Dominion Energy South Carolina (SCG) 10-Q 5 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document - shares	9 Months Ended
	Sep. 30, 2018	Oct. 26, 2018
Entity Information [Line Items]
Entity Registrant Name	SCANA Corporation
Entity Central Index Key	754,737
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		142,619,243
SCEG
Entity Information [Line Items]
Entity Registrant Name	SOUTH CAROLINA ELECTRIC & GAS CO
Entity Central Index Key	91,882
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,296,147

CONDENSED CONSOLIDATED BALANCE

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

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Common Stock, Shares, Outstanding	143	143
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 140	$ 133
Public Utilities, Property, Plant and Equipment, Net	10,882	10,648
Allowance for Doubtful Accounts Receivable, Current	4	6
Write-down, Goodwill	230	230
Assets, Current	1,420	1,851
Regulated Entity, Other Assets, Noncurrent	$ 5,971	$ 5,766
SCEG
Common Stock, Shares, Outstanding	40.3	40.3
Public Utilities, Property, Plant and Equipment, Net	$ 8,690	$ 8,620
Allowance for Doubtful Accounts Receivable, Current	3	4
Assets, Current	1,352	1,477
Regulated Entity, Other Assets, Noncurrent	5,874	5,640
SCEG | Variable Interest Entity, Primary Beneficiary [Member]
Public Utilities, Property, Plant and Equipment, Net	676	711
Assets, Current	74	191
Regulated Entity, Other Assets, Noncurrent	$ 34	$ 50

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating Revenues:
Electric Regulated Revenue	$ 669	$ 786	$ 1,767	$ 2,042
Regulated Operating Revenue, Gas	122	123	631	584
Gas-nonregulated	135	167	550	623
Regulated and Unregulated Operating Revenue	926	1,076	2,948	3,249
Operating Expenses
Fuel used in electric generation	188	167	503	464
Purchased power	10	22	77	54
Utilities Operating Expense, Gas and Petroleum Purchased	177	211	774	808
Other operation and maintenance	201	181	610	535
Utilities Operating Expense, Impairments	0	210	4	210
Depreciation and amortization	100	96	299	285
Other taxes	67	67	206	200
Total Operating Expenses	743	954	2,473	2,556
Operating Income	183	122	475	693
Other Nonoperating Income (Expense)	3	19	136	45
Other Income (Expense):
Other income	8	28	144	61
Other expense	(14)	(9)	(34)	(33)
Interest Expense	(99)	(95)	(292)	(270)
Allowance for equity funds used during construction			12	17
Income Before Income Tax Expense	87	46	319	468
Income Tax Expense	20	12	75	142
Net Income (Loss) Available to Common Stockholders, Basic	$ 67	$ 34	$ 244	$ 326
Earnings Per Share, Basic and Diluted	$ 0.47	$ 0.24	$ 1.71	$ 2.28
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	$ 0	$ 0
Other Comprehensive Income (Loss), Net of Tax	$ 5	$ 3	$ 16	$ 0
Per Common Share Data
Weighted Average Number of Shares Outstanding, Basic and Diluted	143	143	143	143
Weighted Average Common Shares Outstanding (millions)
Common Stock, Dividends, Per Share, Declared	$ 0.1237	$ 0.6125	$ 0.8599	$ 1.838
SCEG
Operating Revenues:
Electric Regulated Revenue	$ 669	$ 786	$ 1,767	$ 2,042
Electric Domestic Regulated Revenues - Affiliate	1	1	3	4
Regulated Operating Revenue, Gas	69	69	303	284
Regulated Operating Revenue Gas, Affiliate		0	1	1
Regulated Operating Revenue	739	856	2,074	2,331
Operating Expenses
Fuel used in electric generation	153	132	408	370
Fuel used in electric generation, affiliate	35	35	95	94
Purchased power	10	22	77	54
Utilities Operating Expense, Gas and Petroleum Purchased	41	39	161	147
Other operation and maintenance	105	109	320	305
Other operation and maintenance, affiliate	39	44	135	135
Utilities Operating Expense, Impairments		210	4	210
Depreciation and amortization	81	78	242	232
Other taxes	61	62	188	183
Other taxes, affiliate	2	1	4	4
Total Operating Expenses	527	732	1,634	1,734
Operating Income	212	124	440	597
Other Nonoperating Income (Expense)	(1)	11	124	26
Other Income (Expense):
Other income	5	21	135	36
Other expense	(10)	(7)	(22)	(23)
Interest Expense	(79)	(76)	(232)	(214)
Allowance for equity funds used during construction			7	13
Income Before Income Tax Expense	132	59	332	409
Income Tax Expense	29	17	70	129
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	103	42	262	280
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	1		1
Other Comprehensive Income (Loss), Net of Tax	104	42	263	280
Net Income (Loss) Attributable to Noncontrolling Interest	6	3	15	10
Earnings Available to Common Shareholder	$ 98	$ 39	$ 248	$ 270
Weighted Average Common Shares Outstanding (millions)
Common Stock, Dividends, Per Share, Declared	$ 17,000,000	$ 81,000,000

CONDENSED CONSOLIDATED STATEM_2

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

CONDENSED CONSOLIDATED STATEM_3

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

CONDENSED CONSOLIDATED STATEM_4

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

CONDENSED CONSOLIDATED STATEM_5

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

CONDENSED CONSOLIDATED STATEM_6

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

CONSOLIDATED STATEMENTS OF COMM

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

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	9 Months Ended
	Sep. 30, 2018
Significant Accounting Policies
Significant Accounting Policies [Text Block]	1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Consolidation and Variable Interest Entities The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $495 million ) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5. Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 11) are presented within Operating Income, and other activities are presented within Other Income (Expense). Asset Management and Supply Service Agreement PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 45% and 39% of PSNC Energy’s natural gas inventory at September 30, 2018 and December 31, 2017, respectively, with a carrying value of $14.3 million and $11.5 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to customers. This agreement expires on March 31, 2019. Earnings Per Share The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. Reclassifications In the statement of operations, amounts reported for 2017 under the captions “Other income,” “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net.” Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated. New Accounting Matters Recently Adopted In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact or no significant impact on their respective financial statements except as indicated. • In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company adopted this guidance on January 1, 2018. • Effective January 1, 2018, the Company and Consolidated SCE&G adopted new accounting guidance for revenue arising from contracts with customers. This guidance uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods are not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3. • Effective January 1, 2018, the Company and Consolidated SCE&G adopted accounting guidance that changed the required presentation of net periodic pension and postretirement benefit costs. As a result, net periodic pension and postretirement benefit costs have been separated into their service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees during the period. Non-service cost components are now excluded from operating income. This guidance has been applied on a retrospective basis for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017. Increase (Decrease) Millions of dollars The Company Consolidated SCE&G September 30, 2017 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended Other operation and maintenance $ (2 ) $ (8 ) $ (1 ) $ (6 ) Total Operating Expenses (2 ) (8 ) (1 ) (6 ) Operating Income 2 8 1 6 Other Income (Expense), Net (2 ) (8 ) (1 ) (6 ) In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost component, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs, and the adoption of this guidance did not result in a material impact on the Company’s and Consolidated SCE&G’s respective financial statements. Amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets. • Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things. • Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented. • Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented. Pending Adoption The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below. In February 2016, the FASB issued accounting guidance related to the recognition, measurement and presentation of leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further, depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. In the first quarter of 2018, FASB amended this accounting guidance to clarify that land easements are within the scope of the new guidance and to provide an optional transition practical expedient, that the Company and Consolidated SCE&G intend to adopt, that allows adopters to not evaluate under the new guidance existing or expired land easements that were not previously accounted for as leases. FASB also approved a new transition option in the first quarter of 2018, that the Company and Consolidated SCE&G intend to adopt, that will allow the new standard to be adopted without revising comparative period reporting or disclosures. The new guidance is effective for years beginning in 2019, and the Company and Consolidated SCE&G do not anticipate that its adoption will have a material impact on their respective financial statements other than increasing amounts reported for assets and liabilities on the balance sheet and changing the location on their respective statements of operations where certain expenses are recorded. No impact on net income is expected. The identification and analysis of leasing and related contracts to which the guidance will apply continues. In addition, the Company and Consolidated SCE&G are implementing a third party software tool to assist with initial adoption and ongoing compliance. System configuration has been completed and data input for financing leases is underway. In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements. In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2019 and do not expect it to have a significant impact on their respective financial statements. In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2019 and do not expect it to have any impact on their respective financial statements. In August 2018, the FASB issued accounting guidance to modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance must be applied retrospectively to all periods presented. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position.
SCEG
Significant Accounting Policies
Significant Accounting Policies [Text Block]	1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Consolidation and Variable Interest Entities The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $495 million ) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5. Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 11) are presented within Operating Income, and other activities are presented within Other Income (Expense). Asset Management and Supply Service Agreement PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 45% and 39% of PSNC Energy’s natural gas inventory at September 30, 2018 and December 31, 2017, respectively, with a carrying value of $14.3 million and $11.5 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to customers. This agreement expires on March 31, 2019. Earnings Per Share The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. Reclassifications In the statement of operations, amounts reported for 2017 under the captions “Other income,” “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net.” Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated. New Accounting Matters Recently Adopted In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact or no significant impact on their respective financial statements except as indicated. • In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company adopted this guidance on January 1, 2018. • Effective January 1, 2018, the Company and Consolidated SCE&G adopted new accounting guidance for revenue arising from contracts with customers. This guidance uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods are not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3. • Effective January 1, 2018, the Company and Consolidated SCE&G adopted accounting guidance that changed the required presentation of net periodic pension and postretirement benefit costs. As a result, net periodic pension and postretirement benefit costs have been separated into their service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees during the period. Non-service cost components are now excluded from operating income. This guidance has been applied on a retrospective basis for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017. Increase (Decrease) Millions of dollars The Company Consolidated SCE&G September 30, 2017 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended Other operation and maintenance $ (2 ) $ (8 ) $ (1 ) $ (6 ) Total Operating Expenses (2 ) (8 ) (1 ) (6 ) Operating Income 2 8 1 6 Other Income (Expense), Net (2 ) (8 ) (1 ) (6 ) In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost component, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs, and the adoption of this guidance did not result in a material impact on the Company’s and Consolidated SCE&G’s respective financial statements. Amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets. • Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things. • Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented. • Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented. Pending Adoption The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below. In February 2016, the FASB issued accounting guidance related to the recognition, measurement and presentation of leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further, depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. In the first quarter of 2018, FASB amended this accounting guidance to clarify that land easements are within the scope of the new guidance and to provide an optional transition practical expedient, that the Company and Consolidated SCE&G intend to adopt, that allows adopters to not evaluate under the new guidance existing or expired land easements that were not previously accounted for as leases. FASB also approved a new transition option in the first quarter of 2018, that the Company and Consolidated SCE&G intend to adopt, that will allow the new standard to be adopted without revising comparative period reporting or disclosures. The new guidance is effective for years beginning in 2019, and the Company and Consolidated SCE&G do not anticipate that its adoption will have a material impact on their respective financial statements other than increasing amounts reported for assets and liabilities on the balance sheet and changing the location on their respective statements of operations where certain expenses are recorded. No impact on net income is expected. The identification and analysis of leasing and related contracts to which the guidance will apply continues. In addition, the Company and Consolidated SCE&G are implementing a third party software tool to assist with initial adoption and ongoing compliance. System configuration has been completed and data input for financing leases is underway. In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements. In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2019 and do not expect it to have a significant impact on their respective financial statements. In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2019 and do not expect it to have any impact on their respective financial statements. In August 2018, the FASB issued accounting guidance to modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance must be applied retrospectively to all periods presented. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position.

