7,180.8 $ 6,632.9 $ 7,399.7 Consolidated SCE&G 5,145.6 5,469.7 5,163.3 5,790.3

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Schedule of Changes in Projected Benefit Obligations [Table Text Block]	The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below. The Company Consolidated SCE&G Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2018 2017 2018 2017 2018 2017 Benefit obligation, January 1 $ 933.2 $ 904.3 $ 289.2 $ 274.7 $ 793.0 $ 768.4 $ 216.6 $ 207.2 Service cost 21.0 21.7 4.6 4.5 17.1 18.1 3.6 3.7 Interest cost 34.1 37.4 10.1 11.5 29.0 31.9 8.0 9.5 Plan participants’ contributions — — 1.4 1.3 — — 1.1 1.1 Actuarial (gain) loss (53.1 ) 42.2 (38.4 ) 9.7 (45.5 ) 36.6 (30.7 ) 6.8 Benefits paid (71.7 ) (72.4 ) (13.2 ) (12.5 ) (61.3 ) (62.0 ) (10.4 ) (10.3 ) Amounts funded to parent n/a n/a n/a n/a — — (0.8 ) (1.4 ) Benefit obligation, December 31 $ 863.5 $ 933.2 $ 253.7 $ 289.2 $ 732.3 $ 793.0 $ 187.4 $ 216.6
Schedule of Assumptions Used to Determine Benefit Obligations [Table Text Block]	Significant assumptions used to determine the above benefit obligations are as follows: Pension Benefits Other Postretirement Benefits 2018 2017 2018 2017 Annual discount rate used to determine benefit obligation 4.35 % 3.71 % 4.38 % 3.74 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 %
Schedule of Net Funded Status [Table Text Block]	The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Fair value of plan assets $ 727.3 $ 849.6 — — $ 676.7 $ 781.3 — — Benefit obligation 863.5 933.2 $ 253.7 $ 289.2 732.3 793.0 $ 187.4 $ 216.6 Funded status $ (136.2 ) $ (83.6 ) $ (253.7 ) $ (289.2 ) $ (55.6 ) $ (11.7 ) $ (187.4 ) $ (216.6 )
Schedule of Amounts Recognized in Balance Sheet [Table Text Block]	Amounts recognized on the consolidated balance sheets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Current liability — — $ (13.3 ) $ (13.5 ) — — $ (10.5 ) $ (10.8 ) Noncurrent liability $ (136.2 ) $ (83.6 ) (240.4 ) (275.7 ) $ (55.6 ) $ (11.7 ) (176.9 ) (205.8 )
Schedule of Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Other changes in plan assets and benefit obligations recognized in OCI (net of tax) were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Current year actuarial (gain) loss $ 4.5 $ (1.0 ) $ 0.6 $ (2.4 ) $ 1.1 $ 0.8 Amortization of actuarial losses (0.5 ) (0.6 ) (0.6 ) — (0.1 ) — Amortization of prior service cost — — (0.1 ) — — — Total recognized in OCI $ 4.0 $ (1.6 ) $ (0.1 ) $ (2.4 ) $ 1.0 $ 0.8
Schedule of defined benefit plan, amounts recognized in regulatory assets [Table Text Block]	Amounts recognized in regulatory assets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Net actuarial loss $ 230.4 $ 194.8 $ 10.9 $ 43.3 $ 202.4 $ 171.4 $ 9.0 $ 35.9 Prior service cost 0.7 1.2 — — 0.6 1.0 — — Total $ 231.1 $ 196.0 $ 10.9 $ 43.3 $ 203.0 $ 172.4 $ 9.0 $ 35.9
Schedule of Changes in Fair Value of Plan Assets [Table Text Block]	Pension Benefits The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Fair value of plan assets, January 1 $ 849.6 $ 793.6 $ 781.3 $ 732.9 Actual return (loss) on plan assets (50.6 ) 128.4 (43.3 ) 110.4 Benefits paid (71.7 ) (72.4 ) (61.3 ) (62.0 ) Fair value of plan assets, December 31 $ 727.3 $ 849.6 $ 676.7 $ 781.3
Schedule of Allocation of Plan Assets [Table Text Block]	The pension plan asset allocation at December 31, 2018 and 2017 and the target allocation for 2019 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2019 2018 2017 Equity Securities 58 % 55 % 58 % Fixed Income 33 % 34 % 31 % Hedge Funds 9 % 11 % 11 %
Schedule of Fair Value of Plan, Assets by Measurement Levels [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Investments with fair value measure at Level 2: Mutual funds $ 107 $ 120 $ 99 $ 110 Short-term investment vehicles 20 17 19 16 US Treasury securities 7 15 7 14 Corporate debt instruments 92 91 86 84 Government and other debt instruments 18 17 16 15 Total assets in the fair value hierarchy 244 260 227 239 Investments at net asset value: Common collective trust 400 498 373 458 Joint venture interests 83 92 77 84 Total investments at fair value $ 727 $ 850 $ 677 $ 781
Schedule of Expected Benefit Payments [Table Text Block]	The Company Consolidated SCE&G Millions of dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits 2019 $ 71.5 $ 13.6 $ 71.5 $ 10.8 2020 62.4 14.3 62.4 11.4 2021 65.6 14.9 65.6 11.8 2022 69.6 15.4 69.6 12.2 2023 66.6 15.8 66.6 12.6 2024-2028 284.9 82.3 284.9 65.4
Schedule of Net Benefit Costs [Table Text Block]	The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Service cost $ 21.0 $ 21.7 $ 20.7 $ 4.6 $ 4.5 $ 4.4 Interest cost 34.1 37.4 39.4 10.1 11.5 12.1 Expected return on assets (56.7 ) (54.7 ) (55.9 ) n/a n/a n/a Prior service cost amortization 0.5 1.6 3.9 — — 0.3 Amortization of actuarial losses 12.8 16.3 14.8 0.7 1.0 0.5 Net periodic benefit cost $ 11.7 $ 22.3 $ 22.9 $ 15.4 $ 17.0 $ 17.3
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]	Amounts recognized in accumulated other comprehensive loss were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Net actuarial loss $ 12.8 $ 8.8 $ 1.1 $ 3.5 $ 3.4 $ 2.1 $ 0.5 $ 1.5 Prior service cost 0.1 0.1 — — — — — — Total $ 12.9 $ 8.9 $ 1.1 $ 3.5 $ 3.4 $ 2.1 $ 0.5 $ 1.5
Schedule of defined benefit plan, Other changes in plan assets recognized in regulatory assets [Table Text Block]	Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Current year actuarial (gain) loss $ 46.7 $ (27.1 ) $ 29.4 $ (31.8 ) $ 9.4 $ 11.1 Amortization of actuarial losses (11.1 ) (14.1 ) (12.7 ) (0.6 ) (0.8 ) (0.4 ) Amortization of prior service cost (0.5 ) (1.4 ) (3.4 ) — — (0.3 ) Total recognized in regulatory assets $ 35.1 $ (42.6 ) $ 13.3 $ (32.4 ) $ 8.6 $ 10.4
Schedule of Assumptions Used in Determining Net Periodic Benefit Cost [Table Text Block]	Pension Benefits Other Postretirement Benefits 2018 2017 2016 2018 2017 2016 Discount rate 3.71 % 4.22 % 4.68 % 3.74 % 4.30 % 4.78 % Expected return on plan assets 7.00 % 7.25 % 7.50 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % Health care cost trend rate n/a n/a n/a 7.00 % 6.60 % 7.00 % Ultimate health care cost trend rate n/a n/a n/a 5.00 % 5.00 % 5.00 % Year achieved n/a n/a n/a 2023 2021 2021
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]	The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2019 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant : Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 0.8 —
Schedule of amounts in regulatory assets to be recognized over the next fiscal year [Table Text Block]	The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2019 are as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Actuarial loss $ 14.7 — $ 12.9 — Prior service cost 0.3 — 0.3 — Total $ 15.0 — $ 13.2 —
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Schedule of Changes in Projected Benefit Obligations [Table Text Block]	The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below. The Company Consolidated SCE&G Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2018 2017 2018 2017 2018 2017 Benefit obligation, January 1 $ 933.2 $ 904.3 $ 289.2 $ 274.7 $ 793.0 $ 768.4 $ 216.6 $ 207.2 Service cost 21.0 21.7 4.6 4.5 17.1 18.1 3.6 3.7 Interest cost 34.1 37.4 10.1 11.5 29.0 31.9 8.0 9.5 Plan participants’ contributions — — 1.4 1.3 — — 1.1 1.1 Actuarial (gain) loss (53.1 ) 42.2 (38.4 ) 9.7 (45.5 ) 36.6 (30.7 ) 6.8 Benefits paid (71.7 ) (72.4 ) (13.2 ) (12.5 ) (61.3 ) (62.0 ) (10.4 ) (10.3 ) Amounts funded to parent n/a n/a n/a n/a — — (0.8 ) (1.4 ) Benefit obligation, December 31 $ 863.5 $ 933.2 $ 253.7 $ 289.2 $ 732.3 $ 793.0 $ 187.4 $ 216.6
Schedule of Assumptions Used to Determine Benefit Obligations [Table Text Block]	Significant assumptions used to determine the above benefit obligations are as follows: Pension Benefits Other Postretirement Benefits 2018 2017 2018 2017 Annual discount rate used to determine benefit obligation 4.35 % 3.71 % 4.38 % 3.74 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 %
Schedule of Net Funded Status [Table Text Block]	The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Fair value of plan assets $ 727.3 $ 849.6 — — $ 676.7 $ 781.3 — — Benefit obligation 863.5 933.2 $ 253.7 $ 289.2 732.3 793.0 $ 187.4 $ 216.6 Funded status $ (136.2 ) $ (83.6 ) $ (253.7 ) $ (289.2 ) $ (55.6 ) $ (11.7 ) $ (187.4 ) $ (216.6 )
Schedule of Amounts Recognized in Balance Sheet [Table Text Block]	Amounts recognized in accumulated other comprehensive loss were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Net actuarial loss $ 12.8 $ 8.8 $ 1.1 $ 3.5 $ 3.4 $ 2.1 $ 0.5 $ 1.5 Prior service cost 0.1 0.1 — — — — — — Total $ 12.9 $ 8.9 $ 1.1 $ 3.5 $ 3.4 $ 2.1 $ 0.5 $ 1.5
Schedule of Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Current year actuarial loss $ 1.4 $ 0.3 — $ (1.0 ) $ 0.5 $ 0.3 Amortization of actuarial losses (0.1 ) (0.1 ) $ (0.1 ) — — — Total recognized in OCI $ 1.3 $ 0.2 $ (0.1 ) $ (1.0 ) $ 0.5 $ 0.3
Schedule of defined benefit plan, amounts recognized in regulatory assets [Table Text Block]	Amounts recognized in regulatory assets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Net actuarial loss $ 230.4 $ 194.8 $ 10.9 $ 43.3 $ 202.4 $ 171.4 $ 9.0 $ 35.9 Prior service cost 0.7 1.2 — — 0.6 1.0 — — Total $ 231.1 $ 196.0 $ 10.9 $ 43.3 $ 203.0 $ 172.4 $ 9.0 $ 35.9
Schedule of Changes in Fair Value of Plan Assets [Table Text Block]	Pension Benefits The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Fair value of plan assets, January 1 $ 849.6 $ 793.6 $ 781.3 $ 732.9 Actual return (loss) on plan assets (50.6 ) 128.4 (43.3 ) 110.4 Benefits paid (71.7 ) (72.4 ) (61.3 ) (62.0 ) Fair value of plan assets, December 31 $ 727.3 $ 849.6 $ 676.7 $ 781.3
Schedule of Allocation of Plan Assets [Table Text Block]	The pension plan asset allocation at December 31, 2018 and 2017 and the target allocation for 2019 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2019 2018 2017 Equity Securities 58 % 55 % 58 % Fixed Income 33 % 34 % 31 % Hedge Funds 9 % 11 % 11 %
Schedule of Fair Value of Plan, Assets by Measurement Levels [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Investments with fair value measure at Level 2: Mutual funds $ 107 $ 120 $ 99 $ 110 Short-term investment vehicles 20 17 19 16 US Treasury securities 7 15 7 14 Corporate debt instruments 92 91 86 84 Government and other debt instruments 18 17 16 15 Total assets in the fair value hierarchy 244 260 227 239 Investments at net asset value: Common collective trust 400 498 373 458 Joint venture interests 83 92 77 84 Total investments at fair value $ 727 $ 850 $ 677 $ 781
Schedule of Expected Benefit Payments [Table Text Block]	The Company Consolidated SCE&G Millions of dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits 2019 $ 71.5 $ 13.6 $ 71.5 $ 10.8 2020 62.4 14.3 62.4 11.4 2021 65.6 14.9 65.6 11.8 2022 69.6 15.4 69.6 12.2 2023 66.6 15.8 66.6 12.6 2024-2028 284.9 82.3 284.9 65.4
Schedule of Net Benefit Costs [Table Text Block]	Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Service cost $ 17.1 $ 18.1 $ 16.9 $ 3.6 $ 3.7 $ 3.6 Interest cost 29.0 31.9 33.4 8.0 9.5 9.9 Expected return on assets (48.1 ) (46.7 ) (47.4 ) n/a n/a n/a Prior service cost amortization 0.4 1.4 3.4 — — 0.3 Amortization of actuarial losses 10.9 13.9 12.5 0.6 0.8 0.4 Net periodic benefit cost $ 9.3 $ 18.6 $ 18.8 $ 12.2 $ 14.0 $ 14.2
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]	Amounts recognized in accumulated other comprehensive loss were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2018 2017 2018 2017 2018 2017 2018 2017 Net actuarial loss $ 12.8 $ 8.8 $ 1.1 $ 3.5 $ 3.4 $ 2.1 $ 0.5 $ 1.5 Prior service cost 0.1 0.1 — — — — — — Total $ 12.9 $ 8.9 $ 1.1 $ 3.5 $ 3.4 $ 2.1 $ 0.5 $ 1.5
Schedule of defined benefit plan, Other changes in plan assets recognized in regulatory assets [Table Text Block]	Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2016 2018 2017 2016 Current year actuarial (gain) loss $ 40.7 $ (24.8 ) $ 26.3 $ (26.4 ) $ 7.3 $ 9.2 Amortization of actuarial losses (9.7 ) (12.5 ) (11.2 ) (0.5 ) (0.7 ) (0.3 ) Amortization of prior service cost (0.4 ) (1.3 ) (3.0 ) — — (0.2 ) Total recognized in regulatory assets $ 30.6 $ (38.6 ) $ 12.1 $ (26.9 ) $ 6.6 $ 8.7
Schedule of Assumptions Used in Determining Net Periodic Benefit Cost [Table Text Block]	Pension Benefits Other Postretirement Benefits 2018 2017 2016 2018 2017 2016 Discount rate 3.71 % 4.22 % 4.68 % 3.74 % 4.30 % 4.78 % Expected return on plan assets 7.00 % 7.25 % 7.50 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % Health care cost trend rate n/a n/a n/a 7.00 % 6.60 % 7.00 % Ultimate health care cost trend rate n/a n/a n/a 5.00 % 5.00 % 5.00 % Year achieved n/a n/a n/a 2023 2021 2021
Schedule of amounts in regulatory assets to be recognized over the next fiscal year [Table Text Block]	The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2019 are as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Actuarial loss $ 14.7 — $ 12.9 — Prior service cost 0.3 — 0.3 — Total $ 15.0 — $ 13.2 —