RATE AND OTHER REGULATORY MATTE

RATE AND OTHER REGULATORY MATTERS	9 Months Ended
	Sep. 30, 2018
Rate Matters [Line Items]
Schedule of Regulatory Assets and Liabilities [Text Block]	RATE AND OTHER REGULATORY MATTERS Rate Matters Tax Act Regulatory Proceedings The Tax Act lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the SCPSC and the NCUC have sought information from utilities under their respective jurisdictions that would disclose the impact of the Tax Act on their individual company's operations and would propose procedures for changing customer rates to reflect those impacts. In addition, the SCPSC and NCUC have issued orders that require SCE&G and PSNC Energy to track and defer such impacts arising from customer rates in 2018 as subject to refund. See Gas - SCE&G below for a discussion of related SCPSC action. For electric rates, SCE&G expects the SCPSC will take further action on this matter in 2018 but cannot determine what form that action will take. PSNC Energy has been ordered by the NCUC to (1) propose adjustments to customer rates to reflect the reduction in the federal corporate tax rate, which adjustments, if approved by the NCUC, are expected to be made effective on or before January 1, 2019; (2) continue to defer as a regulatory liability such amounts arising from customer rates in 2018; and (3) continue to defer as a regulatory liability amounts arising from excess deferred income taxes, as further described below. The NCUC order requires the regulatory liability related to items (2) and (3) be considered in PSNC Energy's next general rate case proceeding or in three years, whichever is sooner (i.e., no later than October 25, 2021). The reduction in the federal corporate income tax rate reflected in various riders for PSNC Energy will be addressed in its next annual rider proceedings. As of September 30, 2018, SCE&G has recorded approximately $60.9 million as Revenue subject to refund and approximately $3.8 million as Regulatory liabilities on the condensed consolidated balance sheet for the Company and Consolidated SCE&G, and PSNC Energy has recorded approximately $10.1 million of such deferrals within Regulatory liabilities on the condensed consolidated balance sheet for the Company. These amounts include the accrual of estimated carrying costs. In addition, as further discussed under Regulatory Assets and Regulatory Liabilities below, certain accumulated deferred income taxes contained within regulatory liabilities represent excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act. Certain of these amounts are protected under normalization regulations and will be amortized over the remaining lives of related property, and certain of these amounts will be amortized to the benefit of customers over a prescribed period as instructed by regulators. Electric - BLRA and Joint Petition On January 12, 2018, SCE&G and Dominion Energy filed with the SCPSC the Joint Petition for review and approval of a proposed business combination whereby SCANA would become a wholly-owned subsidiary of Dominion Energy. In the Joint Petition, approval of a customer benefits plan and a cost recovery plan for the Nuclear Project is also sought. Key provisions of this Joint Petition are summarized at Note 10. In September and October 2018, the SCPSC received public testimony on the Joint Petition and other Concurrent Dockets. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets regarding the merits of the Joint Petition and related issues. As noted below, the SCPSC is required by law to issue its order related to the Joint Petition no later than December 21, 2018. On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA. Act 258 requires the SCPSC to order a reduction in the portion of SCE&G's retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer’s bill to approximately 3.2% , or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On July 2 and 3, 2018, the SCPSC issued orders implementing the rate reduction required by Act 258. The rates and retroactive credits required by Act 258 were put into effect in August 2018, with the retroactive credits for the second quarter being applied in August's billing cycles. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 also alters certain provisions previously applicable under the BLRA, including redefining the standard of care required by the BLRA and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the Nuclear Project. On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented. Electric - Cost of Fuel On April 25, 2018, the SCPSC approved SCE&G’s proposal to increase the total fuel cost component of retail electric rates. Specifically, the SCPSC approved SCE&G’s increase to certain environmental, avoided capacity and DER cost components and SCE&G’s agreement to maintain its base fuel component to produce a projected under-recovered balance of approximately $1.3 million at the end of the 12-month period beginning with the first billing cycle of May 2018. This projected under-recovered balance includes the effect of offsetting fuel cost recovery with the gains realized from the settlement of certain interest rate derivatives in early 2018. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2018, projected DER program costs of approximately $29.3 million. In August 2018, the SCPSC initiated its 2019 annual review of base rates for fuel costs. A public hearing on this matter is scheduled to begin April 3, 2019. Electric - Other On April 25, 2018, the SCPSC approved SCE&G's request to recover approximately $33.0 million of costs and net lost revenues associated with DSM Programs, along with an incentive to invest in such programs. Changes in rates became effective beginning with the first billing cycle of May 2018. Gas - SCE&G On October 10, 2018, the SCPSC approved an overall decrease of approximately $19.7 million , or 4.61% , to SCE&G's natural gas rates under the terms of the RSA including the impact of the lower federal corporate tax rate resulting from the Tax Act. The SCPSC also approved revised rate schedules for natural gas service that include a rider to refund certain amounts previously collected from customers for SCE&G's income taxes. This rate adjustment and rider will become effective with the first billing cycle of November 2018. SCE&G’s natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G’s gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. SCE&G’s annual PGA hearing for the 12-month period ending July 31, 2018, is scheduled for November 8, 2018. Gas - PSNC Energy The NCUC has authorized PSNC Energy to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy files biannual applications to adjust its rates for this purpose. In 2018, the NCUC has approved those applications for the incremental annual revenue requirements, as follows: Rates Effective Incremental Increase March 1, 2018 $14.7 million September 1, 2018 $1.1 million On October 4, 2018, Dominion Energy and SCANA filed a stipulation agreement with the Public Staff of the NCUC and an intervenor in the proposed merger between the two companies. Among other things, in the event the merger closes, the stipulation agreement provides for (1) customer bill credits of $1.25 million in each of January 2019, 2020 and 2021; (2) a rate moratorium until November 1, 2021 other than for rate adjustments pursuant to the CUT, the Integrity Management Tracker and the PGA; and (3) an agreement that direct merger-related expenses will be excluded from PSNC Energy regulated expenses for ratemaking purposes. The NCUC conducted a hearing on the proposed merger in October 2018. The Company cannot predict the timing or the outcome of this matter. Regulatory Assets and Regulatory Liabilities Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises. As a result, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Except for certain unrecovered nuclear project costs and other unrecovered plant, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities. The Company Consolidated SCE&G Millions of dollars September 30, December 31, September 30, December 31, Regulatory Assets: Unrecovered Nuclear Project costs $ 4,140 $ 3,976 $ 4,140 $ 3,976 AROs and related funding 448 434 423 410 Deferred employee benefit plan costs 282 305 254 273 Deferred losses on interest rate derivatives 446 456 446 456 Other unrecovered plant 96 105 96 105 DSM Programs 57 59 57 59 Pipeline integrity management costs 67 51 9 8 Environmental remediation costs 28 30 24 25 Deferred storm damage costs 29 24 29 24 Deferred transmission operating costs 11 — 11 — Other 135 140 134 140 Total Regulatory Assets $ 5,739 $ 5,580 $ 5,623 $ 5,476 Regulatory Liabilities: Monetization of guaranty settlement $ 1,098 $ 1,095 $ 1,098 $ 1,095 Accumulated deferred income taxes 1,075 1,076 916 914 Asset removal costs 775 757 539 527 Deferred gains on interest rate derivatives 77 131 77 131 Other 15 — 5 — Total Regulatory Liabilities $ 3,040 $ 3,059 $ 2,635 $ 2,667 Regulatory assets for unrecovered Nuclear Project costs have been recorded based on such amounts not being probable of loss in accordance with the accounting guidance on abandonments, whereas the other regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under applicable GAAP for regulated operations. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by one of these regulatory agencies, including unrecovered nuclear project costs and deferred transmission operating costs that are the subject of regulatory proceedings as further discussed above and in Note 10. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts embodied in rate orders or applicable state law. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation, changes in state law, other changes in the regulatory environment or changes in accounting requirements or other adverse legislative or regulatory developments, the Company or Consolidated SCE&G could be required to write off all or a portion of its regulatory assets and liabilities. Such an event could have a material effect on the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded. Unrecovered Nuclear Project costs represents expenditures by SCE&G that have been reclassified from construction work in progress as a result of the decision to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs under the abandonment provisions of the BLRA or through other regulatory means, net of an estimated impairment loss and net of the cost of certain assets that have been or will be placed in service. See also Note 10. AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 107 years. Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. SCE&G recovers deferred pension costs through utility rates of approximately $2 million annually for electric operations, which will end in 2044, and approximately $1 million annually for gas operations, which will end in 2027. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees up to approximately 11 years. Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065. Other unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return. DSM Programs represent SCE&G's deferred costs associated with electric demand reduction programs, and such deferred costs are currently being recovered over approximately five years through an approved rate rider. Pipeline integrity management costs represent operating costs incurred to comply with federal regulatory requirements related to natural gas pipelines. PSNC Energy is recovering costs totaling $4.1 million annually through 2021. PSNC Energy is continuing to defer pipeline integrity costs, and as of September 30, 2018 costs of $44.9 million have been deferred pending future approval of rate recovery. SCE&G amortizes $1.9 million of such costs annually. Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy. SCE&G's remediation costs are expected to be recovered over periods of up to approximately 17 years, and PSNC Energy's remediation costs of $4.2 million are being recovered over a period that will end in 2021. Deferred storm damage costs represent storm restoration costs for which SCE&G expects to receive future recovery through customer rates. Deferred transmission operating costs includes deferred depreciation and property taxes associated with certain transmission assets for which SCE&G expects recovery from customers through future rates. See also Note 10. Various other regulatory assets are expected to be recovered through rates over varying periods through 2047 . Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement. The SCPSC is expected to determine how SCE&G's customers will realize the value of these proceeds in connection with its consideration of the Request by the ORS and the Joint Petition (see above and Note 10). Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act (certain of which are protected under normalization regulations and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over a prescribed period as instructed by regulators) and (ii) deferred income taxes arising from investment tax credits, offset by (iii) deferred income taxes that arise from utility operations that have not been included in customer rates (a portion of which relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 85 years). See also Note 6. Asset removal costs represent estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.
SCEG
Rate Matters [Line Items]
Schedule of Regulatory Assets and Liabilities [Text Block]	RATE AND OTHER REGULATORY MATTERS Rate Matters Tax Act Regulatory Proceedings The Tax Act lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the SCPSC and the NCUC have sought information from utilities under their respective jurisdictions that would disclose the impact of the Tax Act on their individual company's operations and would propose procedures for changing customer rates to reflect those impacts. In addition, the SCPSC and NCUC have issued orders that require SCE&G and PSNC Energy to track and defer such impacts arising from customer rates in 2018 as subject to refund. See Gas - SCE&G below for a discussion of related SCPSC action. For electric rates, SCE&G expects the SCPSC will take further action on this matter in 2018 but cannot determine what form that action will take. PSNC Energy has been ordered by the NCUC to (1) propose adjustments to customer rates to reflect the reduction in the federal corporate tax rate, which adjustments, if approved by the NCUC, are expected to be made effective on or before January 1, 2019; (2) continue to defer as a regulatory liability such amounts arising from customer rates in 2018; and (3) continue to defer as a regulatory liability amounts arising from excess deferred income taxes, as further described below. The NCUC order requires the regulatory liability related to items (2) and (3) be considered in PSNC Energy's next general rate case proceeding or in three years, whichever is sooner (i.e., no later than October 25, 2021). The reduction in the federal corporate income tax rate reflected in various riders for PSNC Energy will be addressed in its next annual rider proceedings. As of September 30, 2018, SCE&G has recorded approximately $60.9 million as Revenue subject to refund and approximately $3.8 million as Regulatory liabilities on the condensed consolidated balance sheet for the Company and Consolidated SCE&G, and PSNC Energy has recorded approximately $10.1 million of such deferrals within Regulatory liabilities on the condensed consolidated balance sheet for the Company. These amounts include the accrual of estimated carrying costs. In addition, as further discussed under Regulatory Assets and Regulatory Liabilities below, certain accumulated deferred income taxes contained within regulatory liabilities represent excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act. Certain of these amounts are protected under normalization regulations and will be amortized over the remaining lives of related property, and certain of these amounts will be amortized to the benefit of customers over a prescribed period as instructed by regulators. Electric - BLRA and Joint Petition On January 12, 2018, SCE&G and Dominion Energy filed with the SCPSC the Joint Petition for review and approval of a proposed business combination whereby SCANA would become a wholly-owned subsidiary of Dominion Energy. In the Joint Petition, approval of a customer benefits plan and a cost recovery plan for the Nuclear Project is also sought. Key provisions of this Joint Petition are summarized at Note 10. In September and October 2018, the SCPSC received public testimony on the Joint Petition and other Concurrent Dockets. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets regarding the merits of the Joint Petition and related issues. As noted below, the SCPSC is required by law to issue its order related to the Joint Petition no later than December 21, 2018. On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA. Act 258 requires the SCPSC to order a reduction in the portion of SCE&G's retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer’s bill to approximately 3.2% , or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On July 2 and 3, 2018, the SCPSC issued orders implementing the rate reduction required by Act 258. The rates and retroactive credits required by Act 258 were put into effect in August 2018, with the retroactive credits for the second quarter being applied in August's billing cycles. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 also alters certain provisions previously applicable under the BLRA, including redefining the standard of care required by the BLRA and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the Nuclear Project. On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented. Electric - Cost of Fuel On April 25, 2018, the SCPSC approved SCE&G’s proposal to increase the total fuel cost component of retail electric rates. Specifically, the SCPSC approved SCE&G’s increase to certain environmental, avoided capacity and DER cost components and SCE&G’s agreement to maintain its base fuel component to produce a projected under-recovered balance of approximately $1.3 million at the end of the 12-month period beginning with the first billing cycle of May 2018. This projected under-recovered balance includes the effect of offsetting fuel cost recovery with the gains realized from the settlement of certain interest rate derivatives in early 2018. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2018, projected DER program costs of approximately $29.3 million. In August 2018, the SCPSC initiated its 2019 annual review of base rates for fuel costs. A public hearing on this matter is scheduled to begin April 3, 2019. Electric - Other On April 25, 2018, the SCPSC approved SCE&G's request to recover approximately $33.0 million of costs and net lost revenues associated with DSM Programs, along with an incentive to invest in such programs. Changes in rates became effective beginning with the first billing cycle of May 2018. Gas - SCE&G On October 10, 2018, the SCPSC approved an overall decrease of approximately $19.7 million , or 4.61% , to SCE&G's natural gas rates under the terms of the RSA including the impact of the lower federal corporate tax rate resulting from the Tax Act. The SCPSC also approved revised rate schedules for natural gas service that include a rider to refund certain amounts previously collected from customers for SCE&G's income taxes. This rate adjustment and rider will become effective with the first billing cycle of November 2018. SCE&G’s natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G’s gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. SCE&G’s annual PGA hearing for the 12-month period ending July 31, 2018, is scheduled for November 8, 2018. Gas - PSNC Energy The NCUC has authorized PSNC Energy to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy files biannual applications to adjust its rates for this purpose. In 2018, the NCUC has approved those applications for the incremental annual revenue requirements, as follows: Rates Effective Incremental Increase March 1, 2018 $14.7 million September 1, 2018 $1.1 million On October 4, 2018, Dominion Energy and SCANA filed a stipulation agreement with the Public Staff of the NCUC and an intervenor in the proposed merger between the two companies. Among other things, in the event the merger closes, the stipulation agreement provides for (1) customer bill credits of $1.25 million in each of January 2019, 2020 and 2021; (2) a rate moratorium until November 1, 2021 other than for rate adjustments pursuant to the CUT, the Integrity Management Tracker and the PGA; and (3) an agreement that direct merger-related expenses will be excluded from PSNC Energy regulated expenses for ratemaking purposes. The NCUC conducted a hearing on the proposed merger in October 2018. The Company cannot predict the timing or the outcome of this matter. Regulatory Assets and Regulatory Liabilities Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises. As a result, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Except for certain unrecovered nuclear project costs and other unrecovered plant, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities. The Company Consolidated SCE&G Millions of dollars September 30, December 31, September 30, December 31, Regulatory Assets: Unrecovered Nuclear Project costs $ 4,140 $ 3,976 $ 4,140 $ 3,976 AROs and related funding 448 434 423 410 Deferred employee benefit plan costs 282 305 254 273 Deferred losses on interest rate derivatives 446 456 446 456 Other unrecovered plant 96 105 96 105 DSM Programs 57 59 57 59 Pipeline integrity management costs 67 51 9 8 Environmental remediation costs 28 30 24 25 Deferred storm damage costs 29 24 29 24 Deferred transmission operating costs 11 — 11 — Other 135 140 134 140 Total Regulatory Assets $ 5,739 $ 5,580 $ 5,623 $ 5,476 Regulatory Liabilities: Monetization of guaranty settlement $ 1,098 $ 1,095 $ 1,098 $ 1,095 Accumulated deferred income taxes 1,075 1,076 916 914 Asset removal costs 775 757 539 527 Deferred gains on interest rate derivatives 77 131 77 131 Other 15 — 5 — Total Regulatory Liabilities $ 3,040 $ 3,059 $ 2,635 $ 2,667 Regulatory assets for unrecovered Nuclear Project costs have been recorded based on such amounts not being probable of loss in accordance with the accounting guidance on abandonments, whereas the other regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under applicable GAAP for regulated operations. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by one of these regulatory agencies, including unrecovered nuclear project costs and deferred transmission operating costs that are the subject of regulatory proceedings as further discussed above and in Note 10. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts embodied in rate orders or applicable state law. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation, changes in state law, other changes in the regulatory environment or changes in accounting requirements or other adverse legislative or regulatory developments, the Company or Consolidated SCE&G could be required to write off all or a portion of its regulatory assets and liabilities. Such an event could have a material effect on the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded. Unrecovered Nuclear Project costs represents expenditures by SCE&G that have been reclassified from construction work in progress as a result of the decision to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs under the abandonment provisions of the BLRA or through other regulatory means, net of an estimated impairment loss and net of the cost of certain assets that have been or will be placed in service. See also Note 10. AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 107 years. Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. SCE&G recovers deferred pension costs through utility rates of approximately $2 million annually for electric operations, which will end in 2044, and approximately $1 million annually for gas operations, which will end in 2027. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees up to approximately 11 years. Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065. Other unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return. DSM Programs represent SCE&G's deferred costs associated with electric demand reduction programs, and such deferred costs are currently being recovered over approximately five years through an approved rate rider. Pipeline integrity management costs represent operating costs incurred to comply with federal regulatory requirements related to natural gas pipelines. PSNC Energy is recovering costs totaling $4.1 million annually through 2021. PSNC Energy is continuing to defer pipeline integrity costs, and as of September 30, 2018 costs of $44.9 million have been deferred pending future approval of rate recovery. SCE&G amortizes $1.9 million of such costs annually. Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy. SCE&G's remediation costs are expected to be recovered over periods of up to approximately 17 years, and PSNC Energy's remediation costs of $4.2 million are being recovered over a period that will end in 2021. Deferred storm damage costs represent storm restoration costs for which SCE&G expects to receive future recovery through customer rates. Deferred transmission operating costs includes deferred depreciation and property taxes associated with certain transmission assets for which SCE&G expects recovery from customers through future rates. See also Note 10. Various other regulatory assets are expected to be recovered through rates over varying periods through 2047 . Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement. The SCPSC is expected to determine how SCE&G's customers will realize the value of these proceeds in connection with its consideration of the Request by the ORS and the Joint Petition (see above and Note 10). Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act (certain of which are protected under normalization regulations and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over a prescribed period as instructed by regulators) and (ii) deferred income taxes arising from investment tax credits, offset by (iii) deferred income taxes that arise from utility operations that have not been included in customer rates (a portion of which relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 85 years). See also Note 6. Asset removal costs represent estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.

REVENUE RECOGNITION Notes

REVENUE RECOGNITION Notes	9 Months Ended
	Sep. 30, 2018
Entity Information [Line Items]
Revenue from Contract with Customer [Text Block]	REVENUE RECOGNITION Identifying Revenue Streams and Related Performance Obligations Operating Revenues Operating revenues arise primarily from the sale and transmission of electricity and the sale and transportation of natural gas. Electric and Gas regulated revenues consist primarily of retail sales to residential, commercial and industrial customers under various tariff rates approved by state regulatory commissions. These tariff rates generally include charges for the energy consumed and a standard basic facilities or demand charge designed to recover certain fixed costs incurred to provide service to the customer. Tariff rates also include commission-approved regulatory mechanisms in the form of adjustments or riders, such as for weather normalization, fuel and environmental cost recovery, energy conservation programs, interruptible service and real time pricing provisions, among others. Electric revenues also include wholesale sales and transmission service, primarily to municipal customers and other service providers, under contracts or tariffs approved by the FERC. Gas nonregulated revenues arise from natural gas sales at market-based rates. Such sales to residential and certain commercial customers include charges for natural gas delivered, at either variable or fixed prices, together with any applicable customer service charges, charges originating from an interstate pipeline company, and other incidental charges. The Company has determined that its gas marketing subsidiary serves as an agent for distribution services provided by a nonaffiliated company in its retail market. Accordingly, the pass-through charges to customers related to such services are not considered revenues. Sales to other commercial and to industrial customers include commodity and transportation charges for natural gas delivered at contracted rates, together with applicable fees for storage, injection, demand, and charges originating from one or more interstate pipeline companies. Performance obligations which have not been satisfied by the Company or Consolidated SCE&G relate primarily to demand or standby service for natural gas. Demand or standby charges for natural gas arise when an industrial customer reserves capacity on assets controlled by the service provider and may use that capacity to move natural gas it has acquired from other suppliers. For all periods presented, the amount of revenue recognized by the Company and Consolidated SCE&G for these charges is equal to the amount of consideration they have a right to invoice, and corresponds directly to the value transferred to the customer. As a result, amounts related to performance obligations that have not been fully satisfied are not disclosed. Contracts governing the transactions above do not have a significant financing component. Also, due to the nature of the commodities underlying these transactions, no performance obligations arise for returns, refunds or warranties. In addition, taxes billed to customers are excluded from the transaction price. Such amounts are recorded as liabilities until they are remitted to the respective taxing authority and are not included in revenues or expenses in the statements of operations. Non-Operating Revenues Non-operating revenues are derived from the sale of appliances and water heaters, as well as from contracts covering the repair of certain appliances, wiring, plumbing and similar systems and fees received for such repairs from customers not under a repair contract. In addition, the portion of fees received under asset management agreements that regulators have recognized to be incentives for the Company and Consolidated SCE&G to engage in such transactions is recorded as non-operating revenues. Revenues from sales are recorded when the appliance or water heater is delivered to the customer. Repair contract coverage fees are recorded when invoiced, generally on a monthly basis in advance of the period of coverage. Additional charges for service calls and non-covered repairs are billed and collected at the time service is rendered. Revenues from asset management agreements are recorded when the related fixed monthly amounts are due, which corresponds to timing of the value received by the customer. The point at which the customer controls the use of a purchased product, or has obtained substantially all of the benefits from repair services, corresponds to when revenues are recorded and performance obligations are fulfilled. Contract assets arising from invoicing repair contract fees in advance of the coverage period are not material. Income earned from financing sales of appliances and other products is recorded within interest income. Any performance obligations arising from returns, refunds or warranties are not material. Non-operating revenues also arise from sources unrelated to contracts with customers, such as carrying costs recorded on certain regulatory assets, gains from property sales and income from rentals and from equity method investments, among others. In 2018, such amounts include gains realized upon the settlement of certain interest rate swaps (see Note 12). Such revenues are outside the scope of revenues from contracts with customers. Non-operating revenues are further described in Note 12. Such revenues arising from contracts with customers were not material for any period presented, and accordingly, detailed disclosures regarding these revenues are not provided. Significant Judgments and Estimates Electricity and natural gas are sold and delivered to the customer for immediate consumption and the customer controls the use of, and obtains substantially all of the benefits from, the energy and related services as they are delivered. As such, the related performance obligations are satisfied over time and revenue is recognized over the same period. The Company and Consolidated SCE&G have determined that their right to consideration from a customer directly corresponds to the value of the performance completed at the date each customer invoice is rendered. As a result, the Company and Consolidated SCE&G recognize revenue in the amounts for which they have a right to invoice. This includes estimated amounts unbilled at a balance sheet date but which are to be invoiced in the normal cycle. Regulatory mechanisms exist within electric and gas tariffs or orders from regulators that result in adjustments to customer bills. These regulatory mechanisms are designed: • To recover costs related to fuel, pension, pipeline integrity and energy conservation, among others; • To recover carrying costs associated with debt-based financing; • To replace revenues lost as a result of the utility implementing DER programs and DSM Programs; and • For gas revenues, to achieve weather normalization or to decouple gas revenues from weather and other factors, such as through the WNA at SCE&G or the CUT at PSNC Energy. Recovery of deferred costs and carrying costs and the replacement of lost revenues are components of approved tariffs, and therefore, adjustments to customer bills occur as electricity or natural gas is sold and delivered to the customer. As such, the Company and Consolidated SCE&G have concluded that performance obligations related to these adjustments are not capable of being distinct from the underlying tariff based sales. Accordingly, revenues arising from these adjustments are recorded within Operating Revenues - Electric or Gas - regulated on the statements of operations, consistent with revenues from underlying tariff based sales. Adjustments for SCE&G’s WNA increase gas customer bills when weather is milder than normal and decrease gas customer bills when weather is colder than normal. These adjustments are made during the same period that the underlying natural gas is sold and delivered to the customer, and the performance obligations associated with these adjustments are not capable of being distinct from tariff based sales. Such adjustments are recorded within Operating Revenues - Gas - regulated on the statements of operations. When weather is significantly milder than normal, SCE&G limits such adjustments on a gas customer’s bill to an amount that would be added if weather were 50% milder than normal. Adjustments exceeding this limit, though still recorded as operating revenue, are deferred within regulatory assets until customers are subsequently billed for the excess with the approval of the SCPSC. PSNC Energy’s CUT is a decoupling mechanism that adjusts bills for residential and commercial customers based on per customer average consumption. When average consumption exceeds actual usage, PSNC Energy records increased revenue associated with this undercollection and defers it within regulatory assets. Likewise, when actual usage exceeds average consumption, a decrement to revenue associated with this overcollection is recorded and deferred within regulatory liabilities. PSNC Energy’s tariff based rates are adjusted semiannually, with the approval of the NCUC, to collect or refund these deferred amounts over the subsequent 12 month period. Amounts deferred for the WNA and the CUT arise under specific arrangements with regulators rather than customers. As a result, the Company and Consolidated SCE&G have concluded that these arrangements represent alternative revenue programs. Revenue from alternative revenue programs is included within Operating Revenues - Gas - regulated on the statements of operations in the month such adjustments are deferred within regulatory accounts, and is shown as Other operating revenues when disaggregated in the table below. As permitted, the Company and Consolidated SCE&G have elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues. Disaggregation of Revenues The impact of several factors on the amount, timing and uncertainty of operating revenues and cash flows can vary significantly by customer class. For electric revenues and nonregulated gas revenues, which do not have weather normalization mechanisms in place, weather and conservation measures on energy usage typically affect residential and commercial customers to a greater degree than other customer classes. For utilities, revenue requirements result in increases or decreases in tariff rates approved by regulatory bodies and often vary by customer class. Also, certain cost recovery and other mechanisms may have an uneven impact on a particular customer class depending on the underlying tariffs affected. For nonregulated gas, revenues are impacted by competitive market rates tailored to appeal to specific customer classes. The Company and Consolidated SCE&G have disaggregated operating revenues by customer class as follows: The Company Consolidated SCE&G PSNC Energy Gas-nonregulated Millions of dollars Electric Gas-regulated Gas-regulated Total Gas-regulated Three months ended September 30, 2018 Customer class: Residential $ 310 $ 25 $ 27 $ 52 $ 22 Commercial 231 19 19 38 14 Industrial 95 19 — 19 93 Other 31 6 7 13 6 Revenues from contracts with customers 667 69 53 122 135 Other operating revenues 3 — — — — Total Operating Revenues $ 670 $ 69 $ 53 $ 122 $ 135 Nine months ended September 30, 2018 Customer class: Residential $ 805 $ 145 $ 210 $ 355 $ 158 Commercial 571 80 85 165 64 Industrial 286 64 10 74 304 Other 99 13 22 35 24 Revenues from contracts with customers 1,761 302 327 629 550 Other operating revenues 9 1 1 2 — Total Operating Revenues $ 1,770 $ 303 $ 328 $ 631 $ 550 Contract Costs Costs to obtain contracts are generally expensed when incurred. In limited instances, SCE&G provides economic development grants intended to support economic growth within SCE&G’s electric service territory and defers such grants as regulatory assets on the condensed consolidated balance sheet. Whenever these grants are contingent on a customer entering into a long-term electric supply contract with SCE&G, they are considered costs to obtain that underlying contract. Such costs that exceed certain thresholds are deferred and amortized on a straight-line basis over the term of the related service contract, which generally ranges from ten to 15 years. Balances and activity related to contract costs deferred as regulatory assets were as follows: The Company and Consolidated SCE&G Millions of dollars Regulatory Assets January 1, 2018 $ 16.3 Additional costs — Amortization (1.1 ) Impairment — September 30, 2018 $ 15.2
SCEG
Entity Information [Line Items]
Revenue from Contract with Customer [Text Block]	REVENUE RECOGNITION Identifying Revenue Streams and Related Performance Obligations Operating Revenues Operating revenues arise primarily from the sale and transmission of electricity and the sale and transportation of natural gas. Electric and Gas regulated revenues consist primarily of retail sales to residential, commercial and industrial customers under various tariff rates approved by state regulatory commissions. These tariff rates generally include charges for the energy consumed and a standard basic facilities or demand charge designed to recover certain fixed costs incurred to provide service to the customer. Tariff rates also include commission-approved regulatory mechanisms in the form of adjustments or riders, such as for weather normalization, fuel and environmental cost recovery, energy conservation programs, interruptible service and real time pricing provisions, among others. Electric revenues also include wholesale sales and transmission service, primarily to municipal customers and other service providers, under contracts or tariffs approved by the FERC. Gas nonregulated revenues arise from natural gas sales at market-based rates. Such sales to residential and certain commercial customers include charges for natural gas delivered, at either variable or fixed prices, together with any applicable customer service charges, charges originating from an interstate pipeline company, and other incidental charges. The Company has determined that its gas marketing subsidiary serves as an agent for distribution services provided by a nonaffiliated company in its retail market. Accordingly, the pass-through charges to customers related to such services are not considered revenues. Sales to other commercial and to industrial customers include commodity and transportation charges for natural gas delivered at contracted rates, together with applicable fees for storage, injection, demand, and charges originating from one or more interstate pipeline companies. Performance obligations which have not been satisfied by the Company or Consolidated SCE&G relate primarily to demand or standby service for natural gas. Demand or standby charges for natural gas arise when an industrial customer reserves capacity on assets controlled by the service provider and may use that capacity to move natural gas it has acquired from other suppliers. For all periods presented, the amount of revenue recognized by the Company and Consolidated SCE&G for these charges is equal to the amount of consideration they have a right to invoice, and corresponds directly to the value transferred to the customer. As a result, amounts related to performance obligations that have not been fully satisfied are not disclosed. Contracts governing the transactions above do not have a significant financing component. Also, due to the nature of the commodities underlying these transactions, no performance obligations arise for returns, refunds or warranties. In addition, taxes billed to customers are excluded from the transaction price. Such amounts are recorded as liabilities until they are remitted to the respective taxing authority and are not included in revenues or expenses in the statements of operations. Non-Operating Revenues Non-operating revenues are derived from the sale of appliances and water heaters, as well as from contracts covering the repair of certain appliances, wiring, plumbing and similar systems and fees received for such repairs from customers not under a repair contract. In addition, the portion of fees received under asset management agreements that regulators have recognized to be incentives for the Company and Consolidated SCE&G to engage in such transactions is recorded as non-operating revenues. Revenues from sales are recorded when the appliance or water heater is delivered to the customer. Repair contract coverage fees are recorded when invoiced, generally on a monthly basis in advance of the period of coverage. Additional charges for service calls and non-covered repairs are billed and collected at the time service is rendered. Revenues from asset management agreements are recorded when the related fixed monthly amounts are due, which corresponds to timing of the value received by the customer. The point at which the customer controls the use of a purchased product, or has obtained substantially all of the benefits from repair services, corresponds to when revenues are recorded and performance obligations are fulfilled. Contract assets arising from invoicing repair contract fees in advance of the coverage period are not material. Income earned from financing sales of appliances and other products is recorded within interest income. Any performance obligations arising from returns, refunds or warranties are not material. Non-operating revenues also arise from sources unrelated to contracts with customers, such as carrying costs recorded on certain regulatory assets, gains from property sales and income from rentals and from equity method investments, among others. In 2018, such amounts include gains realized upon the settlement of certain interest rate swaps (see Note 12). Such revenues are outside the scope of revenues from contracts with customers. Non-operating revenues are further described in Note 12. Such revenues arising from contracts with customers were not material for any period presented, and accordingly, detailed disclosures regarding these revenues are not provided. Significant Judgments and Estimates Electricity and natural gas are sold and delivered to the customer for immediate consumption and the customer controls the use of, and obtains substantially all of the benefits from, the energy and related services as they are delivered. As such, the related performance obligations are satisfied over time and revenue is recognized over the same period. The Company and Consolidated SCE&G have determined that their right to consideration from a customer directly corresponds to the value of the performance completed at the date each customer invoice is rendered. As a result, the Company and Consolidated SCE&G recognize revenue in the amounts for which they have a right to invoice. This includes estimated amounts unbilled at a balance sheet date but which are to be invoiced in the normal cycle. Regulatory mechanisms exist within electric and gas tariffs or orders from regulators that result in adjustments to customer bills. These regulatory mechanisms are designed: • To recover costs related to fuel, pension, pipeline integrity and energy conservation, among others; • To recover carrying costs associated with debt-based financing; • To replace revenues lost as a result of the utility implementing DER programs and DSM Programs; and • For gas revenues, to achieve weather normalization or to decouple gas revenues from weather and other factors, such as through the WNA at SCE&G or the CUT at PSNC Energy. Recovery of deferred costs and carrying costs and the replacement of lost revenues are components of approved tariffs, and therefore, adjustments to customer bills occur as electricity or natural gas is sold and delivered to the customer. As such, the Company and Consolidated SCE&G have concluded that performance obligations related to these adjustments are not capable of being distinct from the underlying tariff based sales. Accordingly, revenues arising from these adjustments are recorded within Operating Revenues - Electric or Gas - regulated on the statements of operations, consistent with revenues from underlying tariff based sales. Adjustments for SCE&G’s WNA increase gas customer bills when weather is milder than normal and decrease gas customer bills when weather is colder than normal. These adjustments are made during the same period that the underlying natural gas is sold and delivered to the customer, and the performance obligations associated with these adjustments are not capable of being distinct from tariff based sales. Such adjustments are recorded within Operating Revenues - Gas - regulated on the statements of operations. When weather is significantly milder than normal, SCE&G limits such adjustments on a gas customer’s bill to an amount that would be added if weather were 50% milder than normal. Adjustments exceeding this limit, though still recorded as operating revenue, are deferred within regulatory assets until customers are subsequently billed for the excess with the approval of the SCPSC. PSNC Energy’s CUT is a decoupling mechanism that adjusts bills for residential and commercial customers based on per customer average consumption. When average consumption exceeds actual usage, PSNC Energy records increased revenue associated with this undercollection and defers it within regulatory assets. Likewise, when actual usage exceeds average consumption, a decrement to revenue associated with this overcollection is recorded and deferred within regulatory liabilities. PSNC Energy’s tariff based rates are adjusted semiannually, with the approval of the NCUC, to collect or refund these deferred amounts over the subsequent 12 month period. Amounts deferred for the WNA and the CUT arise under specific arrangements with regulators rather than customers. As a result, the Company and Consolidated SCE&G have concluded that these arrangements represent alternative revenue programs. Revenue from alternative revenue programs is included within Operating Revenues - Gas - regulated on the statements of operations in the month such adjustments are deferred within regulatory accounts, and is shown as Other operating revenues when disaggregated in the table below. As permitted, the Company and Consolidated SCE&G have elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues. Disaggregation of Revenues The impact of several factors on the amount, timing and uncertainty of operating revenues and cash flows can vary significantly by customer class. For electric revenues and nonregulated gas revenues, which do not have weather normalization mechanisms in place, weather and conservation measures on energy usage typically affect residential and commercial customers to a greater degree than other customer classes. For utilities, revenue requirements result in increases or decreases in tariff rates approved by regulatory bodies and often vary by customer class. Also, certain cost recovery and other mechanisms may have an uneven impact on a particular customer class depending on the underlying tariffs affected. For nonregulated gas, revenues are impacted by competitive market rates tailored to appeal to specific customer classes. The Company and Consolidated SCE&G have disaggregated operating revenues by customer class as follows: The Company Consolidated SCE&G PSNC Energy Gas-nonregulated Millions of dollars Electric Gas-regulated Gas-regulated Total Gas-regulated Three months ended September 30, 2018 Customer class: Residential $ 310 $ 25 $ 27 $ 52 $ 22 Commercial 231 19 19 38 14 Industrial 95 19 — 19 93 Other 31 6 7 13 6 Revenues from contracts with customers 667 69 53 122 135 Other operating revenues 3 — — — — Total Operating Revenues $ 670 $ 69 $ 53 $ 122 $ 135 Nine months ended September 30, 2018 Customer class: Residential $ 805 $ 145 $ 210 $ 355 $ 158 Commercial 571 80 85 165 64 Industrial 286 64 10 74 304 Other 99 13 22 35 24 Revenues from contracts with customers 1,761 302 327 629 550 Other operating revenues 9 1 1 2 — Total Operating Revenues $ 1,770 $ 303 $ 328 $ 631 $ 550 Contract Costs Costs to obtain contracts are generally expensed when incurred. In limited instances, SCE&G provides economic development grants intended to support economic growth within SCE&G’s electric service territory and defers such grants as regulatory assets on the condensed consolidated balance sheet. Whenever these grants are contingent on a customer entering into a long-term electric supply contract with SCE&G, they are considered costs to obtain that underlying contract. Such costs that exceed certain thresholds are deferred and amortized on a straight-line basis over the term of the related service contract, which generally ranges from ten to 15 years. Balances and activity related to contract costs deferred as regulatory assets were as follows: The Company and Consolidated SCE&G Millions of dollars Regulatory Assets January 1, 2018 $ 16.3 Additional costs — Amortization (1.1 ) Impairment — September 30, 2018 $ 15.2