COMMITMENTS AND CONTINGENCIES A

COMMITMENTS AND CONTINGENCIES ARO (Tables)	12 Months Ended
	Dec. 31, 2018
Change in Asset Retirement Obligations [Line Items]
Change in Asset Retirement Obligations [Table Text Block]	A reconciliation of the beginning and ending aggregate carrying amount of AROs is as follows: The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Beginning balance $ 568 $ 558 $ 529 $ 522 Liabilities incurred — — — — Liabilities settled (15 ) (10 ) (15 ) (9 ) Accretion expense 25 25 23 23 Revisions in estimated cash flows (1 ) (5 ) 4 (7 ) Ending balance $ 577 $ 568 $ 541 $ 529
SCE&G
Change in Asset Retirement Obligations [Line Items]
Change in Asset Retirement Obligations [Table Text Block]	A reconciliation of the beginning and ending aggregate carrying amount of AROs is as follows: The Company Consolidated SCE&G Millions of dollars 2018 2017 2018 2017 Beginning balance $ 568 $ 558 $ 529 $ 522 Liabilities incurred — — — — Liabilities settled (15 ) (10 ) (15 ) (9 ) Accretion expense 25 25 23 23 Revisions in estimated cash flows (1 ) (5 ) 4 (7 ) Ending balance $ 577 $ 568 $ 541 $ 529

COMMITMENTS AND CONTINGENCIES O

COMMITMENTS AND CONTINGENCIES Operating Leases Tables (Tables) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Leased Assets [Line Items]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	Rent Expense Future Minimum Rental Payments Millions of dollars 2016 2017 2018 2019 2020 2021 2022 2023 Thereafter The Company $ 10.2 $ 10 $ 9.7 $ 10 $ 8 $ 7 $ 6 $ 4 $ 30 Consolidated SCE&G 12.2 11.4 10.2 3 2 1 1 — 16
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 10,000,000
Operating Leases, Future Minimum Payments, Due in Two Years	8,000,000
Operating Leases, Future Minimum Payments, Due in Three Years	7,000,000
Operating Leases, Future Minimum Payments, Due in Four Years	6,000,000
Operating Leases, Future Minimum Payments, Due in Five Years	4,000,000
Operating Leases, Future Minimum Payments, Due Thereafter	$ 30,000,000
Long-term Purchase Commitment [Table Text Block]	Future Payments Millions of dollars 2019 2020 2021 2022 2023 Thereafter The Company and Consolidated SCE&G $ 40 $ 39 $ 39 $ 38 $ 38 $ 396
Contractual Obligation, Due in Next Fiscal Year	$ 23.7	$ 3.6
Contractual Obligation, Due in Second Year	39,000,000
Contractual Obligation, Due in Third Year	39,000,000
Contractual Obligation, Due in Fourth Year	38,000,000
Contractual Obligation, Due in Fifth Year	38,000,000
Contractual Obligation, Due after Fifth Year	$ 396,000,000
Operating Lease, Payments		10
SCE&G
Operating Leased Assets [Line Items]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	Rent Expense Future Minimum Rental Payments Millions of dollars 2016 2017 2018 2019 2020 2021 2022 2023 Thereafter The Company $ 10.2 $ 10 $ 9.7 $ 10 $ 8 $ 7 $ 6 $ 4 $ 30 Consolidated SCE&G 12.2 11.4 10.2 3 2 1 1 — 16
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 3,000,000
Operating Leases, Future Minimum Payments, Due in Two Years	2,000,000
Operating Leases, Future Minimum Payments, Due in Three Years	1,000,000
Operating Leases, Future Minimum Payments, Due in Four Years	1,000,000
Operating Leases, Future Minimum Payments, Due in Five Years	0
Operating Leases, Future Minimum Payments, Due Thereafter	$ 16,000,000
Long-term Purchase Commitment [Table Text Block]	Future Payments Millions of dollars 2019 2020 2021 2022 2023 Thereafter The Company and Consolidated SCE&G $ 40 $ 39 $ 39 $ 38 $ 38 $ 396
Operating Lease, Payments	$ 10	$ 11	$ 12

COMMITMENTS AND CONTINGENCIES N

COMMITMENTS AND CONTINGENCIES Nuclear (Tables)	12 Months Ended
	Dec. 31, 2018
Long-term Purchase Commitment [Table Text Block]	Future Payments Millions of dollars 2019 2020 2021 2022 2023 Thereafter The Company and Consolidated SCE&G $ 40 $ 39 $ 39 $ 38 $ 38 $ 396
SCE&G
Long-term Purchase Commitment [Table Text Block]	Future Payments Millions of dollars 2019 2020 2021 2022 2023 Thereafter The Company and Consolidated SCE&G $ 40 $ 39 $ 39 $ 38 $ 38 $ 396

SEGMENT OF BUSINESS INFORMATI_2

SEGMENT OF BUSINESS INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Disclosure of Reportable Segments The Company: Millions of dollars Electric Operations Gas Distribution Gas Marketing All Other Adjustments/ Eliminations Consolidated Total 2018 External Revenue $ 2,322 $ 934 $ 796 — — $ 4,052 Intersegment Revenue 5 1 139 $ 470 $ (615 ) — Operating Income (Loss) (894 ) 173 n/a — (8 ) (729 ) Interest Expense 18 37 1 — 328 384 Depreciation and Amortization 307 94 2 15 (15 ) 403 Income Tax Expense (Benefit) 9 26 15 (25 ) (437 ) (412 ) Net Income (Loss) n/a n/a 43 (90 ) (481 ) (528 ) Segment Assets 7,988 3,517 305 1,212 4,632 17,654 Expenditures for Assets 973 345 2 8 (438 ) 890 Deferred Tax Assets 4 17 2 — (23 ) — 2017 External Revenue $ 2,659 $ 874 $ 874 — — $ 4,407 Intersegment Revenue 5 2 127 $ 389 $ (523 ) — Operating Income (Loss) (154 ) 187 n/a — 52 85 Interest Expense 19 28 1 — 315 363 Depreciation and Amortization 295 85 2 16 (16 ) 382 Income Tax Expense (Benefit) 8 41 25 (7 ) (179 ) (112 ) Net Income (Loss) n/a n/a 27 (46 ) (100 ) (119 ) Segment Assets 11,979 3,259 230 1,042 2,229 18,739 Expenditures for Assets 216 417 2 7 583 1,225 Deferred Tax Assets 6 25 9 — (40 ) — 2016 External Revenue $ 2,614 $ 788 $ 825 — — $ 4,227 Intersegment Revenue 5 2 111 $ 414 $ (532 ) — Operating Income 969 149 n/a — 49 1,167 Interest Expense 17 25 1 — 299 342 Depreciation and Amortization 287 82 2 16 (16 ) 371 Income Tax Expense 8 32 19 — 212 271 Net Income (Loss) n/a n/a 30 (18 ) 583 595 Segment Assets 11,929 2,892 230 1,124 2,532 18,707 Expenditures for Assets 1,275 276 2 11 15 1,579 Deferred Tax Assets 9 32 11 — (52 ) —
SCE&G
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Consolidated SCE&G: Millions of dollars Electric Gas Adjustments/ Consolidated 2018 External Revenue $ 2,327 $ 435 — $ 2,762 Operating Income (Loss) (894 ) 63 — (831 ) Interest Expense 18 — $ 285 303 Depreciation and Amortization 307 32 (12 ) 327 Segment Assets 7,988 934 6,041 14,963 Expenditures for Assets 973 90 (430 ) 633 Deferred Tax Assets 4 n/a (4 ) — 2017 External Revenue $ 2,664 $ 406 — $ 3,070 Operating Income (Loss) (154 ) 71 — (83 ) Interest Expense 19 — $ 269 288 Depreciation and Amortization 295 30 (13 ) 312 Segment Assets 11,979 869 3,098 15,946 Expenditures for Assets 216 65 647 928 Deferred Tax Assets 6 n/a (6 ) — 2016 External Revenue $ 2,619 $ 367 — $ 2,986 Operating Income 969 56 — 1,025 Interest Expense 17 — $ 253 270 Depreciation and Amortization 287 28 (13 ) 302 Segment Assets 11,929 825 3,337 16,091 Expenditures for Assets 1,275 78 46 1,399 Deferred Tax Assets 9 n/a (9 ) —

UTILITY PLANT AND NONUTILITY _2

UTILITY PLANT AND NONUTILITY PROPERTY Utility and Nonutiltiy Property (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment [Table Text Block]	Millions of dollars The Company Consolidated SCE&G Gross Utility Plant: Generation $ 5,751 $ 5,751 Transmission 2,417 1,758 Distribution 6,032 4,456 Storage 99 74 General and other 631 535 Intangible 241 229 Construction work in progress 527 350 Nuclear Fuel 611 611 Total Gross Utility Plant $ 16,309 $ 13,764 Gross Nonutility Property $ 410 $ 73
Schedule of Jointly Owned Utility Plants [Table Text Block]	As of December 31, 2018 2017 Unit 1 Unit 1 Percent owned 66.7% 66.7% Plant in service $ 1.5 billion $ 1.5 billion Accumulated depreciation $ 643.9 million $ 637.6 million Construction work in progress $ 127.5 million $ 110.1 million
SCE&G
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment [Table Text Block]	Millions of dollars The Company Consolidated SCE&G Gross Utility Plant: Generation $ 5,751 $ 5,751 Transmission 2,417 1,758 Distribution 6,032 4,456 Storage 99 74 General and other 631 535 Intangible 241 229 Construction work in progress 527 350 Nuclear Fuel 611 611 Total Gross Utility Plant $ 16,309 $ 13,764 Gross Nonutility Property $ 410 $ 73
Schedule of Jointly Owned Utility Plants [Table Text Block]	As of December 31, 2018 2017 Unit 1 Unit 1 Percent owned 66.7% 66.7% Plant in service $ 1.5 billion $ 1.5 billion Accumulated depreciation $ 643.9 million $ 637.6 million Construction work in progress $ 127.5 million $ 110.1 million

AFFILIATED TRANSACTIONS (Tables

AFFILIATED TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2018
Related Party Transaction [Line Items]
Schedule of Related Party Transactions [Table Text Block]	Millions of Dollars 2018 2017 2016 Purchases from Canadys Refined Coal, LLC $ 149.9 $ 162.1 $ 161.8 Sales to Canadys Refined Coal, LLC 149.0 161.1 160.8 Millions of Dollars 2018 2017 Receivable from Canadys Refined Coal, LLC $ 6.8 $ 4.9 Payable to Canadys Refined Coal, LLC 6.8 4.9
SCE&G
Related Party Transaction [Line Items]
Schedule of Related Party Transactions [Table Text Block]	Millions of Dollars 2018 2017 2016 Purchases from Canadys Refined Coal, LLC $ 149.9 $ 162.1 $ 161.8 Sales to Canadys Refined Coal, LLC 149.0 161.1 160.8 Millions of Dollars 2018 2017 Receivable from Canadys Refined Coal, LLC $ 6.8 $ 4.9 Payable to Canadys Refined Coal, LLC 6.8 4.9 Millions of Dollars 2018 2017 2016 Purchases from SCANA Energy $ 139.0 $ 127.4 $ 111.5 Direct and Allocated Costs from SCANA Services 283.3 302.8 337.7 Millions of Dollars 2018 2017 Payable to SCANA Energy $ 14.1 $ 10.0 Payable to SCANA Services 37.7 42.0

OTHER INCOME (EXPENSE), NET (Ta

OTHER INCOME (EXPENSE), NET (Tables)	12 Months Ended
	Dec. 31, 2018
Schedule of Other Operating Cost and Expense, by Component [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 Revenues from contracts with customers $ 20 — — $ 5 — — Other income 180 $ 79 $ 64 141 $ 45 $ 29 Other expense (46 ) (55 ) (52 ) (28 ) (32 ) (36 ) Allowance for equity funds used during construction 19 23 29 11 15 26 Other income (expense), net $ 173 $ 47 $ 41 $ 129 $ 28 $ 19
SCE&G
Schedule of Other Operating Cost and Expense, by Component [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2018 2017 2016 2018 2017 2016 Revenues from contracts with customers $ 20 — — $ 5 — — Other income 180 $ 79 $ 64 141 $ 45 $ 29 Other expense (46 ) (55 ) (52 ) (28 ) (32 ) (36 ) Allowance for equity funds used during construction 19 23 29 11 15 26 Other income (expense), net $ 173 $ 47 $ 41 $ 129 $ 28 $ 19