COMMON EQUITY

COMMON EQUITY	9 Months Ended
	Sep. 30, 2018
Common Equity Note [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	COMMON EQUITY SCANA shareholders approved the Merger Agreement at a special meeting on July 31, 2018. Certain regulatory approvals must be obtained and other conditions must be met before the merger may be consummated. SCANA had 200 million shares of common stock authorized as of September 30, 2018 and December 31, 2017. Authorized shares of SCE&G common stock were 50 million as of September 30, 2018 and December 31, 2017. Authorized shares of SCE&G preferred stock were 20 million , of which 1,000 shares, no par value, were issued and outstanding as of September 30, 2018 and December 31, 2017. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA. In June 2018, SCANA made an equity contribution to GENCO of $20 million . SCANA’s articles of incorporation do not limit the dividends that may be paid on its common stock, and the articles of incorporation of each of SCANA's subsidiaries contain no such limitations on their respective common stock. SCANA has agreed to obtain the consent of Dominion Energy, which consent cannot be unreasonably withheld, prior to making dividend payments to shareholders greater than $0.6125 per share for any quarter while the Merger Agreement is pending. SCE&G’s bond indenture under which it issues First Mortgage Bonds contains provisions that could limit the payment of cash dividends on its common stock. SCE&G's bond indenture permits the payment of dividends on SCE&G's common stock only either (1) out of its Surplus (as defined in the bond indenture) or (2) in case there is no Surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, the Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At September 30, 2018 and 2017, retained earnings of approximately $99.9 million and $83.9 million , respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock. PSNC Energy’s note purchase and debenture purchase agreements contain provisions that could limit the payment of cash distributions, including dividends, on PSNC Energy's common stock. These agreements generally limit the sum of distributions to an amount that does not exceed $30 million plus 85% of Consolidated Net Income (as therein defined) accumulated after December 31, 2008 plus the net proceeds of issuances by PSNC Energy of equity or convertible debt securities (as therein defined). As of September 30, 2018, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million.
SCEG
Common Equity Note [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	Authorized shares of SCE&G common stock were 50 million as of September 30, 2018 and December 31, 2017. Authorized shares of SCE&G preferred stock were 20 million , of which 1,000 shares, no par value, were issued and outstanding as of September 30, 2018 and December 31, 2017. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA. In June 2018, SCANA made an equity contribution to GENCO of $20 million . SCANA’s articles of incorporation do not limit the dividends that may be paid on its common stock, and the articles of incorporation of each of SCANA's subsidiaries contain no such limitations on their respective common stock. SCANA has agreed to obtain the consent of Dominion Energy, which consent cannot be unreasonably withheld, prior to making dividend payments to shareholders greater than $0.6125 per share for any quarter while the Merger Agreement is pending. SCE&G’s bond indenture under which it issues First Mortgage Bonds contains provisions that could limit the payment of cash dividends on its common stock. SCE&G's bond indenture permits the payment of dividends on SCE&G's common stock only either (1) out of its Surplus (as defined in the bond indenture) or (2) in case there is no Surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, the Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At September 30, 2018 and 2017, retained earnings of approximately $99.9 million and $83.9 million , respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock. PSNC Energy’s note purchase and debenture purchase agreements contain provisions that could limit the payment of cash distributions, including dividends, on PSNC Energy's common stock. These agreements generally limit the sum of distributions to an amount that does not exceed $30 million plus 85% of Consolidated Net Income (as therein defined) accumulated after December 31, 2008 plus the net proceeds of issuances by PSNC Energy of equity or convertible debt securities (as therein defined). As of September 30, 2018, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million.

LONG-TERM AND SHORT-TERM DEBT

LONG-TERM AND SHORT-TERM DEBT	9 Months Ended
	Sep. 30, 2018
Debt Instrument [Line Items]
Long-term Debt [Text Block]	LONG-TERM DEBT AND LIQUIDITY Long-term Debt In June 2018, GENCO redeemed at maturity $160 million of 6.06% secured notes. The repayment was funded using a combination of utility money pool borrowings and an equity contribution from SCANA. In June 2018, PSNC Energy issued $100 million of 4.33% senior notes due June 15, 2028. In June 2017, PSNC Energy issued $150 million of 4.18 senior notes due June 30, 2047. Proceeds from each of these sales were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes. In August 2018, SCE&G issued $300 million of 3.50% first mortgage bonds due August 15, 2021, and $400 million of 4.25% first mortgage bonds due August 15, 2028. Proceeds from these sales were used on September 28, 2018, to repay prior to maturity $250 million of 5.25% first mortgage bonds and $300 million of 6.50% first mortgage bonds, each due November 1, 2018. In addition, proceeds were used for general corporate purposes. Substantially all electric utility plant is pledged as collateral in connection with long-term debt. Liquidity Credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. Committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Committed LOC, outstanding LOC advances, commercial paper, and LOC-supported letter of credit obligations were as follows: September 30, 2018 (Millions of dollars) Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: + Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Three-year, expiring December 2018 200.0 — 200.0 — Total committed long-term 2,000.0 400.0 1,400.0 200.0 LOC advances 40.0 40.0 — — Weighted average interest rate 3.78 % — — Outstanding commercial paper (270 or fewer days) 314.2 3.7 173.2 137.3 Weighted average interest rate 3.20 % 3.21 % 3.13 % Letters of credit supported by LOC 37.6 37.3 0.3 — Available $ 1,608.2 $ 319.0 $ 1,226.5 $ 62.7 December 31, 2017 (Millions of dollars) Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Three-year, expiring December 2018 200.0 — 200.0 — Total committed long-term 2,000.0 400.0 1,400.0 200.0 Outstanding commercial paper (270 or fewer days) 350.3 — 251.6 98.7 Weighted average interest rate — 1.92 % 1.93 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,646.4 $ 397.0 $ 1,148.1 $ 101.3 In March 2018, SCE&G borrowed $100 million under the five-year credit agreement expiring December 2020. The proceeds of this draw were deposited with a natural gas supplier to provide contractually required credit support. In September 2018, SCE&G obtained a surety bond to replace this credit support and, as a result, the deposit was returned and this draw was repaid in September 2018. Also, SCANA obtained letters of credit in favor of natural gas suppliers to provide contractually required credit support. In September 2018, SCANA borrowed $40 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at September 30, 2018 was 3.78% , and this draw is classified as long-term debt. Proceeds from the draw were deposited with two natural gas suppliers to provide contractually required credit support, and this deposit is reflected within other assets on the condensed consolidated balance sheet. SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2019, which reflects a one-year authorization period rather than the two-year period SCE&G and GENCO had requested. In granting the authorization for a shorter period, FERC cited several ongoing proceedings involving the ORS and Act 258, as well as the pending merger between SCANA and Dominion Energy, that could affect SCE&G's and GENCO's circumstances. Were adverse developments to occur with respect to uncertainties highlighted elsewhere, the ability of SCE&G or GENCO to secure renewal of this short-term borrowing authority may be adversely impacted. Proceeds received under or arising from the monetization of the Toshiba Settlement in 2017 have been utilized to repay maturing commercial paper balances, which short-term borrowings had been incurred primarily for the construction of Unit 2 and Unit 3 prior to the decision to stop their construction (see Note 10). Should the SCPSC or a court direct that these proceeds be refunded to customers in the near-term, or direct that such funds be escrowed or otherwise made unavailable to SCE&G, it is anticipated that SCE&G would issue commercial paper, draw on its credit facilities or issue long-term debt or the Company would issue equity to fund such requirement. However, if the SCPSC were to rule in favor of the ORS in response to the Request that SCE&G suspend collections from customers of amounts previously authorized under the BLRA, if the temporary rate reduction arising from the implementation of Act 258 were to remain in effect following the order of the SCPSC arising from the Joint Petition, or were other actions of the SCPSC or others taken in order to significantly restrict SCE&G’s access to revenues or impose additional adverse refund obligations on SCE&G, the Company’s and Consolidated SCE&G's assessments regarding the recoverability of all or a portion of the remaining balance of unrecovered Nuclear Project costs would be adversely impacted (see Note 2 and Note 10). Further, the recognition of significant additional impairment losses with respect to unrecovered Nuclear Project costs could increase the Company’s and Consolidated SCE&G’s debt to total capitalization to a level which may limit their ability to borrow under their commercial paper programs or under their credit facilities. Borrowing costs for long-term debt issuances could also be impacted. Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019. Consolidated SCE&G participates in a utility money pool with SCANA and another regulated subsidiary of SCANA. Money pool borrowings and investments bear interest at short-term market rates. For the three and nine months ended September 30, 2018, Consolidated SCE&G recorded interest income from money pool transactions of $1.1 million and $2.5 million , respectively, and for the same periods Consolidated SCE&G recorded interest expense from money pool transactions of $1.1 million and $2.5 million , respectively. Interest income and interest expense for periods in 2017 were not significant. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $195 million and investments due from an affiliate of $177 million at September 30, 2018. At December 31, 2017 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $37 million and investments due from an affiliate of $28 million . For each period presented, money pool borrowings were made by Fuel Company and GENCO, and money pool investments were made by SCE&G. On its condensed consolidated balance sheet, Consolidated SCE&G includes money pool borrowings within Affiliated payables and money pool investments within Affiliated companies receivables.
SCEG
Debt Instrument [Line Items]
Long-term Debt [Text Block]	LONG-TERM DEBT AND LIQUIDITY Long-term Debt In June 2018, GENCO redeemed at maturity $160 million of 6.06% secured notes. The repayment was funded using a combination of utility money pool borrowings and an equity contribution from SCANA. In June 2018, PSNC Energy issued $100 million of 4.33% senior notes due June 15, 2028. In June 2017, PSNC Energy issued $150 million of 4.18 senior notes due June 30, 2047. Proceeds from each of these sales were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes. In August 2018, SCE&G issued $300 million of 3.50% first mortgage bonds due August 15, 2021, and $400 million of 4.25% first mortgage bonds due August 15, 2028. Proceeds from these sales were used on September 28, 2018, to repay prior to maturity $250 million of 5.25% first mortgage bonds and $300 million of 6.50% first mortgage bonds, each due November 1, 2018. In addition, proceeds were used for general corporate purposes. Substantially all electric utility plant is pledged as collateral in connection with long-term debt. Liquidity Credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. Committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Committed LOC, outstanding LOC advances, commercial paper, and LOC-supported letter of credit obligations were as follows: September 30, 2018 (Millions of dollars) Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: + Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Three-year, expiring December 2018 200.0 — 200.0 — Total committed long-term 2,000.0 400.0 1,400.0 200.0 LOC advances 40.0 40.0 — — Weighted average interest rate 3.78 % — — Outstanding commercial paper (270 or fewer days) 314.2 3.7 173.2 137.3 Weighted average interest rate 3.20 % 3.21 % 3.13 % Letters of credit supported by LOC 37.6 37.3 0.3 — Available $ 1,608.2 $ 319.0 $ 1,226.5 $ 62.7 December 31, 2017 (Millions of dollars) Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Three-year, expiring December 2018 200.0 — 200.0 — Total committed long-term 2,000.0 400.0 1,400.0 200.0 Outstanding commercial paper (270 or fewer days) 350.3 — 251.6 98.7 Weighted average interest rate — 1.92 % 1.93 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,646.4 $ 397.0 $ 1,148.1 $ 101.3 In March 2018, SCE&G borrowed $100 million under the five-year credit agreement expiring December 2020. The proceeds of this draw were deposited with a natural gas supplier to provide contractually required credit support. In September 2018, SCE&G obtained a surety bond to replace this credit support and, as a result, the deposit was returned and this draw was repaid in September 2018. Also, SCANA obtained letters of credit in favor of natural gas suppliers to provide contractually required credit support. In September 2018, SCANA borrowed $40 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at September 30, 2018 was 3.78% , and this draw is classified as long-term debt. Proceeds from the draw were deposited with two natural gas suppliers to provide contractually required credit support, and this deposit is reflected within other assets on the condensed consolidated balance sheet. SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2019, which reflects a one-year authorization period rather than the two-year period SCE&G and GENCO had requested. In granting the authorization for a shorter period, FERC cited several ongoing proceedings involving the ORS and Act 258, as well as the pending merger between SCANA and Dominion Energy, that could affect SCE&G's and GENCO's circumstances. Were adverse developments to occur with respect to uncertainties highlighted elsewhere, the ability of SCE&G or GENCO to secure renewal of this short-term borrowing authority may be adversely impacted. Proceeds received under or arising from the monetization of the Toshiba Settlement in 2017 have been utilized to repay maturing commercial paper balances, which short-term borrowings had been incurred primarily for the construction of Unit 2 and Unit 3 prior to the decision to stop their construction (see Note 10). Should the SCPSC or a court direct that these proceeds be refunded to customers in the near-term, or direct that such funds be escrowed or otherwise made unavailable to SCE&G, it is anticipated that SCE&G would issue commercial paper, draw on its credit facilities or issue long-term debt or the Company would issue equity to fund such requirement. However, if the SCPSC were to rule in favor of the ORS in response to the Request that SCE&G suspend collections from customers of amounts previously authorized under the BLRA, if the temporary rate reduction arising from the implementation of Act 258 were to remain in effect following the order of the SCPSC arising from the Joint Petition, or were other actions of the SCPSC or others taken in order to significantly restrict SCE&G’s access to revenues or impose additional adverse refund obligations on SCE&G, the Company’s and Consolidated SCE&G's assessments regarding the recoverability of all or a portion of the remaining balance of unrecovered Nuclear Project costs would be adversely impacted (see Note 2 and Note 10). Further, the recognition of significant additional impairment losses with respect to unrecovered Nuclear Project costs could increase the Company’s and Consolidated SCE&G’s debt to total capitalization to a level which may limit their ability to borrow under their commercial paper programs or under their credit facilities. Borrowing costs for long-term debt issuances could also be impacted. Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019. Consolidated SCE&G participates in a utility money pool with SCANA and another regulated subsidiary of SCANA. Money pool borrowings and investments bear interest at short-term market rates. For the three and nine months ended September 30, 2018, Consolidated SCE&G recorded interest income from money pool transactions of $1.1 million and $2.5 million , respectively, and for the same periods Consolidated SCE&G recorded interest expense from money pool transactions of $1.1 million and $2.5 million , respectively. Interest income and interest expense for periods in 2017 were not significant. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $195 million and investments due from an affiliate of $177 million at September 30, 2018. At December 31, 2017 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $37 million and investments due from an affiliate of $28 million . For each period presented, money pool borrowings were made by Fuel Company and GENCO, and money pool investments were made by SCE&G. On its condensed consolidated balance sheet, Consolidated SCE&G includes money pool borrowings within Affiliated payables and money pool investments within Affiliated companies receivables.

INCOME TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2018
income tax [Line Items]
Income Tax Disclosure [Text Block]	6. INCOME TAXES The Company files consolidated federal income tax returns which include Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns. The Company’s federal returns through 2007 are closed by statute. In addition, federal returns for 2008 and 2009 are closed except to the extent of the examination of amended return claims discussed below. Federal returns for years 2010 through 2017 are currently being examined as noted below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010. During 2013 and 2014, the Company amended certain of its income tax returns for 2008 through 2012 to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). The Company also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016, 2017 and 2018, the Company claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the Nuclear Project, in its 2015, 2016 and 2017 income tax returns. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. The IRS examined the claims in the amended 2008-2012 returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2017 income tax returns. These IRC Section 174 income tax deductions and IRC Section 41 credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are recorded as unrecognized tax benefits in the financial statements. Also, following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G claimed an abandonment loss deduction under IRC Section 165 on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, would instead be expected to be deductible in 2017 under IRC Section 165. The abandonment loss deduction is also considered an uncertain tax position; however, under relevant accounting guidance, no estimated unrecognized tax benefits were recorded as of September 30, 2018. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, credits, and certain unrecognized state tax benefits. As of September 30, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $98 million ( $19 million net of the impact of state deductions on federal returns, net of NOL and credit carryforwards, and net of receivables related to the uncertain tax positions). If recognized, $98 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. These unrecognized tax benefits are not expected to increase significantly within the next 12 months. It is also reasonably possible that these unrecognized tax benefits may decrease by $11 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through September 30, 2018 (see Note 10). In connection with the research and experimentation deduction and credit claims reflected on the 2015, 2016 and 2017 income tax returns and under the provisions of an SCPSC order, the Company and Consolidated SCE&G recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, with the expectation that these deferred costs and related interest thereon would be recoverable through customer rates in future years. However, an impairment loss with respect to such deferred regulatory asset was recorded in 2017 (see Note 10). Also under the provisions of an SCPSC order, estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 and 2016 income tax returns was deferred as a regulatory asset and was expected to be recoverable through customer rates in future years. An impairment loss with respect to these deferred amounts was also recorded as of December 31, 2017 (see Note 10). Otherwise, the Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses. Related to the unrecognized tax benefits noted above, the Company and Consolidated SCE&G accrued interest expense of $6.8 million and interest income of $ 1.4 million during 2018. Amounts recorded for such interest income and interest expense were mostly deferred within regulatory assets during 2017, and such deferred amounts were subsequently included within the impairment loss recorded by the Company and Consolidated SCE&G in 2017. Penalties were not material in either period presented. In December of 2017, the Tax Act was enacted to lower the federal statutory corporate tax rate from 35% to 21% . The rate change resulted in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory corporate tax rate as of December 31, 2017. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in deferred income tax balances within regulatory liabilities. As of September 30, 2018, the amortization of amounts arising from remeasurement have not significantly affected the Company’s or Consolidated SCE&G’s effective tax rate for 2018 due to such amortization being deferred pending implementation of decisions by regulators prescribing how the benefits of such excess deferred tax amounts will be realized by customers. The Company filed a superseding 2017 consolidated income tax return on October 10, 2018. Adjustments to deferred income taxes resulting from the completion and filing of this return will be recorded in the fourth quarter of 2018 but are not expected to have a material impact on the Company’s or Consolidated SCE&G's financial position, results of operations, or cash flows. The State of North Carolina lowered its corporate income tax rate to 3.0% in 2017 and 2.5% effective January 1, 2019. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows.
SCEG
income tax [Line Items]
Income Tax Disclosure [Text Block]	6. INCOME TAXES The Company files consolidated federal income tax returns which include Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns. The Company’s federal returns through 2007 are closed by statute. In addition, federal returns for 2008 and 2009 are closed except to the extent of the examination of amended return claims discussed below. Federal returns for years 2010 through 2017 are currently being examined as noted below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010. During 2013 and 2014, the Company amended certain of its income tax returns for 2008 through 2012 to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). The Company also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016, 2017 and 2018, the Company claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the Nuclear Project, in its 2015, 2016 and 2017 income tax returns. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. The IRS examined the claims in the amended 2008-2012 returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2017 income tax returns. These IRC Section 174 income tax deductions and IRC Section 41 credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are recorded as unrecognized tax benefits in the financial statements. Also, following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G claimed an abandonment loss deduction under IRC Section 165 on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, would instead be expected to be deductible in 2017 under IRC Section 165. The abandonment loss deduction is also considered an uncertain tax position; however, under relevant accounting guidance, no estimated unrecognized tax benefits were recorded as of September 30, 2018. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, credits, and certain unrecognized state tax benefits. As of September 30, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $98 million ( $19 million net of the impact of state deductions on federal returns, net of NOL and credit carryforwards, and net of receivables related to the uncertain tax positions). If recognized, $98 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. These unrecognized tax benefits are not expected to increase significantly within the next 12 months. It is also reasonably possible that these unrecognized tax benefits may decrease by $11 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through September 30, 2018 (see Note 10). In connection with the research and experimentation deduction and credit claims reflected on the 2015, 2016 and 2017 income tax returns and under the provisions of an SCPSC order, the Company and Consolidated SCE&G recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, with the expectation that these deferred costs and related interest thereon would be recoverable through customer rates in future years. However, an impairment loss with respect to such deferred regulatory asset was recorded in 2017 (see Note 10). Also under the provisions of an SCPSC order, estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 and 2016 income tax returns was deferred as a regulatory asset and was expected to be recoverable through customer rates in future years. An impairment loss with respect to these deferred amounts was also recorded as of December 31, 2017 (see Note 10). Otherwise, the Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses. Related to the unrecognized tax benefits noted above, the Company and Consolidated SCE&G accrued interest expense of $6.8 million and interest income of $ 1.4 million during 2018. Amounts recorded for such interest income and interest expense were mostly deferred within regulatory assets during 2017, and such deferred amounts were subsequently included within the impairment loss recorded by the Company and Consolidated SCE&G in 2017. Penalties were not material in either period presented. In December of 2017, the Tax Act was enacted to lower the federal statutory corporate tax rate from 35% to 21% . The rate change resulted in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory corporate tax rate as of December 31, 2017. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in deferred income tax balances within regulatory liabilities. As of September 30, 2018, the amortization of amounts arising from remeasurement have not significantly affected the Company’s or Consolidated SCE&G’s effective tax rate for 2018 due to such amortization being deferred pending implementation of decisions by regulators prescribing how the benefits of such excess deferred tax amounts will be realized by customers. The Company filed a superseding 2017 consolidated income tax return on October 10, 2018. Adjustments to deferred income taxes resulting from the completion and filing of this return will be recorded in the fourth quarter of 2018 but are not expected to have a material impact on the Company’s or Consolidated SCE&G's financial position, results of operations, or cash flows. The State of North Carolina lowered its corporate income tax rate to 3.0% in 2017 and 2.5% effective January 1, 2019. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	9 Months Ended
	Sep. 30, 2018
Derivative [Line Items]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	7. DERIVATIVE FINANCIAL INSTRUMENTS Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. Policies and procedures, and in some cases risk limits, are established to control the level of market, credit, liquidity and operational and administrative risks. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions. Commodity Derivatives The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions. Cash settlements of commodity derivatives are classified as operating activities in the consolidated statements of cash flows. PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes. Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit. As an accommodation to certain customers, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives. These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes. Interest Rate Swaps Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances. In cases in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense. Forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt. Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and its nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 have not been designated for accounting purposes as cash flow hedges, and fair value changes and settlement amounts related to them have been recorded as regulatory assets and liabilities. Settlement losses on swaps generally have been amortized over the lives of subsequent debt issuances, and gains have been amortized to interest expense or have been applied as otherwise directed by the SCPSC. See Note 2 and Note 12 regarding the settlement gains realized in the first quarter of 2018. Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes. Quantitative Disclosures Related to Derivatives The Company was party to natural gas derivative contracts outstanding in the following quantities: Commodity and Other Energy Management Contracts (in MMBTU) Hedge designation Gas Distribution Gas Marketing Total As of September 30, 2018 Commodity contracts 7,050,000 16,856,000 23,906,000 Energy management contracts (a) — 40,949,232 40,949,232 Total (a) 7,050,000 57,805,232 64,855,232 As of December 31, 2017 Commodity contracts 6,430,000 13,433,000 19,863,000 Energy management contracts (a) — 41,856,890 41,856,890 Total (a) 6,430,000 55,289,890 61,719,890 (a) Includes amounts related to basis swap contracts totaling 9,396,000 MMBTU in 2018 and 2,582,000 MMBTU in 2017. The aggregate notional amounts of the interest rate swaps were as follows: Interest Rate Swaps The Company Consolidated SCE&G Millions of dollars September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 Designated as hedging instruments $ 106.8 $ 111.2 $ 36.4 $ 36.4 Not designated as hedging instruments 35.0 735.0 35.0 735.0 The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown. Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of September 30, 2018 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 2 — $ 1 Other deferred credits and other liabilities — 16 — 6 Commodity contracts Prepayments $ 1 — — — Total $ 1 $ 18 — $ 7 Not designated as hedging instruments Interest rate contracts Other deferred credits and other liabilities — $ 2 — $ 2 Commodity contracts Prepayments $ 1 — — — Energy management contracts Prepayments 1 — — — Other current assets 1 — — — Other current liabilities — 2 — — Total $ 3 $ 4 — $ 2 The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of December 31, 2017 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 3 — $ 1 Other deferred credits and other liabilities — 24 — 9 Commodity contracts Prepayments — 2 — — Other current assets — 1 — — Total — $ 30 — $ 10 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 54 $ 1 $ 54 $ 1 Other deferred credits and other liabilities — 4 — 4 Commodity contracts Other current assets 1 — — — Energy management contracts Prepayments — 1 — — Other current assets 3 — — — Other deferred debits and other assets 1 — — — Derivative financial instruments — 2 — — Total $ 59 $ 8 $ 54 $ 5 The effect of derivative instruments on the consolidated statements of income is as follows: Derivatives in Cash Flow Hedging Relationships The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts (Loss) Reclassified from Deferred Accounts into Income Millions of dollars 2018 2017 Location 2018 2017 Three Months Ended September 30, Interest rate contracts — — Interest expense — — Nine Months Ended September 30, Interest rate contracts $ 2 $ (1 ) Interest expense $ (1 ) $ (1 ) The Company: Gain (Loss) Recognized in OCI, net of tax Gain (Loss) Reclassified from AOCI into Income, net of tax Millions of dollars 2018 2017 Location 2018 2017 Three Months Ended September 30, Interest rate contracts $ 1 — Interest expense $ (3 ) $ (2 ) Total $ 1 — $ (3 ) $ (2 ) Nine Months Ended September 30, Interest rate contracts $ 3 $ (1 ) Interest expense $ (7 ) $ (6 ) Commodity contracts 2 (4 ) Gas purchased for resale (2 ) 2 Total $ 5 $ (5 ) $ (9 ) $ (4 ) As of September 30, 2018, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $0.5 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.9 million as an increase to interest expense. Reclassifications related to commodity and energy management contracts are not expected to be significant. As of September 30, 2018, all of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2021. As of September 30, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $1.0 million as an increase to interest expense. Hedge Ineffectiveness For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented. Derivatives Not designated as Hedging Instruments The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars 2018 2017 Location 2018 2017 Three Months Ended September 30, Interest rate contracts $ 1 $ (6 ) Interest Expense $ (1 ) $ (1 ) Nine Months Ended September 30, Interest rate contracts $ 66 $ (30 ) Interest Expense $ (2 ) $ (2 ) Other Income 115 — As of September 30, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $2.8 million as an increase to interest expense. Credit Risk Considerations Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral. Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 20.8 $ 33.7 $ 8.7 $ 14.7 Fair value of collateral already posted 22.3 28.9 8.7 10.1 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ (1.5 ) $ 4.8 — $ 4.6 in Net Asset Position Aggregate fair value of derivatives in net asset position — $ 53.5 — $ 53.5 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — $ 53.5 — $ 53.5 In addition, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of $0.3 million related to $2.9 million in commodity derivatives that are in a net asset position at September 30, 2018, compared to letters of credit in the amount of $1.2 million related to derivatives of $4.0 million at December 31, 2017, if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting of derivative assets and derivative liabilities follows: Derivative Assets The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of September 30, 2018 Gross Amounts of Recognized Assets — $ 2 $ 2 $ 4 — Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position — 2 2 4 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 2 $ 2 $ 4 — Balance sheet location Prepayments $ 3 — Other current assets 1 — Total $ 4 — As of December 31, 2017 Gross Amounts of Recognized Assets $ 54 $ 1 $ 4 $ 59 $ 54 Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position 54 1 4 59 54 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 54 $ 1 $ 4 $ 59 $ 54 Balance sheet location Other current assets $ 58 $ 54 Other deferred debits and other assets 1 — Total $ 59 $ 54 Derivative Liabilities Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of September 30, 2018 Gross Amounts of Recognized Liabilities $ 20 — $ 2 $ 22 $ 9 Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position 20 — 2 22 9 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (21 ) — (1 ) (22 ) (9 ) Net Amount $ (1 ) — $ 1 — — Balance sheet location Derivative financial instruments $ 2 $ 1 Other current liabilities 2 — Other deferred credits and other liabilities 18 8 Total $ 22 $ 9 As of December 31, 2017 Gross Amounts of Recognized Liabilities $ 32 $ 3 $ 3 $ 38 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 32 3 2 37 15 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted 28 — (1 ) 27 — Net Amount $ 60 $ 3 $ 1 $ 64 $ 15 Balance sheet location Other current assets $ 2 — Derivative financial instruments 7 $ 2 Other deferred credits and other liabilities 28 13 Total $ 37 $ 15
SCEG
Derivative [Line Items]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	7. DERIVATIVE FINANCIAL INSTRUMENTS Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. Policies and procedures, and in some cases risk limits, are established to control the level of market, credit, liquidity and operational and administrative risks. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions. Commodity Derivatives The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions. Cash settlements of commodity derivatives are classified as operating activities in the consolidated statements of cash flows. PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes. Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit. As an accommodation to certain customers, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives. These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes. Interest Rate Swaps Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances. In cases in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense. Forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt. Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and its nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 have not been designated for accounting purposes as cash flow hedges, and fair value changes and settlement amounts related to them have been recorded as regulatory assets and liabilities. Settlement losses on swaps generally have been amortized over the lives of subsequent debt issuances, and gains have been amortized to interest expense or have been applied as otherwise directed by the SCPSC. See Note 2 and Note 12 regarding the settlement gains realized in the first quarter of 2018. Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes. Quantitative Disclosures Related to Derivatives The Company was party to natural gas derivative contracts outstanding in the following quantities: Commodity and Other Energy Management Contracts (in MMBTU) Hedge designation Gas Distribution Gas Marketing Total As of September 30, 2018 Commodity contracts 7,050,000 16,856,000 23,906,000 Energy management contracts (a) — 40,949,232 40,949,232 Total (a) 7,050,000 57,805,232 64,855,232 As of December 31, 2017 Commodity contracts 6,430,000 13,433,000 19,863,000 Energy management contracts (a) — 41,856,890 41,856,890 Total (a) 6,430,000 55,289,890 61,719,890 (a) Includes amounts related to basis swap contracts totaling 9,396,000 MMBTU in 2018 and 2,582,000 MMBTU in 2017. The aggregate notional amounts of the interest rate swaps were as follows: Interest Rate Swaps The Company Consolidated SCE&G Millions of dollars September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 Designated as hedging instruments $ 106.8 $ 111.2 $ 36.4 $ 36.4 Not designated as hedging instruments 35.0 735.0 35.0 735.0 The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown. Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of September 30, 2018 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 2 — $ 1 Other deferred credits and other liabilities — 16 — 6 Commodity contracts Prepayments $ 1 — — — Total $ 1 $ 18 — $ 7 Not designated as hedging instruments Interest rate contracts Other deferred credits and other liabilities — $ 2 — $ 2 Commodity contracts Prepayments $ 1 — — — Energy management contracts Prepayments 1 — — — Other current assets 1 — — — Other current liabilities — 2 — — Total $ 3 $ 4 — $ 2 The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of December 31, 2017 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 3 — $ 1 Other deferred credits and other liabilities — 24 — 9 Commodity contracts Prepayments — 2 — — Other current assets — 1 — — Total — $ 30 — $ 10 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 54 $ 1 $ 54 $ 1 Other deferred credits and other liabilities — 4 — 4 Commodity contracts Other current assets 1 — — — Energy management contracts Prepayments — 1 — — Other current assets 3 — — — Other deferred debits and other assets 1 — — — Derivative financial instruments — 2 — — Total $ 59 $ 8 $ 54 $ 5 The effect of derivative instruments on the consolidated statements of income is as follows: Derivatives in Cash Flow Hedging Relationships The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts (Loss) Reclassified from Deferred Accounts into Income Millions of dollars 2018 2017 Location 2018 2017 Three Months Ended September 30, Interest rate contracts — — Interest expense — — Nine Months Ended September 30, Interest rate contracts $ 2 $ (1 ) Interest expense $ (1 ) $ (1 ) The Company: Gain (Loss) Recognized in OCI, net of tax Gain (Loss) Reclassified from AOCI into Income, net of tax Millions of dollars 2018 2017 Location 2018 2017 Three Months Ended September 30, Interest rate contracts $ 1 — Interest expense $ (3 ) $ (2 ) Total $ 1 — $ (3 ) $ (2 ) Nine Months Ended September 30, Interest rate contracts $ 3 $ (1 ) Interest expense $ (7 ) $ (6 ) Commodity contracts 2 (4 ) Gas purchased for resale (2 ) 2 Total $ 5 $ (5 ) $ (9 ) $ (4 ) As of September 30, 2018, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $0.5 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.9 million as an increase to interest expense. Reclassifications related to commodity and energy management contracts are not expected to be significant. As of September 30, 2018, all of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2021. As of September 30, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $1.0 million as an increase to interest expense. Hedge Ineffectiveness For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented. Derivatives Not designated as Hedging Instruments The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars 2018 2017 Location 2018 2017 Three Months Ended September 30, Interest rate contracts $ 1 $ (6 ) Interest Expense $ (1 ) $ (1 ) Nine Months Ended September 30, Interest rate contracts $ 66 $ (30 ) Interest Expense $ (2 ) $ (2 ) Other Income 115 — As of September 30, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $2.8 million as an increase to interest expense. Credit Risk Considerations Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral. Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 20.8 $ 33.7 $ 8.7 $ 14.7 Fair value of collateral already posted 22.3 28.9 8.7 10.1 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ (1.5 ) $ 4.8 — $ 4.6 in Net Asset Position Aggregate fair value of derivatives in net asset position — $ 53.5 — $ 53.5 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — $ 53.5 — $ 53.5 In addition, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of $0.3 million related to $2.9 million in commodity derivatives that are in a net asset position at September 30, 2018, compared to letters of credit in the amount of $1.2 million related to derivatives of $4.0 million at December 31, 2017, if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting of derivative assets and derivative liabilities follows: Derivative Assets The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of September 30, 2018 Gross Amounts of Recognized Assets — $ 2 $ 2 $ 4 — Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position — 2 2 4 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 2 $ 2 $ 4 — Balance sheet location Prepayments $ 3 — Other current assets 1 — Total $ 4 — As of December 31, 2017 Gross Amounts of Recognized Assets $ 54 $ 1 $ 4 $ 59 $ 54 Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position 54 1 4 59 54 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 54 $ 1 $ 4 $ 59 $ 54 Balance sheet location Other current assets $ 58 $ 54 Other deferred debits and other assets 1 — Total $ 59 $ 54 Derivative Liabilities Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of September 30, 2018 Gross Amounts of Recognized Liabilities $ 20 — $ 2 $ 22 $ 9 Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position 20 — 2 22 9 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (21 ) — (1 ) (22 ) (9 ) Net Amount $ (1 ) — $ 1 — — Balance sheet location Derivative financial instruments $ 2 $ 1 Other current liabilities 2 — Other deferred credits and other liabilities 18 8 Total $ 22 $ 9 As of December 31, 2017 Gross Amounts of Recognized Liabilities $ 32 $ 3 $ 3 $ 38 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 32 3 2 37 15 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted 28 — (1 ) 27 — Net Amount $ 60 $ 3 $ 1 $ 64 $ 15 Balance sheet location Other current assets $ 2 — Derivative financial instruments 7 $ 2 Other deferred credits and other liabilities 28 13 Total $ 37 $ 15