QUARTERLY FINANCIAL INFORMATI_2

QUARTERLY FINANCIAL INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2018
Statement [Line Items]
Schedule of Quarterly Financial Information [Table Text Block]	The Company First Quarter Second Quarter Third Quarter Fourth Quarter Annual 2018 Total Operating Revenues $ 1,180 $ 843 $ 926 $ 1,103 $ 4,052 Operating Income (Loss) 189 103 183 (1,204 ) (729 ) Net Income (Loss) 169 8 67 (772 ) (528 ) Earnings (Loss) Per Share of Common Stock 1.18 0.06 0.47 (5.41 ) (3.70 ) 2017 Total Operating Revenues $ 1,173 $ 1,001 $ 1,076 $ 1,157 $ 4,407 Operating Income (Loss) 320 251 122 (608 ) 85 Net Income (Loss) 171 121 34 (445 ) (119 ) Earnings (Loss) Per Share of Common Stock 1.19 0.85 0.24 (3.11 ) (0.83 )
SCE&G
Statement [Line Items]
Schedule of Quarterly Financial Information [Table Text Block]	Consolidated SCE&G Millions of dollars First Quarter Second Quarter Third Quarter Fourth Quarter Annual 2018 Total Operating Revenues $ 702 $ 632 $ 739 $ 689 $ 2,762 Operating Income (Loss) 121 107 212 (1,271 ) (831 ) Total Comprehensive Income (Loss) 128 31 104 (852 ) (589 ) Comprehensive Income Available (Loss Attributable) to Common Shareholder 124 26 98 (861 ) (613 ) 2017 Total Operating Revenues $ 719 $ 756 $ 856 $ 739 $ 3,070 Operating Income (Loss) 226 247 124 (680 ) (83 ) Total Comprehensive Income (Loss) 112 126 42 (452 ) (172 ) Comprehensive Income Available (Loss Attributable) to Common Shareholder 109 123 39 (456 ) (185 )

Long Term Purchase Commitment (

Long Term Purchase Commitment (Tables)	12 Months Ended
	Dec. 31, 2018
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment [Table Text Block]	Future Payments Millions of dollars 2019 2020 2021 2022 2023 Thereafter The Company and Consolidated SCE&G $ 40 $ 39 $ 39 $ 38 $ 38 $ 396
SCE&G
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment [Table Text Block]	Future Payments Millions of dollars 2019 2020 2021 2022 2023 Thereafter The Company and Consolidated SCE&G $ 40 $ 39 $ 39 $ 38 $ 38 $ 396

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) shares in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2019USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)MWshares	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)shares
Significant Accounting Policies
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 30,000,000	$ 35,000,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents			$ 115,000,000
Utilities Operating Expense, Maintenance and Operations, Affiliate			18,400,000
Cost, Maintenance			16,300,000	$ 26,100,000
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA				18.00%
Reclassification Operations and Maintenance Expense				$ (9,000,000)	$ (14,000,000)
Long-term Debt, Current Maturities			59,000,000	727,000,000
Short-term borrowings			173,000,000	350,000,000
Regulated Operating Revenue, Gas			934,000,000	874,000,000	788,000,000
Decommissioning Liability, Noncurrent			625,800,000
Payments to Acquire Investments to be Held in Decommissioning Trust Fund			3,200,000
Unbilled Receivables, Current			217,500,000	220,900,000
Goodwill			210,000,000	210,000,000
Accumulated Amortization and Write-down, Goodwill			230,000,000
Nuclear refueling outage cost			28,600,000	23,200,000
Property, Plant and Equipment, Net			267,000,000	270,000,000
Reclassification Total Operating Expense				(9,000,000)	(14,000,000)
Reclassification Operating Income				9,000,000	14,000,000
Reclassification Other Income(Expense)				$ (9,000,000)	(14,000,000)
Change in Retail Electric Rates Approved Under BLRA			$ 2,768,000,000		$ 64,400,000
Public Utilities, Approved Return on Equity, Percentage		10.00%			10.50%
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent	8,000,000
Asset Management and Supply Service Agreements
Public Utilities, Allowance for Funds Used During Construction, Rate			0.00%	0.00%	0.00%
Earnings Per Share
Weighted Average Shares Outstanding - Basic | shares			143	143	143
SCE&G
Significant Accounting Policies
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	15,000,000	$ 20,000,000
Utilities Operating Expense, Maintenance and Operations, Affiliate			$ 182,000,000	$ 180,000,000	$ 199,000,000
Reclassification Operations and Maintenance Expense				(7,000,000)	(12,000,000)
Long-term Debt, Current Maturities			14,000,000	723,000,000
Short-term borrowings			73,000,000	252,000,000
Regulated Operating Revenue, Gas			434,000,000	405,000,000	366,000,000
Environmental Remediation Costs Recognized in Regulatory Assets			23,300,000
Unbilled Receivables, Current			129,300,000	140,300,000
Property, Plant and Equipment, Net			$ 72,000,000	71,000,000
Reclassification Total Operating Expense				(7,000,000)	(12,000,000)
Reclassification Operating Income				7,000,000	12,000,000
Reclassification Other Income(Expense)				$ (7,000,000)	$ (12,000,000)
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent	$ 1,000,000
Asset Management and Supply Service Agreements
Public Utilities, Allowance for Funds Used During Construction, Rate			0.00%	0.00%	0.00%
Genco [Member]
Significant Accounting Policies
Power Generation Capacity Megawatts | MW			605
Property, Plant and Equipment, Net			$ 500,000,000
PSNC Energy
Significant Accounting Policies
Natural gas inventory, carrying amount			$ 13,900,000	$ 11,500,000
PercentOfStorageFeesCreditedToRatePayers			75.00%
PSNC Energy
Significant Accounting Policies
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)			46.00%	39.00%
Summer Station Unit 2 and Unit 3 [Domain]
Significant Accounting Policies
Jointly Owned Utility Plant, Proportionate Ownership Share			55.00%
SCE&G
Significant Accounting Policies
Amount accrued annually for nuclear fuel outages			$ 17,200,000
Electric Generation Equipment [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.61%
Electric Generation Equipment [Member] | SCE&G
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.61%
Gas Transmission Equipment [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.47%
Gas Transmission Equipment [Member] | SCE&G
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.74%
Gas Distribution Equipment [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.48%
Gas Distribution Equipment [Member] | SCE&G
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.41%
Natural Gas, Storage [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.48%
Natural Gas, Storage [Member] | SCE&G
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.71%
Other Energy Equipment [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			5.64%
Other Energy Equipment [Member] | SCE&G
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			3.18%

RATE AND OTHER REGULATORY MAT_3

RATE AND OTHER REGULATORY MATTERS RATE AND OTHER REGULATORY MATTERS (Details) - USD ($)	3 Months Ended					12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
PSNC Energy Rate Case Application, Increase Amount									$ 0.18
Public Utilities, Approved Rate Increase (Decrease), Percentage							3.20%
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances							$ 2,000,000,000
Deferred Revenue, Refund Payments							2,039,000,000
Customer Refundable Fees, Alternative Plan over 20 yrs							1,032,000,000
Customer Refundable Fees, Alternative Plan							1,007,000,000
Refundable Gas Costs		$ 2,450,000					2,450,000
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Charitable Contributions, Amount							1,000,000
SCPSC Order, Recovery Of Projected DER Program Costs							29,300,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery						$ 35,400,000	$ 1,300,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent					35.00%		21.00%	35.00%
Refund to Customer Related to Tax Act							$ 73,700,000
Change in Retail Electric Rates Approved Under BLRA							2,768,000,000		$ 64,400,000
Public Utilities, Approved Return on Equity, Percentage						10.00%			10.50%
SCE&G
Demand Side Management Program Costs, Noncurrent		33,000,000		$ 37,000,000		$ 30,300,000	33,000,000	$ 37,000,000	$ 37,600,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances							31,000,000		61,000,000
SCPSC Order, Recovery Of Projected DER Program Costs								16,500,000	6,900,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery								61,000,000
Carrying costs on deferred income tax assets								18,800,000	$ 14,000,000
SCPSC Order, Approx Annual pension rider decrease amount								11,900,000
Refund to Customer Related to Tax Act						67,000,000	$ 100,000,000
PSNC Energy [Member]
Customer Credits, Alternative Plan over 3 yrs						$ 1,250,000
PSNC Energy Rate Case Application, Increase Amount								$ 19,100,000
Public Utilities, Approved Rate Increase (Decrease), Percentage								4.39%
Pipeline integrity mgmt annual revenue requirement approved by NCUC	$ 1,700,000	$ 1,100,000	$ 14,700,000	$ 700,000	$ 1,900,000
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period							106 years
Revenue Subject to Refund [Member] | SCE&G
Refund to Customer Related to Tax Act							$ 3,700,000
Revenue Subject to Refund [Member] | PSNC Energy [Member]
Refund to Customer Related to Tax Act							$ 15,400,000

RATE AND OTHER REGULATORY MAT_4

RATE AND OTHER REGULATORY MATTERS ELECTRIC-BLRA (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Entity Information [Line Items]
Utilities Operating Expense, Impairments	$ 1,376	$ 1,118
Accumulated Carrying Costs Written Off		$ 51
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA		18.00%
SCE&G
Entity Information [Line Items]
Utilities Operating Expense, Impairments	$ 1,376	$ 1,118

RATE AND OTHER REGULATORY MAT_5

RATE AND OTHER REGULATORY MATTERS GAS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Entity Information [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.20%
PSNC Energy Rate Case Application, Increase Amount			$ 0.18
SCE&G
Entity Information [Line Items]
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates	4.60%	2.20%	1.20%
Public Utilities changes in Retail Natural Gas Rates Approved under RSA	$ 19,700,000	$ 8,600,000	$ 4,100,000
PSNC Energy [Member]
Entity Information [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage		4.39%
Public Utilities, Authorized Allowable Return on Common Equity, Percentage		9.70%
PSNC Energy Rate Case Application, Increase Amount		$ 19,100,000

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Mar. 31, 2019	Dec. 31, 2017
Regulatory Assets, Noncurrent	$ 4,380		$ 5,580
Regulatory Liability, Noncurrent	2,789		3,059
Asset Retirement Obligation Costs [Member]
Regulatory Liability, Noncurrent	779		757
Deferred Income Tax Charge [Member]
Regulatory Liability, Noncurrent	814		1,076
Deferred gains on interest rate derivatives [Member]
Regulatory Liability, Noncurrent	77		131
Other Regulatory Liability [Member]
Regulatory Liability, Noncurrent	21		0
Unrecovered nuclear project costs post impairment [Member]
Regulatory Assets, Noncurrent	2,768
Demand Side Management programs [Member]
Regulatory Assets, Noncurrent	65		59
Pipeline integrity management costs [Member]
Regulatory Assets, Noncurrent	73		51
Storm Costs [Member]
Regulatory Assets, Noncurrent	35		24
Deferred transmission operating costs [Member] [Domain]
Regulatory Assets, Noncurrent	$ 15		0
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period	106 years
Regulatory Assets, Noncurrent	$ 406		434
Pension Costs [Member]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	1
Regulatory Assets, Noncurrent	302		305
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets, Noncurrent	448		456
Canadys Refined Coal [Member]
Regulatory Assets, Noncurrent	93		105
Environmental Restoration Costs [Member]
Regulatory Assets, Noncurrent	$ 27		30
Other Regulatory Assets [Member]
Regulatory Asset Recovery Assessments	2,047
Regulatory Assets, Noncurrent	$ 148		140
Summer Station Unit 2 and Unit 3 [Domain] | Settlement Proceeds [Member]
Regulatory Liability, Noncurrent	1,098		1,095
SCE&G
Regulatory Assets, Noncurrent	4,256		5,476
Regulatory Liability, Noncurrent	2,380		2,667
SCE&G | Settlement Proceeds [Member]
Regulatory Liability, Noncurrent	1,098		1,095
SCE&G | Asset Retirement Obligation Costs [Member]
Regulatory Liability, Noncurrent	541		527
SCE&G | Deferred Income Tax Charge [Member]
Regulatory Liability, Noncurrent	659		914
SCE&G | Deferred gains on interest rate derivatives [Member]
Regulatory Liability, Noncurrent	77		131
SCE&G | Other Regulatory Liability [Member]
Regulatory Liability, Noncurrent	5		0
SCE&G | Unrecovered nuclear project costs post impairment [Member]
Regulatory Assets, Noncurrent	2,768		3,976
SCE&G | Demand Side Management programs [Member]
Regulatory Assets, Noncurrent	65		59
SCE&G | Pipeline integrity management costs [Member]
Regulatory Assets, Noncurrent	9		8
Pipeline integrity management costs, annual amortization amount	3.2	$ 1.9
SCE&G | Storm Costs [Member]
Regulatory Assets, Noncurrent	35		24
SCE&G | Deferred transmission operating costs [Member] [Domain]
Regulatory Assets, Noncurrent	15		0
SCE&G | Asset Retirement Obligation Costs [Member]
Regulatory Assets, Noncurrent	380		410
SCE&G | Pension Costs [Member]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	2
Regulatory Assets, Noncurrent	272		273
SCE&G | Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets, Noncurrent	448		456
SCE&G | Canadys Refined Coal [Member]
Regulatory Assets, Noncurrent	93		105
SCE&G | Environmental Restoration Costs [Member]
Regulatory Assets, Noncurrent	24		25
SCE&G | Other Regulatory Assets [Member]
Regulatory Assets, Noncurrent			$ 140
PSNC Energy [Member]
Pipeline integrity management costs, amount recovering beginning November 2016	4.1
Pipeline integrity management costs, amount deferred pending future approval of rate recovery	$ 51.3

RATE AND OTHER REGULATORY MAT_6

RATE AND OTHER REGULATORY MATTERS NARRATIVE (Details)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period	106 years
PSNC Energy [Member]
MPG environmental remediation	3.8

REVENUE RECOGNITION (Details)