FAIR VALUE MEASUREMENTS, INCLUD

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES	9 Months Ended
	Sep. 30, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosures [Text Block]	8. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES The Company and Consolidated SCE&G value available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, on which the securities are actively traded or are open-ended mutual funds registered with the SEC and maintain a stable NAV and are invested in government money market agreements or fully collateralized repurchase agreements. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: As of September 30, 2018 As of December 31, 2017 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 2 Level 1 Level 2 Level 1 Level 2 Assets: Available for sale securities $ 15 — — $ 119 — $ 100 — Held to maturity securities — $ 6 — — $ 6 — — Interest rate contracts — — — — 54 — $ 54 Commodity contracts 2 — — 1 — — — Energy management contracts — 2 — — 4 — — Liabilities: Interest rate contracts — 20 $ 9 — 32 — 15 Commodity contracts — — — 2 1 — — Energy management contracts — 4 — 1 4 — — The Company and Consolidated SCE&G had no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during either period presented. Financial instruments for which the carrying amount may not equal estimated fair value were as follows: Long-Term Debt September 30, 2018 December 31, 2017 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,753.3 $ 6,980.8 $ 6,632.9 $ 7,399.7 Consolidated SCE&G 5,145.2 5,295.2 5,163.3 5,790.3 Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be considered prudent. Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.
SCEG
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosures [Text Block]	8. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES The Company and Consolidated SCE&G value available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, on which the securities are actively traded or are open-ended mutual funds registered with the SEC and maintain a stable NAV and are invested in government money market agreements or fully collateralized repurchase agreements. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: As of September 30, 2018 As of December 31, 2017 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 2 Level 1 Level 2 Level 1 Level 2 Assets: Available for sale securities $ 15 — — $ 119 — $ 100 — Held to maturity securities — $ 6 — — $ 6 — — Interest rate contracts — — — — 54 — $ 54 Commodity contracts 2 — — 1 — — — Energy management contracts — 2 — — 4 — — Liabilities: Interest rate contracts — 20 $ 9 — 32 — 15 Commodity contracts — — — 2 1 — — Energy management contracts — 4 — 1 4 — — The Company and Consolidated SCE&G had no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during either period presented. Financial instruments for which the carrying amount may not equal estimated fair value were as follows: Long-Term Debt September 30, 2018 December 31, 2017 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,753.3 $ 6,980.8 $ 6,632.9 $ 7,399.7 Consolidated SCE&G 5,145.2 5,295.2 5,163.3 5,790.3 Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be considered prudent. Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	9 Months Ended
	Sep. 30, 2018
Pension and Other Postretirement Benefit Plans
Pension and Other Postretirement Benefits Disclosure [Text Block]	9. EMPLOYEE BENEFIT PLANS Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2018 2017 Three months ended September 30, Service cost $ 5.9 $ 5.7 $ 1.1 $ 1.0 Interest cost 8.5 9.2 2.2 2.8 Expected return on assets (14.0 ) (13.4 ) — — Prior service cost amortization 0.1 0.4 — — Amortization of actuarial (gains) losses 3.7 4.4 (0.5 ) — Net periodic benefit cost $ 4.2 $ 6.3 $ 2.8 $ 3.8 Nine months ended September 30, Service cost $ 15.8 $ 16.3 $ 3.4 $ 3.4 Interest cost 25.6 28.0 7.6 8.6 Expected return on assets (42.6 ) (41.0 ) — — Prior service cost amortization 0.4 1.2 — — Amortization of actuarial losses 9.6 12.2 0.6 0.8 Net periodic benefit cost $ 8.8 $ 16.7 $ 11.6 $ 12.8 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2018 2017 Three months ended September 30, Service cost $ 4.8 $ 4.8 $ 0.9 $ 0.8 Interest cost 7.2 7.8 1.7 2.3 Expected return on assets (11.8 ) (11.4 ) — — Prior service cost amortization 0.1 0.3 — — Amortization of actuarial (gains) losses 3.1 3.7 (0.4 ) — Net periodic benefit cost $ 3.4 $ 5.2 $ 2.2 $ 3.1 Nine months ended September 30, Service cost $ 12.9 $ 13.6 $ 2.7 $ 2.8 Interest cost 21.6 24.0 6.0 7.1 Expected return on assets (36.0 ) (35.0 ) — — Prior service cost amortization 0.3 1.0 — — Amortization of actuarial losses 8.1 10.4 0.5 0.6 Net periodic benefit cost $ 6.9 $ 14.0 $ 9.2 $ 10.5 No significant contribution to the pension trust is expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. PSNC Energy recovers pension costs through cost of service rat
SCEG
Pension and Other Postretirement Benefit Plans
Pension and Other Postretirement Benefits Disclosure [Text Block]	9. EMPLOYEE BENEFIT PLANS Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2018 2017 Three months ended September 30, Service cost $ 5.9 $ 5.7 $ 1.1 $ 1.0 Interest cost 8.5 9.2 2.2 2.8 Expected return on assets (14.0 ) (13.4 ) — — Prior service cost amortization 0.1 0.4 — — Amortization of actuarial (gains) losses 3.7 4.4 (0.5 ) — Net periodic benefit cost $ 4.2 $ 6.3 $ 2.8 $ 3.8 Nine months ended September 30, Service cost $ 15.8 $ 16.3 $ 3.4 $ 3.4 Interest cost 25.6 28.0 7.6 8.6 Expected return on assets (42.6 ) (41.0 ) — — Prior service cost amortization 0.4 1.2 — — Amortization of actuarial losses 9.6 12.2 0.6 0.8 Net periodic benefit cost $ 8.8 $ 16.7 $ 11.6 $ 12.8 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2018 2017 Three months ended September 30, Service cost $ 4.8 $ 4.8 $ 0.9 $ 0.8 Interest cost 7.2 7.8 1.7 2.3 Expected return on assets (11.8 ) (11.4 ) — — Prior service cost amortization 0.1 0.3 — — Amortization of actuarial (gains) losses 3.1 3.7 (0.4 ) — Net periodic benefit cost $ 3.4 $ 5.2 $ 2.2 $ 3.1 Nine months ended September 30, Service cost $ 12.9 $ 13.6 $ 2.7 $ 2.8 Interest cost 21.6 24.0 6.0 7.1 Expected return on assets (36.0 ) (35.0 ) — — Prior service cost amortization 0.3 1.0 — — Amortization of actuarial losses 8.1 10.4 0.5 0.6 Net periodic benefit cost $ 6.9 $ 14.0 $ 9.2 $ 10.5 No significant contribution to the pension trust is expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. PSNC Energy recovers pension costs through cost of service rat