REVENUE RECOGNITION (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Contract with Customer, Liability	$ 9.4				$ 8.3				$ 9.4	$ 8.3
Total Operating Revenues Gas									931
Regulated Operating Revenue, Gas									934	874	$ 788
Electric Regulated Revenue									2,322	2,659	2,614
Residential [Member]
Gas -non regulated revenues									244
Total Operating Revenues Gas									533
Commercial [Member]
Gas -non regulated revenues									92
Total Operating Revenues Gas									242
Industrial [Member]
Gas -non regulated revenues									422
Total Operating Revenues Gas									107
Wholesale [Member]
Gas -non regulated revenues									38
Total Operating Revenues Gas									4
Gas Distribution
Regulated Operating Revenue, Other									4
Total Operating Revenues Gas									935
Gas Marketing segment [Member]
Regulated Operating Revenue, Other									0
Regulated Operating Revenue									796
Revenue from Contract with Customer, Excluding Assessed Tax									796
SCE&G
Contract with Customer, Liability	3.6				2.9				3.6	2.9
Regulated Operating Revenue	689	$ 739	$ 632	$ 702	739	$ 856	$ 756	$ 719	2,762	3,070	2,986
Capitalized Contract Cost, Amortization									(1.5)
Capitalized Contract Cost, Gross	0								0
Capitalized Contract Cost, Net	$ 14.8				$ 16.3				14.8	16.3
Regulated Operating Revenue, Gas									434	405	366
Electric Regulated Revenue									2,322	$ 2,659	$ 2,614
SCE&G | Residential [Member]
Regulated Operating Revenue, Gas									208
Electric Regulated Revenue									1,054
SCE&G | Commercial [Member]
Regulated Operating Revenue, Gas									117
Electric Regulated Revenue									744
SCE&G | Industrial [Member]
Regulated Operating Revenue, Gas									92
Electric Regulated Revenue									385
SCE&G | Transportation [Member] [Domain]
Gas -non regulated revenues									0
Total Operating Revenues Gas									45
Regulated Operating Revenue, Gas									13
Electric Regulated Revenue									0
SCE&G | Wholesale [Member]
Regulated Operating Revenue, Gas									4
Electric Regulated Revenue									132
SCE&G | Electric Operations
Regulated Operating Revenue, Other									12
Regulated Operating Revenue									2,327
Revenue from Contract with Customer, Excluding Assessed Tax									2,315
SCE&G | Gas Distribution
Regulated Operating Revenue, Other									1
Regulated Operating Revenue									435
Revenue from Contract with Customer, Excluding Assessed Tax									434
PSNC Energy [Member] | Residential [Member]
Regulated Operating Revenue, Gas									325
PSNC Energy [Member] | Commercial [Member]
Regulated Operating Revenue, Gas									125
PSNC Energy [Member] | Industrial [Member]
Regulated Operating Revenue, Gas									15
PSNC Energy [Member] | Transportation [Member] [Domain]
Regulated Operating Revenue, Gas									32
PSNC Energy [Member] | Wholesale [Member]
Regulated Operating Revenue, Gas									0
PSNC Energy [Member] | Gas Distribution
Regulated Operating Revenue, Other									3
Regulated Operating Revenue									500
Revenue from Contract with Customer, Excluding Assessed Tax									$ 497

COMMON EQUITY (Details)

COMMON EQUITY (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	200,000,000
SCE&G
Schedule of Capitalization, Equity [Line Items]
Retained Earnings, Appropriated	$ 115	$ 93.9
Common Stock, Shares Authorized	50,000,000
Preferred Stock, Shares Authorized	20,000,000
Preferred Stock, Shares Outstanding	1,000
Genco [Member]
Schedule of Capitalization, Equity [Line Items]
General Partners' Contributed Capital	$ 23
Fuel Company [Member]
Schedule of Capitalization, Equity [Line Items]
General Partners' Contributed Capital	1
SCANA [Member]
Schedule of Capitalization, Equity [Line Items]
General Partners' Contributed Capital	$ 675
PSNC Energy [Member]
Schedule of Capitalization, Equity [Line Items]
Dividend Payment Restrictions Schedule, Description	$30 million plus 85%
Dividends, Common Stock, Cash	$ 100

LONG-TERM AND SHORT-TERM DEBT_2

LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($) $ in Millions	6 Months Ended		9 Months Ended	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Contractual Obligation, Due in Next Fiscal Year				$ 40
Repayments of First Mortgage Bond			$ 250
interest rate first mortgage bonds redeemed			6.50%
interest rate on first mortgage bonds issued			4.25%
Medium-term Notes				800	$ 800
Senior Notes				70	75
Borrowings under credit agreement				100
First Mortgage Bonds				4,990	4,840
GENCO Notes				40	207
Industrial and Pollution Control Bonds				122	122
Senior Notes, Noncurrent				700	600
Other Long-term Debt				73	28
Long-term Debt, Gross				6,795	6,672
Long-term Debt, Current Maturities				(59)	(727)
Debt Instrument, Unamortized Discount				2	1
Unamortized Debt Issuance Expense				(39)	(38)
Long-term Debt				6,695	$ 5,906
Long-term Line of Credit				$ 40
Line of Credit Facility, Interest Rate at Period End				3.87%
Proceeds from Issuance of First Mortgage Bond				$ 300
Long-term Debt Current Maturities in Next Twelve Months				59
Long-term Debt, Maturities, Repayments of Principal in Year Two				368
Long-term Debt, Maturities, Repayments of Principal in Year Three				797
Long-term Debt, Maturities, Repayments of Principal in Year Four				266
Long-term Debt, Maturities, Repayments of Principal in Year Five				14
Aggregate Purchase Price Bonds				$ 1,000
Medium-term Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				5.42%	5.42%
Debt Instrument, Redemption Period, Start Date					Apr. 1, 2020
Debt Instrument, Redemption Period, End Date					Feb. 1, 2022
First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				5.52%	5.80%
Debt Instrument, Redemption Period, Start Date					Nov. 1, 2021
Debt Instrument, Redemption Period, End Date					Jun. 1, 2065
Genco Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				5.49%	5.94%
Debt Instrument, Redemption Period, Start Date					Feb. 1, 2019
Debt Instrument, Redemption Period, End Date					Feb. 1, 2024
Industrial and Pollution Control Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				3.52%	3.52%
Debt Instrument, Redemption Period, Start Date					Feb. 1, 2028
Debt Instrument, Redemption Period, End Date					Dec. 1, 2038
Long-term Debt, Percentage Bearing Variable Interest, Amount				$ 67.8
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate				1.72%	1.85%
Senior Debentures [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				5.07%	5.19%
Debt Instrument, Redemption Period, Start Date					Mar. 30, 2020
Debt Instrument, Redemption Period, End Date					Dec. 15, 2047
Other Debt [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				3.46%	2.83%
Debt Instrument, Redemption Period, Start Date					Jan. 1, 2019
Debt Instrument, Redemption Period, End Date					Sep. 30, 2027
Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				3.44%	2.18%
Debt Instrument, Redemption Period, Start Date					Jun. 1, 2019
Debt Instrument, Redemption Period, End Date					Jun. 1, 2034
Long-term Debt, Percentage Bearing Fixed Interest, Percentage Rate				6.17%
SCE&G
Debt Instrument [Line Items]
Repayments of First Mortgage Bond			$ 300
interest rate first mortgage bonds redeemed			5.25%
Medium-term Notes				$ 300
First Mortgage Bonds				4,990	$ 4,840
GENCO Notes			$ 160	40	207
Industrial and Pollution Control Bonds				122	122
Other Long-term Debt				30	28
Long-term Debt, Gross				5,182	5,197
Long-term Debt, Current Maturities				(14)	(723)
Debt Instrument, Unamortized Discount (Premium), Net				(1)	1
Unamortized Debt Issuance Expense				(35)	(34)
Long-term Debt				5,132	4,441
Debt, Weighted Average Interest Rate			6.06%
Proceeds from Issuance of First Mortgage Bond			$ 400
Long-term Debt, Maturities, Repayments of Principal in Year Two					$ 13
Long-term Debt, Maturities, Repayments of Principal in Year Three				342
Long-term Debt, Maturities, Repayments of Principal in Year Four				11
Long-term Debt, Maturities, Repayments of Principal in Year Five				$ 9
SCE&G | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				5.52%	5.80%
Debt Instrument, Redemption Period, End Date					Jun. 1, 2065
SCE&G | Genco Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				5.49%	5.94%
Debt Instrument, Redemption Period, End Date					Feb. 1, 2024
SCE&G | Industrial and Pollution Control Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				3.52%	3.52%
Debt Instrument, Redemption Period, End Date					Dec. 1, 2038
Long-term Debt, Percentage Bearing Variable Interest, Amount				$ 67.8
SCE&G | Other Debt [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				2.97%	2.83%
Debt Instrument, Redemption Period, Start Date					Jan. 31, 2019
Debt Instrument, Redemption Period, End Date					Sep. 30, 2027
SCEG including Fuel Company [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				3.82%	1.92%
Long-term Debt Current Maturities in Next Twelve Months				$ 14
PSNC Energy [Member]
Debt Instrument [Line Items]
Senior Notes	$ 100	$ 150
Debt Instrument, Interest Rate, Increase (Decrease)	4.33%	4.18%
Debt, Weighted Average Interest Rate				3.49%	1.93%
First Mortgage Bond rate [Domain]
Debt Instrument [Line Items]
interest rate on first mortgage bonds issued				3.50%

LONG-TERM AND SHORT-TERM DEBT_3

LONG-TERM AND SHORT-TERM DEBT (Details 2)	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Sep. 30, 2018
Debt Instrument, Redemption [Line Items]
Medium-term Notes	$ 800,000,000	$ 800,000,000
Interest Income, Related Party	4,000,000
Related Party Transaction, Due from (to) Related Party, Current	$ 282,000,000	28,000,000
Bond Ratio	4.01
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,800,000,000	2,000,000,000
Long-term Line of Credit	$ 40,000,000
Line of Credit Facility, Interest Rate at Period End	3.87%
Commercial Paper	$ 172,900,000	350,300,000
commercial paper available to be borrowed		600,000,000
Letters of Credit Outstanding, Amount	37,600,000	3,300,000
Line of Credit Facility, Remaining Borrowing Capacity	1,549,500,000	1,646,400,000
Genco [Member]
Debt Instrument, Redemption [Line Items]
Commercial Paper		200,000,000
SCEG including Fuel Company [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,200,000,000	1,400,000,000
Commercial Paper	$ 73,200,000	$ 251,600,000
Debt, Weighted Average Interest Rate	3.82%	1.92%
Letters of Credit Outstanding, Amount	$ 300,000	$ 300,000
Line of Credit Facility, Remaining Borrowing Capacity	1,126,500,000	1,148,100,000
Commercial paper borrowing limit		1,600,000,000
SCANA [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	400,000,000	400,000,000
Commercial Paper	$ 2,000,000	0
Debt, Weighted Average Interest Rate	3.65%
Letters of Credit Outstanding, Amount	$ 37,300,000	3,000,000
Line of Credit Facility, Remaining Borrowing Capacity	320,700,000	397,000,000
Fuel Company [Member]
Debt Instrument, Redemption [Line Items]
Long-Term Line of Credit - SC Fuel Co only	500,000,000	500,000,000
SCE&G
Debt Instrument, Redemption [Line Items]
Medium-term Notes	300,000,000
Related Party Transaction, Due from (to) Related Party, Current	353,000,000	37,000,000
Line of Credit Facility, Maximum Borrowing Capacity	700,000,000	700,000,000
Debt, Weighted Average Interest Rate			6.06%
Long-term Line of Credit - SCE&G only		200,000,000
First Mortgage Bonds	1,200,000,000
PSNC Energy [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200,000,000	200,000,000
Commercial Paper	$ 97,700,000	$ 98,700,000
Debt, Weighted Average Interest Rate	3.49%	1.93%
Line of Credit Facility, Remaining Borrowing Capacity	$ 102,300,000	$ 101,300,000
Industrial and Pollution Control Bonds [Member]
Debt Instrument, Redemption [Line Items]
Debt, Weighted Average Interest Rate	3.52%	3.52%
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	1.72%	1.85%
Industrial and Pollution Control Bonds [Member] | SCE&G
Debt Instrument, Redemption [Line Items]
Debt, Weighted Average Interest Rate	3.52%	3.52%
Wells Fargo, National Association, Bank of America & Morgan Stanley [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity		$ 0.095
JP Morgan Chase, Mizuho Corp, TD Bank, Credit Suisse AG ,Cayman Islands Branch and UBS Loan Finance [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity		7.9
royal bank of canada [Domain]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity		0.055
3 Year Credit [Domain]
Debt Instrument, Redemption [Line Items]
Long-term Line of Credit - SCE&G only		200,000,000
five year credit [Domain]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,300,000,000	$ 1,300,000,000

LONG-TERM AND SHORT-TERM DEBT_4

LONG-TERM AND SHORT-TERM DEBT (NARRATIVE) (Details)	12 Months Ended
	Dec. 31, 2018
Debt Instrument [Line Items]
months preceding issuance of bonds	18
Unfunded property additions	70.00%
Consecutive months for bond ratio	12