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	6 Months Ended	9 Months Ended
	Jun. 30, 2018	Sep. 30, 2018
Statement [Line Items]
Commitments and Contingencies Disclosure [Text Block]	COMMITMENTS AND CONTINGENCIES	Abandoned Nuclear Project SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. Various difficulties were encountered which affected the ability of the Consortium to adhere to established budgets and construction schedules for the Nuclear Project and which, in light of Santee Cooper's decision to suspend construction of the Nuclear Project, led to the Company's decision on July 31, 2017 to stop the construction and seek cost recovery under the abandonment provisions of the BLRA. These difficulties and other developments occurring prior to the bankruptcy filing by WEC and WECTEC and other matters are described in Note 10 to the consolidated financial statements included in the Company's and Consolidated SCE&G's combined Form 10-K for the year ended December 31, 2017. Significant developments and continuing contingencies and uncertainties regarding the abandoned Nuclear Project subsequent to December 31, 2017 are discussed below. EPC Contract and BLRA Matters Contractor Bankruptcy Proceedings and Related Uncertainties On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the Nuclear Project and similar units being built for an unaffiliated company as a material factor that caused WEC and WECTEC to seek protection under the bankruptcy laws. As part of such filing, WEC and WECTEC publicly announced their inability to complete Unit 2 and Unit 3 under the terms of the EPC Contract. On September 1, 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of WEC and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by the Consortium of the EPC Contract, and assert against WEC and WECTEC any and all claims that are based thereon or that may be related thereto. These claims were sold to Citibank on September 27, 2017 as part of a monetization transaction discussed below. Notwithstanding the sale of the claims, SCE&G and Santee Cooper remain responsible for any claims that may be made by WEC and WECTEC against them relating to the EPC Contract. WEC’s Reorganization Plan was confirmed by the Bankruptcy Court on March 28, 2018, and became effective August 1, 2018. In connection with the effectiveness of the Reorganization Plan, the EPC Contract was deemed rejected. Initially, WEC had projected that its Reorganization Plan would pay in full or nearly in full its pre-petition trade creditors, including several of the WEC Subcontractors which have alleged non-payment by the Consortium for amounts owed for work performed on the Nuclear Project and have filed liens on property in Fairfield County, South Carolina, where Unit 2 and Unit 3 were to be located (Unit 2/3 Property). SCE&G is contesting approximately $290 million of filed liens in Fairfield County. Most of these asserted liens are “pre-petition” claims that relate to work performed by WEC Subcontractors before the WEC bankruptcy, although some of them are “post-petition” claims arising from work performed after the WEC bankruptcy. WEC has indicated that some unsecured creditors have sought or may seek amounts beyond what WEC allocated when it submitted the Reorganization Plan. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the Reorganization Plan allocated by WEC, it is possible that the Reorganization Plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant. See also discussion below regarding limitations with respect to SCE&G’s pre-petition lien obligations arising from its monetization of the Toshiba Settlement. SCE&G and Santee Cooper are responsible for amounts owed to WEC for valid work performed by WEC Subcontractors on the Nuclear Project after the WEC bankruptcy filing (i.e., post-petition) until termination of the IAA (the IAA Period). While SCE&G and Santee Cooper funded amounts to WEC for such IAA Period obligations on a weekly basis, SCE&G and Santee Cooper undertook a reconciliation to ensure that amounts advanced to WEC for such purposes while the IAA was in effect were paid to WEC Subcontractors. That reconciliation remains ongoing. In the WEC bankruptcy proceeding, deadlines were established for creditors of WEC (including the WEC Subcontractors on the Nuclear Project) to assert the amounts owed to such creditors prior to the WEC bankruptcy filing and during the IAA Period. Many of the WEC Subcontractors have filed such claims. SCE&G does not believe that the claims asserted related to the IAA Period will exceed the amounts previously funded for the currently asserted IAA-related claims, whether relating to claims already paid or those remaining to be paid. SCE&G intends to oppose any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the IAA. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof. Further, some WEC Subcontractors who have made claims against WEC in the bankruptcy proceeding also filed against SCE&G and Santee Cooper in South Carolina state court for damages. The WEC Subcontractor claims in South Carolina state court include common law claims for pre-petition work, IAA Period work, and work after the termination of the IAA. Many of these claimants have also asserted construction liens against the Nuclear Project site. SCE&G also intends to oppose these claims and liens. With respect to claims of WEC Subcontractors during the IAA Period, SCE&G believes there were sufficient amounts previously funded during the IAA Period to pay such validly asserted claims. With respect to the WEC Subcontractor claims which relate to other periods, SCE&G understands that such claims will be paid pursuant to WEC’s confirmed Reorganization Plan. SCE&G further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, SCE&G believes that the WEC Subcontractors may be paid substantially (and potentially in full) from WEC. While SCE&G cannot be assured that it will not have any exposure on account of unpaid WEC Subcontractor claims (which SCE&G is presently disputing), SCE&G believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof. Toshiba Settlement and Subsequent Monetization Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC. In 2015 Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. In satisfaction of such guaranty obligations, on July 27, 2017, the Toshiba Settlement was executed under which Toshiba was to make periodic settlement payments beginning in October 2017 in the total amount of approximately $2.2 billion ( $1.2 billion for SCE&G’s 55% share), subject to certain offsets for payments by WEC in bankruptcy that would have the effect of satisfying the liens discussed above and below. In September and October 2017, proceeds totaling approximately $1.997 billion were received in full satisfaction of the Toshiba Settlement ( $1.098 billion for SCE&G's 55% share). The proceeds were obtained through the receipt of a payment from Toshiba and a payment from Citibank arising from its purchase of all other scheduled payments, including amounts related to the contractor liens discussed below. The purchase agreement with Citibank provides that SCE&G and Santee Cooper (each according to its pro rata share) would indemnify Citibank for its losses arising from misrepresentations or covenant defaults under the purchase agreement. SCE&G and Santee Cooper also assigned their claims under the WEC bankruptcy process to Citibank, and agreed to use commercially reasonable efforts to cooperate with Citibank and provide reasonable support necessary for its enforcement of those claims. The proceeds received under or arising from the monetization of the Toshiba Settlement are recorded as a regulatory liability on the accompanying condensed consolidated balance sheets, as the net value of the proceeds will be utilized to benefit SCE&G's customers in a manner to be determined by the SCPSC. As described above, several WEC Subcontractors have filed liens against the Unit 2/3 Property, which SCE&G is contesting. Payments under the Toshiba Settlement are subject to reduction if WEC pays WEC Subcontractors holding pre-petition liens directly. Under these circumstances, SCE&G and Santee Cooper, each in its pro rata share, would be required to make Citibank whole for the reduction. On January 2, 2018, the purchase agreement with Citibank was amended to limit the amount that SCE&G and Santee Cooper could be required to reimburse Citibank for valid subcontractor and vendor pre-petition liens to $60 million ( $33 million for SCE&G's 55% share). Regulatory, Political and Legal Developments In September 2017, the Company was served with a subpoena issued by the United States Attorney’s Office for the District of South Carolina seeking documents relating to the Nuclear Project. The subpoena requires the Company to produce a broad range of documents related to the project. Also, SLED is conducting a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. In October 2017, the staff of the SEC's Division of Enforcement also issued a subpoena for documents related to an investigation they are conducting related to the Nuclear Project. These investigations are ongoing, and the Company and Consolidated SCE&G intend to fully cooperate with them. Also in connection with the abandonment of the Nuclear Project, various state and local governmental authorities have attempted and may further attempt to challenge, reverse or revoke previously-approved tax or economic development incentives, benefits or exemptions and have attempted and may further attempt to apply such actions retroactively. No assurance can be given as to the timing or outcome of these matters. See Claims and Litigation for a description of specific challenges. On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, and in reliance on the opinion from the Office of Attorney General, the ORS filed the Request seeking an order from the SCPSC directing SCE&G to immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS, which the ORS believes should have been disclosed, that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections. On October 17, 2017, the ORS filed a motion with the SCPSC to amend the Request, in which motion the ORS asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. See Claims and Litigation herein for additional discussions regarding regarding the constitutionality of the BLRA. On December 20, 2017, the SCPSC denied a motion by SCE&G to dismiss the Request. Parties who have intervened in the Request or who filed a letter in support of it include the state's Governor, Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, Santee Cooper, the SCEUC, certain large industrial customers, and several environmental groups. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets, including the Request, regarding the merits of the Joint Petition and related issues. This schedule was established in response to legislation described below. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the outcome of this matter. See also Note 2. In 2017, special committees of the South Carolina General Assembly, both in the House of Representatives and in the Senate, conducted public hearings regarding the Company's decision to abandon the Nuclear Project. Several legislative proposals adverse to the Company and Consolidated SCE&G resulted from the work of these committees, two of which became law in 2018 and are described below. On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA. Act 258 requires the SCPSC to order a reduction in the portion of SCE&G's retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer’s bill to approximately 3.2% , or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On July 2 and 3, 2018, the SCPSC issued orders implementing the temporary rate reduction required by Act 258. The resulting new rates and retroactive credits required by Act 258 were put into effect in August 2018, with the retroactive credits for the second quarter being applied in August's billing cycles. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 alters certain provisions previously applicable under the BLRA, including redefining the standard of care required by the BLRA and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the Nuclear Project. On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented. Proposals to Resolve Outstanding Issues On November 16, 2017, SCE&G announced for public consideration a proposal to resolve outstanding issues relating to the Nuclear Project. Under the proposal, SCE&G electric customers were to receive a 3.5% electric rate reduction, the addition of an existing 540-MW natural gas fired power plant by SCE&G with the acquisition cost borne by SCANA shareholders, and the addition of approximately 100-MW of large scale solar energy by SCE&G. The proposal also provided for the recovery of the nuclear construction costs (net of the proceeds of the Toshiba Settlement not utilized for satisfaction of project liens) over 50 years. While SCE&G’s proposal was not formally submitted for regulatory approval at that time, discussions with key stakeholders over the ensuing weeks indicated that SCE&G's proposal would not be sufficient to resolve the outstanding issues. On January 2, 2018, SCANA entered into the Merger Agreement with Dominion Energy, and on January 12, 2018, SCE&G and Dominion Energy filed the Joint Petition requesting SCPSC approval of the merger or a finding that either the merger is in the public interest or that there is an absence of harm arising from the merger. In this petition, the parties committed to providing an up-front, one time rate credit to SCE&G's electric customers totaling approximately $1.3 billion within 90 days of the merger's closing, providing at least a 5% reduction in customer bills (later adjusted to approximately 7% in light of the effects of the Tax Act), shortening the amortization period for costs related to the Nuclear Project to 20 years, forgoing recovery of approximately $1.7 billion in costs related to the Nuclear Project, and purchasing an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers. On October 25, 2018, in response to the desire of various parties to the Concurrent Dockets for an alternative that would further reduce customer bills, Dominion Energy filed with the SCPSC the Alternative Customer Benefits Plan (Alternative Plan). The testimony filed by Dominion Energy in connection with the Alternative Plan indicates that customers would receive refunds totaling approximately $1.91 billion with approximately $1.0 billion being refunded evenly over 20 years and approximately $880 million credited to customers over approximately ten years instead of the up-front, one time rate credit of $1.3 billion originally proposed in the Joint Petition. In addition, such testimony indicates that approximately $2.3 billion in costs related to the Nuclear Project would not be recovered in connection with the Alternative Plan, instead of the $1.7 billion originally proposed. The parties to the Joint Petition estimate that these changes would result in customer bill reductions of approximately 14% (including the effects of the Tax Act). The Alternative Plan also contemplates the purchase of an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers. The ORS has filed direct and rebuttal testimony and a pre-hearing brief related to the Concurrent Dockets. In these filings, the ORS has proposed (ORS Plan) that the SCPSC reduce SCE&G's electric rates during the 12 months following the effective date of its order by approximately $561 million compared to rates that would otherwise be in effect when the temporary rate reduction under Act 258 expires. This proposal includes reductions due to assumed merger synergies, the use of an ROE of 9.1% rather than 10.25% (which proposed ROE would be applied to a smaller rate base after all adjustments specified by the ORS), the ORS calculation of savings from the Tax Act (which exceeds SCE&G's calculation), the refund of amounts deferred as subject to refund that arise from the Tax Act and other adjustments. After 12 months (after amounts subject to refund have been returned to customers), the ORS proposes that SCE&G's electric rates be modified to an amount that would be approximately $528 million lower annually compared to rates that would otherwise be in effect when the temporary rate reduction under Act 258 expires. On October 25, 2018, in testimony filed in connection with the Concurrent Dockets, a representative of Dominion Energy noted that (1) the ORS Plan, if adopted, would be devastating not only to the proposed merger but also to SCE&G's future and to the interests of SCE&G's customers and the state of South Carolina in reliable electric service at just and reasonable rates and (2) there is currently pending litigation in the South Carolina state courts in which the judge has indicated that he is considering issuing an order that would violate the "no change in law" provision of the Merger Agreement, and that if such an order were issued or the ORS Plan is adopted, the merger would be unable to close. On October 26, 2018, Santee Cooper filed a pre-hearing brief with respect to the Joint Petition. In its filing, Santee Cooper requested that the SCPSC not approve a merger between SCANA and Dominion Energy as being in the public interest unless SCANA and Dominion Energy commit to creating a fund of approximately $351 million to mitigate the financial impact of the abandonment of the Nuclear Project on Santee Cooper's wholesale and retail customers. Santee Cooper proposes that the cost of creating such a fund should not be recoverable from SCE&G's customers. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets regarding the merits of the Joint Petition and related issues, and as noted above, pursuant to S. 954 the SCPSC is required to issue an order related to the Joint Petition no later than December 21, 2018. No assurance can be given as to the timing or outcome of efforts to consummate the Merger Agreement or to obtain approval of the Joint Petition. On May 9, 2018, SCE&G completed its purchase of CEC, the existing 540-MW natural gas fired power plant referred to above, for approximately $180 million . As disclosed in Note 10 to the Company's and Consolidated SCE&G's Form 10-K for December 31, 2017, an impairment loss recorded in the fourth quarter of 2017 included $180 million related to SCE&G's commitment to not seek recovery from customers for the acquisition cost of this natural gas fired power plant, and accordingly, this amount was recorded as a reduction to unrecovered Nuclear Project costs within regulatory assets on the Company's and Consolidated SCE&G's consolidated balance sheets at December 31, 2017. As such, the Company's and Consolidated SCE&G's condensed consolidated balance sheet as of September 30, 2018 reflect the cost for CEC within Utility Plant in Service, and the $180 million impairment initially recorded as unrecovered Nuclear Project costs within regulatory assets is now reflected within Accumulated Depreciation and Amortization, which results in the carrying value of CEC being entirely written off. SCE&G’s commitment to not seek recovery from customers for the acquisition cost of CEC was one element of certain broader rate mitigation proposals contained within the Joint Petition and the Alternative Plan. Assuming that the SCPSC approves either of the mitigating proposals as outlined in the Joint Petition or approves the Alternative Plan, SCE&G will not seek recovery of CEC acquisition costs. Impairment Considerations At September 30, 2018, SCE&G estimated that revised rates collections previously approved under the BLRA totaled approximately $445 million annually. SCE&G estimates that such revised rates collections for 2018 would be reduced by approximately $279 million if Act 258 remains in effect and is implemented through December 21, 2018, which is the expected pendency of the SCPSC proceeding with respect to the Joint Petition. New rates are expected to be ordered by the SCPSC in connection with its order on the Joint Petition, which order is to be issued no later than December 21, 2018. On a cumulative basis, at September 30, 2018, SCE&G estimated that revised rates collections previously approved under the BLRA totaled approximately $2.1 billion , which amount reflects the impacts of Act 258. For each of the quarters ended June 30, 2018, September 30, 2018 and December 31, 2018, SCANA's Board of Directors declared a dividend of $0.1237 per share, which represents an approximately 80% reduction from the $0.6125 per share paid on SCANA’s common stock for the first quarter of 2018. This reduction corresponds to the portion of the dividend attributable to SCE&G's electric operations and serves to partially mitigate the liquidity impacts arising from the reduced revenues and cash flows resulting from the implementation of Act 258. Under the current regulatory construct in South Carolina, pursuant to the BLRA or through other means, the ability of SCE&G to recover costs incurred in connection with Unit 2 and Unit 3, and a reasonable return on them, will be subject to review and approval by the SCPSC. In light of the contentious nature of activity involving the General Assembly and other officials and the Request being considered by the SCPSC that could result in the suspension of all rates currently being collected under the BLRA, as well as the return of such amounts previously collected, there is significant uncertainty as to SCE&G’s ultimate ability to recover its costs of Unit 2 and Unit 3 and a return on them from its customers. See also Claims and Litigation herein for additional discussion regarding the constitutionality of the BLRA. SCE&G continues to contest the specific challenges described above. However, based on the consideration of those challenges, and particularly in light of SCE&G's proposed solution announced on November 16, 2017 and details in the Joint Petition filed by SCE&G and Dominion Energy