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($)	3 Months Ended			12 Months Ended
	Dec. 31, 2018	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Investments, Owned, Federal Income Tax Note [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	$ 539,000,000			$ 539,000,000	$ 600,000,000
Deferred Tax Asset, Legal Settlement net of tax	274,000,000			274,000,000	273,000,000
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards	106,000,000			106,000,000	$ 98,000,000	$ 350,000,000	$ 49,000,000
Decrease in Unrecognized Tax Benefits is Reasonably Possible	11,000,000			11,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	106,000,000			$ 106,000,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent			35.00%	21.00%	35.00%
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)				$ (8,000,000)	$ (414,000,000)	36,000,000
Current State and Local Tax Expense (Benefit)				5,000,000	18,000,000	13,000,000
Current Income Tax Expense (Benefit)				(3,000,000)	(396,000,000)	49,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred State and Local Income Tax Expense (Benefit)				(55,000,000)	(37,000,000)	21,000,000
Income Tax Reconciliation, Tax Credits, Investment [Abstract]
Income Tax Expense (Benefit)				(412,000,000)	(112,000,000)	271,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic				(940,000,000)	(231,000,000)	866,000,000
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount				(197,000,000)	(81,000,000)	303,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount				(37,000,000)	(7,000,000)	27,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits				(3,000,000)	(5,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction				(4,000,000)	(8,000,000)	(10,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Dividends, Amount				(2,000,000)	(9,000,000)	(10,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits				(2,000,000)	(2,000,000)	(2,000,000)
Section 45 tax credit				(9,000,000)	(8,000,000)	(8,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent				0	(18,000,000)	(23,000,000)
Income Tax Reconcilation, Tax Reform Remeasurement				188,000,000	(30,000,000)
Income Tax Reconciliation, Sale of Subsidiaries				5,000,000	0	0
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount				2,000,000	(4,000,000)	(1,000,000)
Deferred tax Nuclear Decommissioning	143,000,000			143,000,000	141,000,000
Deferred Tax Asset, Remeasurement	0			0	54,000,000
Deferred Tax Assets, Financial Instruments	10,000,000			10,000,000	15,000,000
Deferred Tax Asset, Unamortized Investment, Tax Credits	7,000,000			7,000,000	8,000,000
Deferred Tax Assets, Other	4,000,000			4,000,000	6,000,000
Deferred Tax Assets, Net	1,061,000,000			1,061,000,000	1,185,000,000
Deferred Tax Liabilities, Property, Plant and Equipment	1,227,000,000			1,227,000,000	1,220,000,000
Deferred Tax Liability, Impairment	668,000,000			668,000,000	962,000,000
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	60,000,000			60,000,000	60,000,000
Deferred Tax Liabilities, Asset Retirement Obligation	94,000,000			94,000,000	91,000,000
Deferred tax asset unrecovered plant	24,000,000			24,000,000	27,000,000
Deferred Tax Liability, Demand Side Management	16,000,000			16,000,000	16,000,000
deferred tax liability, prepayments	21,000,000			21,000,000	21,000,000
Deferred Tax Liabilities, Other	63,000,000			63,000,000	49,000,000
Deferred Tax Liabilities, Net	2,173,000,000			2,173,000,000	2,446,000,000
Deferred Tax Liabilities, Net, Noncurrent	1,112,000,000			1,112,000,000	1,261,000,000
Unrecognized tax benefits	38,000,000			38,000,000	19,000,000
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions				8,000,000	0	94,000,000
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions				0	(273,000,000)	0
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions				0	21,000,000	207,000,000
Utilities Operating Loss, Impairment, Net of Taxes	870,000,000	$ 3,000,000		53,000,000	690,000,000
SCE&G
Investments, Owned, Federal Income Tax Note [Line Items]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest				(614,000,000)
Deferred Tax Assets, Operating Loss Carryforwards	493,000,000			493,000,000	541,000,000
Deferred Tax Asset, Legal Settlement net of tax	274,000,000			274,000,000	273,000,000
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards	106,000,000			106,000,000	98,000,000	350,000,000	$ 49,000,000
Unrecognized Tax Benefits, Income Tax Penalties Expense				0
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)				(16,000,000)	(410,000,000)	50,000,000
Current State and Local Tax Expense (Benefit)				0	(18,000,000)	13,000,000
Current Income Tax Expense (Benefit)				(16,000,000)	(428,000,000)	63,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred State and Local Income Tax Expense (Benefit)				52,000,000	(2,000,000)	20,000,000
Income Tax Reconciliation, Tax Credits, Investment [Abstract]
Income Tax Expense (Benefit)				(416,000,000)	(171,000,000)	248,000,000
Net Income (Loss) Attributable to Noncontrolling Interest				25,000,000	13,000,000	13,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic				(1,005,000,000)	(343,000,000)	774,000,000
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount				(211,000,000)	(120,000,000)	271,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount				(38,000,000)	(8,000,000)	26,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits				(3,000,000)	(5,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction				(2,000,000)	(5,000,000)	(9,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits				(2,000,000)	(2,000,000)	(2,000,000)
Section 45 tax credit				(9,000,000)	(8,000,000)	(8,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent				0	(18,000,000)	(23,000,000)
Income Tax Reconcilation, Tax Reform Remeasurement				176,000,000	1,000,000
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount				2,000,000	(4,000,000)	(2,000,000)
Deferred tax Nuclear Decommissioning	135,000,000			135,000,000	132,000,000
Deferred Tax Asset, Remeasurement	0			0	54,000,000
Deferred Tax Asset, Unamortized Investment, Tax Credits	7,000,000			7,000,000	8,000,000
Deferred Tax Assets, Other	5,000,000			5,000,000	5,000,000
Deferred Tax Assets, Net	954,000,000			954,000,000	1,055,000,000
Deferred Tax Liabilities, Property, Plant and Equipment	1,033,000,000			1,033,000,000	1,035,000,000
Deferred Tax Liability, Impairment	668,000,000			668,000,000	962,000,000
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	53,000,000			53,000,000	53,000,000
Deferred Tax Liabilities, Asset Retirement Obligation	88,000,000			88,000,000	85,000,000
Deferred tax asset unrecovered plant	24,000,000			24,000,000	27,000,000
Deferred Tax Liability, Demand Side Management	16,000,000			16,000,000	16,000,000
deferred tax liability, prepayments	20,000,000			20,000,000	19,000,000
Deferred Tax Liabilities, Other	41,000,000			41,000,000	31,000,000
Deferred Tax Liabilities, Net	1,943,000,000			1,943,000,000	2,228,000,000
Deferred Tax Liabilities, Net, Noncurrent	989,000,000			989,000,000	1,173,000,000
Unrecognized tax benefits	$ 38,000,000			38,000,000	19,000,000
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions				8,000,000	0	94,000,000
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions				0	(273,000,000)	0
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions				0	$ 21,000,000	$ 207,000,000
Utilities Operating Loss, Impairment, Net of Taxes				$ 46,000,000

INCOME TAXES INCOME TAXES (Deta

INCOME TAXES INCOME TAXES (Details 2) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
income tax [Line Items]
Deferred Tax Liability, Impairment	$ 668,000,000				$ 962,000,000				$ 668,000,000	$ 962,000,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent								35.00%	21.00%	35.00%
Income Available to Common Shareholders	(772,000,000)	$ 67,000,000	$ 8,000,000	$ 169,000,000	(445,000,000)	$ 34,000,000	$ 121,000,000	$ 171,000,000	$ (528,000,000)	$ (119,000,000)	$ 595,000,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate									(197,000,000)	(81,000,000)	303,000,000
Income Tax Expense (Benefit) Continuing Operations, Income Tax Reconciliation, Changes [Abstract]
Income Tax Reconciliation, State and Local Income Taxes									(37,000,000)	(7,000,000)	27,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits									(3,000,000)	(5,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction									(4,000,000)	(8,000,000)	(10,000,000)
Income Tax Reconciliation, Deductions, Dividends									2,000,000	9,000,000	10,000,000
Amortization of Amounts Deferred under Federal Investment Tax Credits									2,000,000	2,000,000	2,000,000
Section 45 tax credit									9,000,000	8,000,000	8,000,000
Income Tax Reconciliation, Other Adjustments									2,000,000	(4,000,000)	(1,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent									0	(18,000,000)	(23,000,000)
Income Tax Expense (Benefit)									(412,000,000)	(112,000,000)	271,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic									(940,000,000)	(231,000,000)	866,000,000
Income Tax Reconciliation, Sale of Subsidiaries									5,000,000	0	0
SCE&G
income tax [Line Items]
Deferred Tax Liability, Impairment	668,000,000				962,000,000				668,000,000	962,000,000
Net Income (Loss) Attributable to Parent	$ (861,000,000)	$ 98,000,000	$ 26,000,000	$ 124,000,000	$ (456,000,000)	$ 39,000,000	$ 123,000,000	$ 109,000,000	(613,000,000)	(185,000,000)	513,000,000
Net Income (Loss) Attributable to Noncontrolling Interest									25,000,000	13,000,000	13,000,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate									(211,000,000)	(120,000,000)	271,000,000
Income Tax Expense (Benefit) Continuing Operations, Income Tax Reconciliation, Changes [Abstract]
Income Tax Reconciliation, State and Local Income Taxes									(38,000,000)	(8,000,000)	26,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits									(3,000,000)	(5,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction									(2,000,000)	(5,000,000)	(9,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits									2,000,000	2,000,000	2,000,000
Section 45 tax credit									9,000,000	8,000,000	8,000,000
Income Tax Reconciliation, Other Adjustments									2,000,000	(4,000,000)	(2,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent									0	(18,000,000)	(23,000,000)
Income Tax Expense (Benefit)									(416,000,000)	(171,000,000)	248,000,000
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest									(1,005,000,000)	(343,000,000)	774,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic									$ (1,005,000,000)	$ (343,000,000)	$ 774,000,000

INCOME TAXES INCOME TAXES (De_2

INCOME TAXES INCOME TAXES (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Investments, Owned, Federal Income Tax Note [Line Items]
Deferred Income Tax Expense (Benefit)	$ (407)	$ 286	$ 224
Deferred Federal Income Tax Expense (Benefit)	(352)	323	203
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	84	88
Deferred tax Nuclear Decommissioning	143	141
Deferred Tax Assets, Financial Instruments	10	15
Deferred Tax Asset, Unamortized Investment, Tax Credits	7	8
Deferred Tax Assets, Other	4	6
Deferred Tax Assets, Net	1,061	1,185
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	1,227	1,220
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	60	60
Deferred Tax Liabilities, Asset Retirement Obligation	94	91
Deferred tax asset unrecovered plant	24	27
Deferred Tax Liability, Demand Side Management	16	16
deferred tax liability, prepayments	21	21
Deferred Tax Liabilities, Other	63	49
Deferred Tax Liabilities, Gross	2,173	2,446
Deferred Tax Liabilities, Net, Noncurrent	1,112	1,261
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	8	0	94
Gross decreases tax positions in prior period	0	(273)	0
Gross increases current period tax positions	0	21	207
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards	106	98	350	$ 49
SCE&G
Investments, Owned, Federal Income Tax Note [Line Items]
Deferred Income Tax Expense (Benefit)	398	259	187
Deferred Federal Income Tax Expense (Benefit)	(346)	261	167
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	40	42
Deferred tax Nuclear Decommissioning	135	132
Deferred Tax Asset, Unamortized Investment, Tax Credits	7	8
Deferred Tax Assets, Other	5	5
Deferred Tax Assets, Net	954	1,055
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	1,033	1,035
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	53	53
Deferred Tax Liabilities, Asset Retirement Obligation	88	85
Deferred tax asset unrecovered plant	24	27
Deferred Tax Liability, Demand Side Management	16	16
deferred tax liability, prepayments	20	19
Deferred Tax Liabilities, Other	41	31
Deferred Tax Liabilities, Gross	1,943	2,228
Deferred Tax Liabilities, Net, Noncurrent	989	1,173
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	8	0	94
Gross decreases tax positions in prior period	0	(273)	0
Gross increases current period tax positions	0	21	207
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards	$ 106	$ 98	$ 350	$ 49

INCOME TAXES INCOME TAXES CARRY

INCOME TAXES INCOME TAXES CARRYFORWARD (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended						24 Months Ended
	Mar. 31, 2017	Dec. 31, 2037	Dec. 31, 2035	Dec. 31, 2032	Dec. 31, 2026	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2037
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%					21.00%	35.00%
Deferred Tax Assets, State Taxes						$ 30
Operating Loss Carryforwards						1,807
Renewable Energy Tax Credit						83
State Operating Loss Carryforward						2,447
Tax Credit Carryforward, Amount						4,367
Tax Carryforward [Member]
Tax Credit Carryforward, Ending Expiration Date		Dec. 31, 2037
Renewable Energy Tax Credit [Member]
Tax Credit Carryforward Expiration Date, Beginning			2,035
Tax Credit Carryforward, Ending Expiration Date								Dec. 31, 2038
State NOL Carryforwards [Member]
Tax Credit Carryforward, Ending Expiration Date		Dec. 31, 2037
State and Local Jurisdiction [Member]
Tax Credit Carryforward, Ending Expiration Date				Dec. 31, 2033	Dec. 31, 2026
SCE&G
Deferred Tax Assets, State Taxes						30
Operating Loss Carryforwards						1,642
Renewable Energy Tax Credit						83
State Operating Loss Carryforward						2,198
Tax Credit Carryforward, Amount						$ 3,953

DERIVATIVE FINANCIAL INSTRUME_3

DERIVATIVE FINANCIAL INSTRUMENTS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)MMBTU		Dec. 31, 2017USD ($)MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	66	[1]	62
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6		6
Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	60	[1]	55
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	47	[1]	42
Energy Related Derivative [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	47		42
Commodity Contract [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	19		20
Commodity Contract [Member] | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6		6
Commodity Contract [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	13		13
Basis Swap [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	5		3
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 106.8		$ 111.2
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	35		735
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	36.4		36.4
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 35		$ 735
[1]	(a) Includes amounts related to basis swap contracts totaling 5.1 bcf in 2018 and 2.6 bcf in 2017.

DERIVATIVE FINANCIAL INSTRUME_4

DERIVATIVE FINANCIAL INSTRUMENTS FAIR VALUE ON BALANCE SHEET (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 38	$ 38
Derivative Liability	38	37
Derivative Asset	14	59
Derivative Asset, Fair Value, Gross Asset	14	59
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	1	1
Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	22	28
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability		2
Derivative Asset	1	58
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	3	7
Prepayments [Member]
Derivative [Line Items]
Derivative Liability	13
Derivative Asset	12
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	24	32
Derivative Liability	24	32
Derivative Asset	0	54
Derivative Asset, Fair Value, Gross Asset	0	54
Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1	3
Derivative Liability	1	3
Derivative Asset	1	1
Derivative Asset, Fair Value, Gross Asset	1	1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	13	3
Derivative Liability	2	2
Derivative Asset	2	4
Derivative Asset, Fair Value, Gross Asset	13	4
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	22	30
Derivative Asset, Fair Value, Gross Asset	0	0
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	2	3
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	19	24
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		1
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1	2
Derivative Asset, Fair Value, Gross Asset		0
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	16	8
Derivative Asset, Fair Value, Gross Asset	14	59
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		1
Derivative Asset, Fair Value, Gross Asset		54
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	3	4
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		1
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		2
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1	1
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Derivative Asset, Fair Value, Gross Asset	1	3
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	12	1
Derivative Asset, Fair Value, Gross Asset	11	0
SCE&G
Derivative [Line Items]
Derivative Liability	11	15
Derivative Asset	0	54
SCE&G | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	0	0
SCE&G | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	10	13
SCE&G | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset		54
SCE&G | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	1	2
SCE&G | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	11	15
Derivative Liability	11	15
Derivative Asset	0	54
Derivative Asset, Fair Value, Gross Asset	0	54
SCE&G | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	8	10
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1	1
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	7	9
SCE&G | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	3	5
Derivative Asset, Fair Value, Gross Asset	0	54
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		1
Derivative Asset, Fair Value, Gross Asset		54
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 3	$ 4

DERIVATIVE FINANCIAL INSTRUME_5

DERIVATIVE FINANCIAL INSTRUMENTS ON INCOME STATEMENT (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ (2)	$ (7)	$ 4
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	(16)	(6)	$ (13)
Utilities Operating Expense, Impairments	$ 1,376	$ 1,118
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 9	$ 7	$ 7
Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	(8.7)
Commodity Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	7	(1)	6
Commodity Contract [Member] | Gas Purchased for Resale [Member] [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	(0.6)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	64	(32)	(34)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Nonoperating Income (Expense) [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	0	(173)	$ (2)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(2)	(3)
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	2.8
SCE&G
Derivative [Line Items]
Utilities Operating Expense, Impairments	$ 1,376	$ 1,118
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ 64	$ (32)	$ (34)
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Nonoperating Income (Expense) [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income			(2)
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(2)	(3)
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Operating Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	115	(173)
Cash Flow Hedging [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	1	0	(1)
Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	1	(2)	0
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(1)	(2)	(2)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(9)	(7)	(7)
Cash Flow Hedging [Member] | Commodity Contract [Member]
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	(3)	(7)	5
Cash Flow Hedging [Member] | Commodity Contract [Member] | Gas Purchased for Resale [Member] [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(7)	1	(6)
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	0.9
Cash Flow Hedging [Member] | SCE&G | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	1	(2)	0
Cash Flow Hedging [Member] | SCE&G | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(1)	$ (2)	$ (2)
Cash Flow Hedging [Member] | SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	0.9
Cash Flow Hedging [Member] | SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	$ 2.8

DERIVATIVE FINANCIAL INSTRUME_6

DERIVATIVE FINANCIAL INSTRUMENTS (CREDIT RISK) (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Gain (Loss) on Derivatives
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	$ 24.3	$ 28.9
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	0.5	4.8
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	24.8	33.7
Cash collateral requested from counterparty	0	53.5
Derivative, net asset position	0	53.5
Letter of Credit Available Commodity Derivatives,asset position		1.2
Commodity Derivative, net asset position	$ 1.7	$ 4
SCE&G
Gain (Loss) on Derivatives
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	$ 11	$ 10.1
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	0.2	4.6
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	11.2	14.7
Cash collateral requested from counterparty	0	53.5
Derivative, net asset position	0	53.5
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	64	(32)	$ (34)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	64	(32)	(34)
Interest Rate Contract [Member] | Interest Expense [Member] | Not Designated as Hedging Instrument [Member]
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(2)	(3)
Interest Rate Contract [Member] | Interest Expense [Member] | Not Designated as Hedging Instrument [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(2)	(3)
Interest Rate Contract [Member] | Operating Expense [Member] | Not Designated as Hedging Instrument [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	115	(173)
Interest Rate Contract [Member] | Other Nonoperating Income (Expense) [Member] | Not Designated as Hedging Instrument [Member]
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	0	(173)	(2)
Interest Rate Contract [Member] | Other Nonoperating Income (Expense) [Member] | Not Designated as Hedging Instrument [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income			(2)
Interest Rate Contract [Member] | Cash Flow Hedging [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	1	(2)	0
Interest Rate Contract [Member] | Cash Flow Hedging [Member] | Interest Expense [Member]
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ 1	$ (2)	$ 0

DERIVATIVE FINANCIAL INSTRUME_7

DERIVATIVE FINANCIAL INSTRUMENTS OFFSETTING ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 3
Derivative Liability	38	$ 37
Derivative, Fair Value, Net	27
Derivative Asset, Fair Value, Gross Liability	(11)	0
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	0
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Liability, Fair Value, Gross Asset	(11)	(1)
Derivative Liabilities, Net Amount	3	8
Derivative Liability, Fair Value, Gross Liability	38	38
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	0
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	24	(29)
Derivative Assets, Net Amount	3	59
Derivative Asset	14	59
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	1	1
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability		2
Derivative Asset	1	58
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	3	7
Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	22	28
Prepayments [Member]
Derivative [Line Items]
Derivative Liability	13
Derivative Asset	12
SCE&G
Derivative [Line Items]
Derivative Liability	11	15
Derivative Asset	0	54
SCE&G | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	0	0
SCE&G | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset		54
SCE&G | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	1	2
SCE&G | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	10	13
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability	24	32
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	0
Derivative Liabilities, Net Amount	0	4
Derivative Liability, Fair Value, Gross Liability	24	32
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments		0
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	24	(28)
Derivative Assets, Net Amount	0	54
Derivative Asset	0	54
Interest Rate Contract [Member] | SCE&G
Derivative [Line Items]
Derivative Liability	11	15
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	0
Derivative Liabilities, Net Amount	0	15
Derivative Liability, Fair Value, Gross Liability	11	15
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	0
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted		0
Derivative Assets, Net Amount	0	54
Derivative Asset	0	54
Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability	1	3
Derivative Liabilities, Net Amount	1	3
Derivative Liability, Fair Value, Gross Liability	1	3
Derivative Assets, Net Amount	1	1
Derivative Asset	1	1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability	2	2
Derivative Asset, Fair Value, Gross Liability	(11)	0
Derivative Liability, Fair Value, Gross Asset	(11)	(1)
Derivative Liabilities, Net Amount	2	1
Derivative Liability, Fair Value, Gross Liability	13	3
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	0	(1)
Derivative Assets, Net Amount	2	4
Derivative Asset	2	$ 4
Other Energy Management Contract [Member] | SCE&G
Derivative [Line Items]
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	$ (11)

FAIR VALUE MEASUREMENTS, INCL_3

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 14	$ 59
Derivative Liability	$ 38	$ 37
Liabilities, Fair Value Disclosure [Abstract]
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Level 3 Fair Value Measurements	no	no
Available-for-sale Securities [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	$ 0	$ 119
Held-to-maturity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	6	6
Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	54
Derivative Liability	24	32
Interest Rate Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	54
Financial and Nonfinancial Liabilities, Fair Value Disclosure	24	32
Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	1	1
Derivative Liability	1	3
Commodity Contract [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	1	1
Financial and Nonfinancial Liabilities, Fair Value Disclosure	1	2
Commodity Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	0
Financial and Nonfinancial Liabilities, Fair Value Disclosure	0	1
Other Energy Management Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	2	4
Derivative Liability	2	2
Other Energy Management Contract [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	11	0
Financial and Nonfinancial Liabilities, Fair Value Disclosure	12	1
Other Energy Management Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	2	4
Financial and Nonfinancial Liabilities, Fair Value Disclosure	3	4
SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	54
Derivative Liability	$ 11	$ 15
Liabilities, Fair Value Disclosure [Abstract]
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Level 3 Fair Value Measurements	no	no
SCE&G | Available-for-sale Securities [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	$ 0	$ 100
SCE&G | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	54
Derivative Liability	11	15
SCE&G | Interest Rate Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	54
Financial and Nonfinancial Liabilities, Fair Value Disclosure	$ 11	$ 15

FAIR VALUE MEASUREMENTS, INCL_4

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other Long-term Debt, Noncurrent	$ 6,753.9	$ 6,632.9
Long-term debt, Fair Value	7,180.8	7,399.7
SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other Long-term Debt, Noncurrent	5,145.6	5,163.3
Long-term debt, Fair Value	$ 5,469.7	$ 5,790.3

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		$ 71.7
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year, Description		no
Defined Benefit Plan, Accumulated Benefit Obligation		$ 842.4	$ 905.8
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation		$ 0.7	1.6
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation		0.6	1.4
Defined Benefit Plan, Plan Assets, Amount		727.3	849.6	$ 793.6
Defined Benefit Plan, Plan Assets, Increase (Decrease) for Actual Return (Loss)		(50.6)	128.4
Defined Benefit Plan, Shared Costs Deferred		$ 24.9	$ 21.4
Defined Benefit Plan Health Care Cost Trend Rate, Assumed		6.60%
Defined Benefit Plan, Target Allocation, Equity Securities		55.00%	58.00%
Defined Benefit Plan, Target Plan Asset Allocations		34.00%	31.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
Defined Benefit Plan, Benefit Obligation, Benefits Paid			$ 72.4
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid			12.5
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		$ 1.4	1.3
Defined Benefit Plan, Benefit Obligation		253.7	289.2	274.7
Defined Benefit Plan, Service Cost		4.6	4.5	4.4
Defined Benefit Plan, Interest Cost		10.1	11.5	$ 12.1
Defined Benefit Plan, Actuarial Net (Gains) Losses		$ 38.4	$ (9.7)
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
Defined Benefit Plan, Plan Assets, Amount		$ 0	$ 0
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(253.7)	(289.2)
Liability, Defined Benefit Plan, Current		(13.3)	(13.5)
Liability, Other Postretirement Defined Benefit Plan, Noncurrent		(240.4)	(275.7)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax		1.1	3.5
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax		0	0
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax		1.1	3.5
pension and other postretirement benefit plans, regulated assets, net gains, before tax		10.9	43.3
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		0	0
Pension and other postretirement benefit plans, regulatory assets, before tax		10.9	43.3
Defined Benefit Plan, Shared Costs Deferred		12.4	14.7
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		(31.8)	9.4	$ 11.1
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(0.6)	(0.8)	(0.4)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		0	0	(0.3)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ (32.4)	$ 8.6	$ 10.4
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.74%	4.30%	4.78%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year		7.00%	6.60%	7.00%
Defined Benefit Plan, Benefit Obligation, Benefits Paid		$ 13.2
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		863.5	$ 933.2	$ 904.3
Defined Benefit Plan, Service Cost		21	21.7	20.7
Defined Benefit Plan, Interest Cost		34.1	37.4	39.4
Defined Benefit Plan, Actuarial Net (Gains) Losses		$ 53.1	$ (42.2)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.35%	3.71%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.00%	3.00%
Defined Benefit Plan, Plan Assets, Amount		$ 727.3	$ 849.6
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(136.2)	(83.6)
Liability, Defined Benefit Plan, Current			0
Liability, Defined Benefit Pension Plan, Noncurrent		(136.2)	(83.6)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax		12.8	8.8
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax		0.1	0.1
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax		12.9	8.9
pension and other postretirement benefit plans, regulated assets, net gains, before tax		230.4	194.8
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		0.7	1.2
Pension and other postretirement benefit plans, regulatory assets, before tax		231.1	196
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		46.7	(27.1)	29.4
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(11.1)	(14.1)	(12.7)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		(0.5)	(1.4)	(3.4)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ 35.1	$ (42.6)	$ 13.3
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.00%	7.25%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.71%	4.22%	4.68%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Benefit Obligation, Benefits Paid		$ 71.7	$ 72.4
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		$ 61.3	62
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year, Description		no
Defined Benefit Plan, Period for which Annual Base Earnings are Considered Under Average Pay Formula		3
Defined Benefit Plan, Accumulated Benefit Obligation		$ 714.3	769.7
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation		$ 0.6	1.3
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation		0.5	1.1
Defined Benefit Plan, Plan Assets, Amount		676.7	781.3	$ 732.9
Defined Benefit Plan, Plan Assets, Increase (Decrease) for Actual Return (Loss)		$ (43.3)	$ 110.4
Defined Benefit Plan Health Care Cost Trend Rate, Assumed		6.60%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.00%
Defined Benefit Plan, Target Allocation, Equity Securities		55.00%	58.00%
Defined Benefit Plan, Target Plan Asset Allocations		34.00%	31.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
SCE&G | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		$ 10.4	$ 10.3
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		1.1	1.1
Defined Benefit Plan, Benefit Obligation		187.4	216.6	207.2
Defined Benefit Plan, Service Cost		3.6	3.7	3.6
Defined Benefit Plan, Interest Cost		8	9.5	$ 9.9
Defined Benefit Plan, Actuarial Net (Gains) Losses		30.7	(6.8)
Defined Benefit Plan, Amounts Funded to Parent		$ (0.8)	$ (1.4)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.38%	3.74%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.00%	3.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
Defined Benefit Plan, Plan Assets, Amount		$ 0	$ 0
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(187.4)	(216.6)
Liability, Defined Benefit Plan, Current		(10.5)	(10.8)
Liability, Other Postretirement Defined Benefit Plan, Noncurrent		(176.9)	(205.8)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax		0.5	1.5
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax		0	0
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax		0.5	1.5
pension and other postretirement benefit plans, regulated assets, net gains, before tax		9	35.9
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		0	0
Pension and other postretirement benefit plans, regulatory assets, before tax		9	35.9
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		(26.4)	7.3	$ 9.2
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(0.5)	(0.7)	0.3
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		0	0	(0.2)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ (26.9)	$ 6.6	$ 8.7
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.74%	4.30%	4.78%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year		7.00%	6.60%	7.00%
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		$ 61.3	$ 62
Defined Benefit Plan, Benefit Obligation		732.3	793	$ 768.4
Defined Benefit Plan, Service Cost		17.1	18.1	16.9
Defined Benefit Plan, Interest Cost		29	31.9	33.4
Defined Benefit Plan, Actuarial Net (Gains) Losses		45.5	(36.6)
Defined Benefit Plan, Amounts Funded to Parent		$ 0	$ 0
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.35%	3.71%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.00%	3.00%
Defined Benefit Plan, Plan Assets, Amount		$ 676.7	$ 781.3
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(55.6)	(11.7)
Liability, Defined Benefit Plan, Current			0
Liability, Defined Benefit Pension Plan, Noncurrent		(55.6)	(11.7)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax		3.4	2.1
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax		0	0
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax		3.4	2.1
pension and other postretirement benefit plans, regulated assets, net gains, before tax		202.4	171.4
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		0.6	1
Pension and other postretirement benefit plans, regulatory assets, before tax		203	172.4
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		40.7	(24.8)	26.3
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(9.7)	(12.5)	(11.2)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		(0.4)	(1.3)	(3)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ 30.6	$ (38.6)	$ 12.1
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.00%	7.25%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.71%	4.22%	4.68%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Pension Costs [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority		$ 1
Pension Costs [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority		$ 2
Scenario, Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	7.00%
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%
Scenario, Forecast [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%

EMPLOYEE BENEFIT PLANS EMPLOYEE

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 2)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities		55.00%	58.00%
Defined Benefit Plan, Target Plan Asset Allocations		34.00%	31.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities		55.00%	58.00%
Defined Benefit Plan, Target Plan Asset Allocations		34.00%	31.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
Scenario, Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%
Scenario, Forecast [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%

EMPLOYEE BENEFIT PLANS EMPLOY_2

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 727.3	$ 849.6	$ 793.6
Compensation and Benefits Trust	$ 400	$ 498
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Alternative Investment	$ 727	$ 850
Noncontrolling Interest in Joint Ventures	83	92
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	244	260
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	107	120
Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	20	17
Fair Value, Inputs, Level 2 [Member] | Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	7	15
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	92	91
Fair Value, Inputs, Level 2 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	18	17
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	676.7	781.3	$ 732.9
Compensation and Benefits Trust	$ 373	$ 458
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Alternative Investment	$ 677	$ 781
Noncontrolling Interest in Joint Ventures	77	84
SCE&G | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	227	239
SCE&G | Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	99	110
SCE&G | Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	19	16
SCE&G | Fair Value, Inputs, Level 2 [Member] | Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	7	14
SCE&G | Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	86	84
SCE&G | Fair Value, Inputs, Level 2 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 16	$ 15

EMPLOYEE BENEFIT PLANS EMPLOY_3

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 4) $ in Millions	Dec. 31, 2018USD ($)
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	$ 71.5
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	62.4
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	65.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	69.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	66.6
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	284.9
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	13.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	14.3
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	14.9
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	15.4
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	15.8
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	82.3
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	71.5
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	62.4
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	65.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	69.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	66.6
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	284.9
SCE&G | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	10.8
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	11.4
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	11.8
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	12.2
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	12.6
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	$ 65.4

EMPLOYEE BENEFIT PLANS EMPLOY_4

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		$ 2	$ 0	$ 0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		$ (2)	0	1
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%
Defined Contribution Plan, Maximum Percentage of Employer Contribution for up to Six Percent of Participant Contribution		100.00%
Defined Contribution Plan, Maximum Percentage of Participant Contribution Eligible for Employer Contribution Match		6.00%
Defined Contribution Plan, Cost		$ 24.1	27.9	27.5
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		4.5	(1)	0.6
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		(0.5)	(0.6)	(0.6)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax		0	0	(0.1)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		4	(1.6)	(0.1)
Defined Benefit Plan, Service Cost		21	21.7	20.7
Defined Benefit Plan, Interest Cost		34.1	37.4	39.4
Defined Benefit Plan, Expected Return (Loss) on Plan Assets		(56.7)	(54.7)	(55.9)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0.5	1.6	3.9
Defined Benefit Plan, Amortization of Gain (Loss)		12.8	16.3	14.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 11.7	$ 22.3	$ 22.9
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.71%	4.22%	4.68%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.00%	7.25%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		$ (2.4)	$ 1.1	$ 0.8
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		0	(0.1)	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax		0	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		(2.4)	1	0.8
Defined Benefit Plan, Service Cost		4.6	4.5	4.4
Defined Benefit Plan, Interest Cost		10.1	11.5	12.1
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0	0	0.3
Defined Benefit Plan, Amortization of Gain (Loss)		0.7	1	0.5
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 15.4	$ 17	$ 17.3
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.74%	4.30%	4.78%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year		7.00%	6.60%	7.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		$ 0	$ 0	$ 0
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		$ 0	(1)	0
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year		insignificant
Defined Contribution Plan, Maximum Percentage of Employer Contribution for up to Six Percent of Participant Contribution		100.00%
Defined Contribution Plan, Maximum Percentage of Participant Contribution Eligible for Employer Contribution Match		6.00%
Defined Contribution Plan, Cost		$ 19.6	23.4	22.9
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		1.4	0.3	0
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		(0.1)	(0.1)	(0.1)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		1.3	0.2	(0.1)
Defined Benefit Plan, Service Cost		17.1	18.1	16.9
Defined Benefit Plan, Interest Cost		29	31.9	33.4
Defined Benefit Plan, Expected Return (Loss) on Plan Assets		(48.1)	(46.7)	(47.4)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0.4	1.4	3.4
Defined Benefit Plan, Amortization of Gain (Loss)		10.9	13.9	12.5
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 9.3	$ 18.6	$ 18.8
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.71%	4.22%	4.68%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.00%	7.25%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
SCE&G | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		$ (1)	$ 0.5	$ 0.3
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		0	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		(1)	0.5	0.3
Defined Benefit Plan, Service Cost		3.6	3.7	3.6
Defined Benefit Plan, Interest Cost		8	9.5	9.9
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0	0	0.3
Defined Benefit Plan, Amortization of Gain (Loss)		0.6	0.8	0.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 12.2	$ 14	$ 14.2
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.74%	4.30%	4.78%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year		7.00%	6.60%	7.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
Scenario, Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	7.00%
Scenario, Forecast [Member] | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Amortization of Net Gains (Losses)	$ 0.8
Defined benefit plan, future amortization of gain or loss from regulatory assets	14.7
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	0.3
Defined benefit plan, amount to be amortized from regulatory assets next year	15
Scenario, Forecast [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Amortization of Net Gains (Losses)	0
Defined benefit plan, future amortization of gain or loss from regulatory assets	0
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	0
Defined benefit plan, amount to be amortized from regulatory assets next year	0
Scenario, Forecast [Member] | SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, future amortization of gain or loss from regulatory assets	12.9
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	0.3
Defined benefit plan, amount to be amortized from regulatory assets next year	13.2
Scenario, Forecast [Member] | SCE&G | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, future amortization of gain or loss from regulatory assets	0
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	0
Defined benefit plan, amount to be amortized from regulatory assets next year	$ 0

SHARE-BASED COMPENSATION (Detai

SHARE-BASED COMPENSATION (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost	$ 28,600,000
Employee Service Share-based Compensation, Cash Flow Effect, Cash Used to Settle Awards	$ 19,600,000	$ 9,100,000	$ 6,700,000	$ 5.5	$ 28	$ 18.4
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized				5,000,000
Restricted Stock Units
Share-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized				1,000,000

SHARE-BASED COMPENSATION Liabil

SHARE-BASED COMPENSATION Liability Awards (Details) - USD ($)	Feb. 28, 2019	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Liability Awards
Cash-Settled Liabilities		$ 19,600,000	$ 9,100,000	$ 6,700,000	$ 5.5	$ 28	$ 18.4
Compensation Expenses Recognized Resulting From Fair Value Adjustments of Performance Awards					$ (1.7)	(9)	25.6
Capitalized Compensation Expense						(1.3)	3.3
Performance Shares [Member]
Liability Awards
Weight of Entity's Performance Against Pre-Determined Measures of Total Stockholder Return As Compared to Peer Groups of Utilities to Determine Payout of Performance Shares as a Percentage					50.00%
Weight of Growth in GAAP-adjusted net earnings per share from operations to determine payout of performance shares as a percent					50.00%
SCE&G
Liability Awards
Cash-Settled Liabilities					$ 3.5	20.2	13.2
Compensation Expenses Recognized Resulting From Fair Value Adjustments of Performance Awards					$ (0.9)	(6.3)	17.3
Capitalized Compensation Expense						$ (0.9)	$ 3.1
SCE&G | Restricted Stock Units
Liability Awards
Performance Cycle (in years)				3 years
Percentage of Performance Award Granted in Form of Restricted Stock Units (as a percent)					30.00%
SCE&G | Performance Shares [Member]
Liability Awards
Percentage of Performance Award Granted in Form of Performance Shares (as a percent)					70.00%
Weight of Entity's Performance Against Pre-Determined Measures of Total Stockholder Return As Compared to Peer Groups of Utilities to Determine Payout of Performance Shares as a Percentage					50.00%
Weight of Growth in GAAP-adjusted net earnings per share from operations to determine payout of performance shares as a percent					50.00%
Subsequent Event [Member] | Restricted Stock Units
Liability Awards
Percentage of Performance Award Granted in Form of Restricted Stock Units (as a percent)	30.00%
Subsequent Event [Member] | Performance Shares [Member]
Liability Awards
Percentage of Performance Award Granted in Form of Performance Shares (as a percent)	70.00%
Subsequent Event [Member] | SCE&G | Restricted Stock Units
Liability Awards
Percentage of Performance Award Granted in Form of Restricted Stock Units (as a percent)	30.00%
Subsequent Event [Member] | SCE&G | Performance Shares [Member]
Liability Awards
Percentage of Performance Award Granted in Form of Performance Shares (as a percent)	70.00%

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Details)	3 Months Ended		12 Months Ended
	Dec. 31, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Commitments and contingencies
Legal Expense, net of taxes			$ 118,000,000
Operating Lease, Payments				$ 10
Estimate of aggregate amount of subcontractor and vendor liens filed			285,000,000
Guarantee Settlement Receipts			2,200,000,000
Impairment loss write off	$ 1,372,000,000	$ 4,000,000	1,372,000,000	1,118,000,000
Monetization Settlement Exceeding Costs Incurred			1,997,000,000
Asset Retirement Obligation Other Conditional Obligations	359,000,000		359,000,000
Asset Retirement Obligation	$ 577,000,000		577,000,000	568,000,000	$ 558,000,000
Asset Retirement Obligation, Liabilities Incurred			0	0
Asset Retirement Obligation, Liabilities Settled			(15,000,000)	(10,000,000)
Asset Retirement Obligation, Accretion Expense			25,000,000	25,000,000
Asset Retirement Obligation, Revision of Estimate			$ (1,000,000)	$ (5,000,000)
Environmental
Emission Rate Standard For Coal Fired Power Plants Under Clean Air Act	1,400		1,400
Emission Rate Standard for Natural Gas	1,000		1,000
Goal For Reduced Carbon Dioxide Emissions From 2005 Levels By 2030 Under Clean Air Act			32.00%
Number of States affected by CSAPR	28		28
Nuclear Generation
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA				18.00%
Change in Retail Electric Rates Approved Under BLRA			$ 2,768,000,000		64,400,000
Public Utilities, Requested Rate Increase (Decrease), Amount			31,000,000
Managing Member or General Partner, Subsequent Distribution Amount			115,000,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances			2,000,000,000
Contractual Obligation, Due in Next Fiscal Year	$ 23.7		23.7	$ 3.6
SCE&G
Commitments and contingencies
Operating Lease, Payments			10	11	12
Estimate of aggregate amount of subcontractor and vendor liens filed			33,000,000
Guarantee Settlement Receipts			1,200,000,000
Monetization Settlement Exceeding Costs Incurred			1,098,000,000
Asset Retirement Obligation Other Conditional Obligations	323,000,000		323,000,000
Asset Retirement Obligation	541,000,000		541,000,000	529,000,000	522,000,000
Asset Retirement Obligation, Liabilities Incurred			0	0
Asset Retirement Obligation, Liabilities Settled			(15,000,000)	(9,000,000)
Asset Retirement Obligation, Accretion Expense			23,000,000	23,000,000
Asset Retirement Obligation, Revision of Estimate			4,000,000	$ (7,000,000)
Nuclear Insurance
Maximum Insurance Coverage For Each Nuclear Plant by ANI	450,000,000		450,000,000
Federal Limit on Public Liability Claims from Nuclear Incident Approximate			14,000,000,000
Maximum liability assessment per reactor for each nuclear incident			137,700,000
Maximum yearly assessment per reactor			20,500,000
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3			91,800,000
Maximum Insurance Coverage for Nuclear events	2,750,000,000		2,750,000,000
NEIL Maximum Insurance Coverage To Nuclear Facility For Property Damage And Outage Costs From Non-Nuclear Event			2,330,000,000
Maximum prosepective insurance premium per nuclear incident			23,400,000
Maximum amount of coverage to nuclear facility for property damage and outage costs	2,750,000,000		2,750,000,000
EMANI Maximum Insurance Coverage for Summer Station Unit 1 For Property Damage And Outage Costs From Non-Nuclear Event			415,000,000
EMANI Maximum Retrospective Premium Assessment			2,000,000
Environmental
Environmental Remediation Expense			9,500,000
Deferred costs, net of costs previously recovered through rates and insurance settlements included in regulatory assets	23,300,000		23,300,000
Nuclear Generation
Asset Retirement Obligation Nuclear Decommissioning	218,000,000		218,000,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances			31,000,000		$ 61,000,000
SCE&G | SCE&G
Nuclear Insurance
Maximum yearly assessment per reactor			13,700,000
Summer Station Unit 2 and Unit 3 [Domain]
Commitments and contingencies
Transmission Assets related to BLRA Capital Costs	$ 367,000,000		367,000,000
Estimate of aggregate amount of subcontractor and vendor liens filed			$ 60,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%		55.00%
Other Regulatory Assets (Liabilities) [Member] | Summer Station Unit 2 and Unit 3 [Domain]
Commitments and contingencies
Transmission Assets related to BLRA Capital Costs	$ 15,000,000		$ 15,000,000

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES Nuclear (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Legal Settlements				$ 157,000
Deferred Tax Asset, Legal Settlement net of tax	$ 274,000			$ 274,000	$ 273,000
Loss Contingency, Actions Taken by Plaintiff				75
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 31,000
Impairment loss write off	1,372,000	$ 4,000		1,372,000	1,118,000
Increase (Decrease) in Client Funds Held				2,000,000
Utilities Operating Expense, Impairments				1,376,000	1,118,000
Utilities Operating Loss, Impairment, Net of Taxes	870,000	$ 3,000		53,000	690,000
Guarantee Settlement Receipts				2,200,000
Estimate of aggregate amount of subcontractor and vendor liens filed				285,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances				2,000,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery			$ 35,400	1,300
Monetization Settlement Exceeding Costs Incurred				1,997,000
Long-term Debt, Current Maturities	59,000			59,000	727,000
Short-term borrowings	173,000			173,000	$ 350,000
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment				105,000
Customer Fees, Refunds Payments, Additional Liability Alternative Plan	1,007,000			1,007,000
Refundable Gas Costs	2,450			2,450
Multiemployer Plans, Minimum Contribution	22,000			22,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Impairment Losses	145,000			145,000
Increase (Decrease) in Property and Other Taxes Payable			$ 410,000
PSNC Energy [Member]
Public Utilities, Authorized Allowable Return on Common Equity, Percentage					9.70%
Multiemployer Plans, Minimum Contribution	1,000			1,000
SCE&G
Deferred Tax Asset, Legal Settlement net of tax	274,000			274,000	$ 273,000
EMANI Maximum Insurance Coverage for Summer Station Unit 1 For Property Damage And Outage Costs From Non-Nuclear Event				415,000
Federal Limit on Public Liability Claims from Nuclear Incident Approximate				14,000,000
EMANI Maximum Retrospective Premium Assessment				2,000
Utilities Operating Expense, Impairments				1,376,000	1,118,000
Utilities Operating Loss, Impairment, Net of Taxes				46,000
Guarantee Settlement Receipts				1,200,000
Estimate of aggregate amount of subcontractor and vendor liens filed				33,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances				31,000		$ 61,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery					61,000
Monetization Settlement Exceeding Costs Incurred				1,098,000
Long-term Debt, Current Maturities	14,000			14,000	723,000
Short-term borrowings	73,000			73,000	$ 252,000
Maximum Insurance Coverage For Each Nuclear Plant by ANI	450,000			450,000
Summer Station Unit 2 and Unit 3 [Domain]
Transmission Assets related to BLRA Capital Costs	367,000			367,000
Estimate of aggregate amount of subcontractor and vendor liens filed				60,000
Summer Station Unit 2 and Unit 3 [Domain]
Transmission Assets related to BLRA Capital Costs	$ 15,000			$ 15,000

SEGMENT OF BUSINESS INFORMATI_3

SEGMENT OF BUSINESS INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Total	$ 17,654				$ 18,739				$ 17,654	$ 18,739	$ 18,707
Additions to Other Assets, Amount									890	1,225	1,579
Deferred Tax Assets, Gross	0				0				0	0	0
Regulated and Unregulated Operating Revenue	1,103	$ 926	$ 843	$ 1,180	1,157	$ 1,076	$ 1,001	$ 1,173	4,052	4,407	4,227
Intersegment Revenue									0	0	0
Operating Income	(1,204)	183	103	189	(608)	122	251	320	(729)	85	1,167
Interest Expense									384	363	342
Depreciation, Depletion and Amortization									403	382	371
Income Tax Expense (Benefit)									(412)	(112)	271
Income Available to Common Shareholders	(772)	67	8	169	(445)	34	121	171	(528)	(119)	595
Regulated Operating Revenue, Gas									934	874	788
Electric Operations
Segment Reporting Information [Line Items]
Total	7,988				11,979				7,988	11,979	11,929
Additions to Other Assets, Amount									973	216	1,275
Deferred Tax Assets, Gross	(4)				(6)				(4)	(6)	(9)
Regulated and Unregulated Operating Revenue									2,322	2,659	2,614
Intersegment Revenue									5	5	5
Operating Income									(894)	(154)	969
Interest Expense									18	19	17
Depreciation, Depletion and Amortization									307	295	287
Income Tax Expense (Benefit)									9	8	8
Gas Distribution
Segment Reporting Information [Line Items]
Total	3,517				3,259				3,517	3,259	2,892
Additions to Other Assets, Amount									345	417	276
Deferred Tax Assets, Gross	(17)				(25)				(17)	(25)	(32)
Regulated and Unregulated Operating Revenue									934	874	788
Intersegment Revenue									1	2	2
Operating Income									173	187	149
Interest Expense									37	28	25
Depreciation, Depletion and Amortization									94	85	82
Income Tax Expense (Benefit)									26	41	32
Gas Marketing [Member]
Segment Reporting Information [Line Items]
Total	305				230				305	230	230
Additions to Other Assets, Amount									2	2	2
Deferred Tax Assets, Gross	(2)				(9)				(2)	(9)	(11)
Regulated and Unregulated Operating Revenue									796	874	825
Intersegment Revenue									139	127	111
Interest Expense									1	1	1
Depreciation, Depletion and Amortization									2	2	2
Income Tax Expense (Benefit)									15	25	19
Income Available to Common Shareholders									43	27	30
All Other [member]
Segment Reporting Information [Line Items]
Total	1,212				1,042				1,212	1,042	1,124
Additions to Other Assets, Amount									8	7	11
Deferred Tax Assets, Gross	0				0				0	0	0
Regulated and Unregulated Operating Revenue									0	0	0
Intersegment Revenue									470	389	414
Operating Income									0	0	0
Interest Expense									0	0	0
Depreciation, Depletion and Amortization									15	16	16
Income Tax Expense (Benefit)									(25)	(7)	0
Income Available to Common Shareholders									(90)	(46)	(18)
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Total	4,632				2,229				4,632	2,229	2,532
Additions to Other Assets, Amount									(438)	583	15
Deferred Tax Assets, Gross	23				40				23	40	52
Regulated and Unregulated Operating Revenue									0	0	0
Intersegment Revenue									(615)	(523)	(532)
Operating Income									(8)	52	49
Interest Expense									328	315	299
Depreciation, Depletion and Amortization									(15)	(16)	(16)
Income Tax Expense (Benefit)									(437)	(179)	212
Income Available to Common Shareholders									(481)	(100)	583
SCE&G
Segment Reporting Information [Line Items]
Total	14,963				15,946				14,963	15,946	16,091
Additions to Other Assets, Amount									633	928	1,399
Deferred Tax Assets, Gross	0				0				0	0	0
Regulated Operating Revenue	689	739	632	702	739	856	756	719	2,762	3,070	2,986
Operating Income	(1,271)	$ 212	$ 107	$ 121	(680)	$ 124	$ 247	$ 226	(831)	(83)	1,025
Interest Expense									303	288	270
Depreciation, Depletion and Amortization									327	312	302
Income Tax Expense (Benefit)									(416)	(171)	248
Regulated Operating Revenue, Gas									434	405	366
SCE&G | Electric Operations
Segment Reporting Information [Line Items]
Total	7,988								7,988		11,929
Additions to Other Assets, Amount									973		1,275
Deferred Tax Assets, Gross	(4)								(4)		(9)
Regulated Operating Revenue									2,327
Operating Income									(894)		969
Interest Expense									18	19	17
Depreciation, Depletion and Amortization									307	295	287
SCE&G | Gas Distribution
Segment Reporting Information [Line Items]
Total	934				869				934	869	825
Additions to Other Assets, Amount									90	65	78
Regulated and Unregulated Operating Revenue									435	406	367
Regulated Operating Revenue									435
Operating Income									63	71	56
Depreciation, Depletion and Amortization									32	30	28
SCE&G | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Total	6,041				3,098				6,041	3,098	3,337
Additions to Other Assets, Amount									(430)	647	46
Deferred Tax Assets, Gross	$ 4				$ 6				4	6	9
Operating Income											0
Interest Expense									285	269	253
Depreciation, Depletion and Amortization									(12)	(13)	(13)
External revenue [Member] | SCE&G
Segment Reporting Information [Line Items]
Regulated and Unregulated Operating Revenue									$ 2,327	$ 2,664	$ 2,619

UTILITY PLANT AND NONUTILITY _3

UTILITY PLANT AND NONUTILITY PROPERTY Jointly Owned Utiltiy Plant (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Utility Plant In Service	$ 15,171	$ 14,370
Property, Plant and Equipment, Gross	410
Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	5,751
Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	16,309
Gas Transmission Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	2,417
Electric Distribution [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	6,032
Natural Gas, Storage [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	99
Other Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	631
Other Intangible Assets [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	241
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	527
Nuclear Fuel [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	611
Summer Station Units 1 [Domain]
Property, Plant and Equipment [Line Items]
Accounts Receivable, Net	$ 46.3	$ 53.8
Jointly Owned Utility Plant, Proportionate Ownership Share	67.00%	67.00%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 1,500	$ 1,500
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	643.9	637.6
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	127.5	110.1
SCE&G
Property, Plant and Equipment [Line Items]
Utility Plant In Service	12,803	$ 12,161
SCE&G | Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	5,751
Property, Plant and Equipment, Gross	73
SCE&G | Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	13,764
SCE&G | Gas Transmission Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	1,758
SCE&G | Electric Distribution [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	4,456
SCE&G | Natural Gas, Storage [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	74
SCE&G | Other Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	535
SCE&G | Other Intangible Assets [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	229
SCE&G | Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	350
SCE&G | Nuclear Fuel [Member]
Property, Plant and Equipment [Line Items]
Utility Plant In Service	$ 611

AFFILIATED TRANSACTIONS (Detail

AFFILIATED TRANSACTIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Proceeds from Equity Method Investment, Distribution	$ 2.3	$ 2.8	$ 3.7
Equity Method Investments	4.2	4.6	5.5
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Related Party Tax Expense, Due to Affiliates, Current	6.8	4.9
Related Party Transaction, Purchases from Related Party	149.9	162.1	161.8
Related Party Tax Expense, Due from Affiliates, Current	$ 6.8	4.9
Equity Method Investment, Ownership Percentage	40.00%
Sales to Affiliate	$ 149	161.1	160.8
Energy Marketing [Member]
Related Party Transaction [Line Items]
Utilities Operating Expense, Gas and Petroleum Purchased, affiliate	139	127.4	111.5
SCE&G
Related Party Transaction [Line Items]
Utilities Operating Expense, Gas and Petroleum Purchased, affiliate			9
Related Party Tax Expense, Due to Affiliates, Current	14.1	10
Accounts Payable, Related Parties, Current	37.7	42
SCANA Services [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 283.3	$ 302.8	$ 337.7

OTHER INCOME (EXPENSE), NET (De

OTHER INCOME (EXPENSE), NET (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other income	$ 180	$ 79	$ 64
Other Nonoperating Expense	(46)	(55)	(52)
Public Utilities, Allowance for Funds Used During Construction, Additions	19	23	29
Nonoperating Income (Expense)	(173)	(47)	(41)
SCE&G
Other income	141	45	29
Other Nonoperating Expense	(28)	(32)	(36)
Public Utilities, Allowance for Funds Used During Construction, Additions	11	15	26
Nonoperating Income (Expense)	(129)	$ (28)	$ (19)
Interest Rate Contract [Member] | Other Income [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ 114

QUARTERLY FINANCIAL INFORMATI_3

QUARTERLY FINANCIAL INFORMATION (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Regulated and Unregulated Operating Revenue	$ 1,103	$ 926	$ 843	$ 1,180	$ 1,157	$ 1,076	$ 1,001	$ 1,173	$ 4,052	$ 4,407	$ 4,227
Operating Income (Loss)	(1,204)	183	103	189	(608)	122	251	320	(729)	85	1,167
Income Available to Common Shareholders	$ (772)	$ 67	$ 8	$ 169	$ (445)	$ 34	$ 121	$ 171	$ (528)	$ (119)	$ 595
Earnings Per Share, Basic and Diluted	$ (5.41)	$ 0.47	$ 0.06	$ 1.18	$ (3.11)	$ 0.24	$ 0.85	$ 1.19	$ (3.70)	$ (0.83)	$ 4.16
SCE&G
Regulated Operating Revenue	$ 689	$ 739	$ 632	$ 702	$ 739	$ 856	$ 756	$ 719	$ 2,762	$ 3,070	$ 2,986
Operating Income (Loss)	(1,271)	212	107	121	(680)	124	247	226	(831)	(83)	1,025
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(852)	104	31	128	(452)	42	126	112	(589)	(172)	526
Net Income (Loss) Attributable to Parent	$ (861)	$ 98	$ 26	$ 124	$ (456)	$ 39	$ 123	$ 109	(613)	$ (185)	$ 513
Income (Loss) from Continuing Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest									$ (613)

SCHEDULE II (Details)

SCHEDULE II (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
SEC Schedule, 12-09, Allowance, Credit Loss [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	$ 7	$ 6	$ 6	$ 5
Valuation Allowances and Reserves, Charged to Cost and Expense	15	13	12
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	14	13	11
General Liability [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	7	9	9	6
Valuation Allowances and Reserves, Charged to Cost and Expense	5	8	5
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	7	8	2
SCE&G | SEC Schedule, 12-09, Allowance, Credit Loss [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	4	4	3	3
Valuation Allowances and Reserves, Charged to Cost and Expense	7	8	6
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	7	7	6
SCE&G | General Liability [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	6	8	8	$ 5
Valuation Allowances and Reserves, Charged to Cost and Expense	5	8	5
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	$ 7	$ 8	$ 2