with the SCPSC on January 12, 2018, the Company and Consolidated SCE&G determined that a disallowance of recovery of part of the cost of the abandoned Nuclear Project is both probable and reasonably estimable under applicable accounting guidance. In addition, the Company and Consolidated SCE&G determined that full recovery of certain other related costs deferred within regulatory assets is less than probable. As a result, in 2017 the Company and Consolidated SCE&G recognized a pre-tax impairment loss totaling $1.118 billion ( $690 million net of tax). Also, in the first quarter of 2018, the Company and Consolidated SCE&G recognized an additional pre-tax impairment loss of approximately $3.6 million ( $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. It is reasonably possible that a change in estimated impairment loss could occur in the near term and could be material; however, all such changes cannot be reasonably estimated. The impairment loss recorded in 2017 reflects impacts similar to those that would have resulted had the proposed solution announced on November 16, 2017 been implemented. If the merger benefits and cost recovery plan outlined in the Joint Petition are implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $1.7 billion (approximately $1.3 billion net of tax) would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $813 million recorded within regulatory assets, the write-off of unrecovered Nuclear Project costs of approximately $86 million recorded within Utility Plant, and the recording of additional liabilities for customer refunds totaling approximately $1.875 billion, net of approximately $1.065 billion , which amount represents the monetization of guaranty settlement recorded within regulatory liabilities less amounts that may be required to satisfy contractor liens. If the Alternative Plan were implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $2.3 billion (approximately $1.7 billion net of tax) would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $1.368 billion recorded within regulatory assets, the write-off of unrecovered Nuclear Project costs of approximately $86 million recorded within Utility Plant, and the recording of additional liabilities for customer refunds of approximately $880 million. In addition, the Alternative Plan provides for the refunding of the existing regulatory liability associated with the monetization of guaranty settlement over 20 years less amounts that may be required to satisfy contractor liens. If (i) the SCPSC does not approve the Joint Petition or the Alternative Plan and instead approves the Request by the ORS; (ii) the BLRA is found to be unconstitutional; or (iii) the General Assembly further amends or revokes the BLRA or approves other legislation with a similar effect, the Company and Consolidated SCE&G may be required to record an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $5.0 billion (approximately $3.7 billion net of tax). This additional impairment loss would result from the write-off of approximately $3.960 billion in regulatory assets (comprised of remaining unrecovered Nuclear Project costs of $4.140 billion offset by $180 million in previously impaired costs related to CEC, which would result from the proposals put forward in the Joint Petition or the Alternative Plan not being approved by the SCPSC) and the refund of revised rates collections under the BLRA described above of approximately $2.1 billion (comprised of the revised rates collections on a cumulative basis as of September 30, 2018 and reflective of the impacts of Act 258), net of approximately $1.065 billion, which amount represents the monetization of guaranty settlement recorded within regulatory liabilities less amounts that may be required to satisfy contractor liens. The Company and Consolidated SCE&G do not currently anticipate that any amounts collected prior to April 1, 2018, will be subject to refund (other than amounts arising from the effects of the Tax Act); however, no assurance can be given as to the outcome of this matter. See Claims and Litigation herein for additional discussion regarding the constitutionality of the BLRA. At September 30, 2018, the Company and Consolidated SCE&G included considerations of the impact of Act 258 in the evaluation as to their ability to recover the remaining Nuclear Project costs and a reasonable return on those costs. Because Act 258 explicitly provides for an experimental rate that is temporary and does not disallow any of the costs currently deferred as a regulatory asset, and because the experimental rate is to be replaced by rates that the SCPSC is to determine and order no later than December 21, 2018, the Company and Consolidated SCE&G have concluded that additional impairment charges related to unrecovered Nuclear Project costs are not probable, and the recording of such charges would not be appropriate, at this time. However, if a disallowance were ordered or the rates under Act 258 were made other than temporary by the SCPSC in the Joint Petition proceeding, the Company and Consolidated SCE&G would reevaluate this conclusion. Were the rates under Act 258 made other than temporary following the SCPSC's final decision on the Joint Petition, and without consideration of any other factors that may be embodied in such an order, an additional pre-tax impairment charge totaling approximately $1.7 billion may be required. In addition to the matters above, in the Joint Petition, the Company and Consolidated SCE&G proposed to remove from BLRA capital costs their investment in transmission assets that have been or will be placed in service and have not been abandoned. As of September 30, 2018, such investment in these assets total approximately $376 million (approximately $365 million within utility plant, net and approximately $11 million within regulatory assets, which amount represents certain deferred operating costs). The Company and Consolidated SCE&G believe that this investment represents assets that are or will be used to
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Commitments and Contingencies Disclosure [Text Block]	COMMITMENTS AND CONTINGENCIES	Abandoned Nuclear Project SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. Various difficulties were encountered which affected the ability of the Consortium to adhere to established budgets and construction schedules for the Nuclear Project and which, in light of Santee Cooper's decision to suspend construction of the Nuclear Project, led to the Company's decision on July 31, 2017 to stop the construction and seek cost recovery under the abandonment provisions of the BLRA. These difficulties and other developments occurring prior to the bankruptcy filing by WEC and WECTEC and other matters are described in Note 10 to the consolidated financial statements included in the Company's and Consolidated SCE&G's combined Form 10-K for the year ended December 31, 2017. Significant developments and continuing contingencies and uncertainties regarding the abandoned Nuclear Project subsequent to December 31, 2017 are discussed below. EPC Contract and BLRA Matters Contractor Bankruptcy Proceedings and Related Uncertainties On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the Nuclear Project and similar units being built for an unaffiliated company as a material factor that caused WEC and WECTEC to seek protection under the bankruptcy laws. As part of such filing, WEC and WECTEC publicly announced their inability to complete Unit 2 and Unit 3 under the terms of the EPC Contract. On September 1, 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of WEC and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by the Consortium of the EPC Contract, and assert against WEC and WECTEC any and all claims that are based thereon or that may be related thereto. These claims were sold to Citibank on September 27, 2017 as part of a monetization transaction discussed below. Notwithstanding the sale of the claims, SCE&G and Santee Cooper remain responsible for any claims that may be made by WEC and WECTEC against them relating to the EPC Contract. WEC’s Reorganization Plan was confirmed by the Bankruptcy Court on March 28, 2018, and became effective August 1, 2018. In connection with the effectiveness of the Reorganization Plan, the EPC Contract was deemed rejected. Initially, WEC had projected that its Reorganization Plan would pay in full or nearly in full its pre-petition trade creditors, including several of the WEC Subcontractors which have alleged non-payment by the Consortium for amounts owed for work performed on the Nuclear Project and have filed liens on property in Fairfield County, South Carolina, where Unit 2 and Unit 3 were to be located (Unit 2/3 Property). SCE&G is contesting approximately $290 million of filed liens in Fairfield County. Most of these asserted liens are “pre-petition” claims that relate to work performed by WEC Subcontractors before the WEC bankruptcy, although some of them are “post-petition” claims arising from work performed after the WEC bankruptcy. WEC has indicated that some unsecured creditors have sought or may seek amounts beyond what WEC allocated when it submitted the Reorganization Plan. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the Reorganization Plan allocated by WEC, it is possible that the Reorganization Plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant. See also discussion below regarding limitations with respect to SCE&G’s pre-petition lien obligations arising from its monetization of the Toshiba Settlement. SCE&G and Santee Cooper are responsible for amounts owed to WEC for valid work performed by WEC Subcontractors on the Nuclear Project after the WEC bankruptcy filing (i.e., post-petition) until termination of the IAA (the IAA Period). While SCE&G and Santee Cooper funded amounts to WEC for such IAA Period obligations on a weekly basis, SCE&G and Santee Cooper undertook a reconciliation to ensure that amounts advanced to WEC for such purposes while the IAA was in effect were paid to WEC Subcontractors. That reconciliation remains ongoing. In the WEC bankruptcy proceeding, deadlines were established for creditors of WEC (including the WEC Subcontractors on the Nuclear Project) to assert the amounts owed to such creditors prior to the WEC bankruptcy filing and during the IAA Period. Many of the WEC Subcontractors have filed such claims. SCE&G does not believe that the claims asserted related to the IAA Period will exceed the amounts previously funded for the currently asserted IAA-related claims, whether relating to claims already paid or those remaining to be paid. SCE&G intends to oppose any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the IAA. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof. Further, some WEC Subcontractors who have made claims against WEC in the bankruptcy proceeding also filed against SCE&G and Santee Cooper in South Carolina state court for damages. The WEC Subcontractor claims in South Carolina state court include common law claims for pre-petition work, IAA Period work, and work after the termination of the IAA. Many of these claimants have also asserted construction liens against the Nuclear Project site. SCE&G also intends to oppose these claims and liens. With respect to claims of WEC Subcontractors during the IAA Period, SCE&G believes there were sufficient amounts previously funded during the IAA Period to pay such validly asserted claims. With respect to the WEC Subcontractor claims which relate to other periods, SCE&G understands that such claims will be paid pursuant to WEC’s confirmed Reorganization Plan. SCE&G further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, SCE&G believes that the WEC Subcontractors may be paid substantially (and potentially in full) from WEC. While SCE&G cannot be assured that it will not have any exposure on account of unpaid WEC Subcontractor claims (which SCE&G is presently disputing), SCE&G believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof. Toshiba Settlement and Subsequent Monetization Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC. In 2015 Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. In satisfaction of such guaranty obligations, on July 27, 2017, the Toshiba Settlement was executed under which Toshiba was to make periodic settlement payments beginning in October 2017 in the total amount of approximately $2.2 billion ( $1.2 billion for SCE&G’s 55% share), subject to certain offsets for payments by WEC in bankruptcy that would have the effect of satisfying the liens discussed above and below. In September and October 2017, proceeds totaling approximately $1.997 billion were received in full satisfaction of the Toshiba Settlement ( $1.098 billion for SCE&G's 55% share). The proceeds were obtained through the receipt of a payment from Toshiba and a payment from Citibank arising from its purchase of all other scheduled payments, including amounts related to the contractor liens discussed below. The purchase agreement with Citibank provides that SCE&G and Santee Cooper (each according to its pro rata share) would indemnify Citibank for its losses arising from misrepresentations or covenant defaults under the purchase agreement. SCE&G and Santee Cooper also assigned their claims under the WEC bankruptcy process to Citibank, and agreed to use commercially reasonable efforts to cooperate with Citibank and provide reasonable support necessary for its enforcement of those claims. The proceeds received under or arising from the monetization of the Toshiba Settlement are recorded as a regulatory liability on the accompanying condensed consolidated balance sheets, as the net value of the proceeds will be utilized to benefit SCE&G's customers in a manner to be determined by the SCPSC. As described above, several WEC Subcontractors have filed liens against the Unit 2/3 Property, which SCE&G is contesting. Payments under the Toshiba Settlement are subject to reduction if WEC pays WEC Subcontractors holding pre-petition liens directly. Under these circumstances, SCE&G and Santee Cooper, each in its pro rata share, would be required to make Citibank whole for the reduction. On January 2, 2018, the purchase agreement with Citibank was amended to limit the amount that SCE&G and Santee Cooper could be required to reimburse Citibank for valid subcontractor and vendor pre-petition liens to $60 million ( $33 million for SCE&G's 55% share). Regulatory, Political and Legal Developments In September 2017, the Company was served with a subpoena issued by the United States Attorney’s Office for the District of South Carolina seeking documents relating to the Nuclear Project. The subpoena requires the Company to produce a broad range of documents related to the project. Also, SLED is conducting a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. In October 2017, the staff of the SEC's Division of Enforcement also issued a subpoena for documents related to an investigation they are conducting related to the Nuclear Project. These investigations are ongoing, and the Company and Consolidated SCE&G intend to fully cooperate with them. Also in connection with the abandonment of the Nuclear Project, various state and local governmental authorities have attempted and may further attempt to challenge, reverse or revoke previously-approved tax or economic development incentives, benefits or exemptions and have attempted and may further attempt to apply such actions retroactively. No assurance can be given as to the timing or outcome of these matters. See Claims and Litigation for a description of specific challenges. On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, and in reliance on the opinion from the Office of Attorney General, the ORS filed the Request seeking an order from the SCPSC directing SCE&G to immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS, which the ORS believes should have been disclosed, that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections. On October 17, 2017, the ORS filed a motion with the SCPSC to amend the Request, in which motion the ORS asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. See Claims and Litigation herein for additional discussions regarding regarding the constitutionality of the BLRA. On December 20, 2017, the SCPSC denied a motion by SCE&G to dismiss the Request. Parties who have intervened in the Request or who filed a letter in support of it include the state's Governor, Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, Santee Cooper, the SCEUC, certain large industrial customers, and several environmental groups. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets, including the Request, regarding the merits of the Joint Petition and related issues. This schedule was established in response to legislation described below. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the outcome of this matter. See also Note 2. In 2017, special committees of the South Carolina General Assembly, both in the House of Representatives and in the Senate, conducted public hearings regarding the Company's decision to abandon the Nuclear Project. Several legislative proposals adverse to the Company and Consolidated SCE&G resulted from the work of these committees, two of which became law in 2018 and are described below. On June 27, 2018, the South Carolina General Assembly adopted Act 258, which became law June 28, 2018, to temporarily reduce the amount SCE&G can collect from customers under the BLRA. Act 258 requires the SCPSC to order a reduction in the portion of SCE&G's retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer’s bill to approximately 3.2% , or a reduction of approximately $31 million per month, retroactive to April 1, 2018. Absent an earlier ruling from the SCPSC, which could be issued only on the SCPSC’s own initiative, these lower rates are to be effective until the SCPSC renders a final decision on the merits of the Joint Petition. On July 2 and 3, 2018, the SCPSC issued orders implementing the temporary rate reduction required by Act 258. The resulting new rates and retroactive credits required by Act 258 were put into effect in August 2018, with the retroactive credits for the second quarter being applied in August's billing cycles. In addition to the reduction of electric rates (which rates had been previously approved by the SCPSC), Act 258 alters certain provisions previously applicable under the BLRA, including redefining the standard of care required by the BLRA and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the Nuclear Project. On June 29, 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of Act 258 along with joint resolution S. 954, which became law on July 2, 2018. Among other things, S. 954 prohibits the SCPSC from holding a hearing on the merits of the Joint Petition before November 1, 2018, and requires it to issue an order on the merits of the Joint Petition by December 21, 2018. In the lawsuit, which was subsequently amended, SCE&G seeks a declaration that the new laws are unconstitutional and asks the court to issue an injunction prohibiting the SCPSC from implementing Act 258. Various parties have been granted status as intervenor defendants, and during the third quarter the District Court denied their motions to dismiss. SCE&G’s motion for the issuance of a preliminary injunction was denied on August 5, 2018, which SCE&G appealed to the Court of Appeals. On September 21, 2018, the Court of Appeals denied SCE&G's motion for an injunction pending appeal and also denied a motion to dismiss by intervenor defendants. At September 30, 2018, each of the lawsuit in the District Court and the appeal of the District Court's denial of a preliminary injunction was pending. The Company and Consolidated SCE&G cannot predict the timing or outcome of this matter. Dominion Energy and Sedona may not be obligated to complete the pending merger with SCANA because Act 258 remains in effect and is being implemented. Proposals to Resolve Outstanding Issues On November 16, 2017, SCE&G announced for public consideration a proposal to resolve outstanding issues relating to the Nuclear Project. Under the proposal, SCE&G electric customers were to receive a 3.5% electric rate reduction, the addition of an existing 540-MW natural gas fired power plant by SCE&G with the acquisition cost borne by SCANA shareholders, and the addition of approximately 100-MW of large scale solar energy by SCE&G. The proposal also provided for the recovery of the nuclear construction costs (net of the proceeds of the Toshiba Settlement not utilized for satisfaction of project liens) over 50 years. While SCE&G’s proposal was not formally submitted for regulatory approval at that time, discussions with key stakeholders over the ensuing weeks indicated that SCE&G's proposal would not be sufficient to resolve the outstanding issues. On January 2, 2018, SCANA entered into the Merger Agreement with Dominion Energy, and on January 12, 2018, SCE&G and Dominion Energy filed the Joint Petition requesting SCPSC approval of the merger or a finding that either the merger is in the public interest or that there is an absence of harm arising from the merger. In this petition, the parties committed to providing an up-front, one time rate credit to SCE&G's electric customers totaling approximately $1.3 billion within 90 days of the merger's closing, providing at least a 5% reduction in customer bills (later adjusted to approximately 7% in light of the effects of the Tax Act), shortening the amortization period for costs related to the Nuclear Project to 20 years, forgoing recovery of approximately $1.7 billion in costs related to the Nuclear Project, and purchasing an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers. On October 25, 2018, in response to the desire of various parties to the Concurrent Dockets for an alternative that would further reduce customer bills, Dominion Energy filed with the SCPSC the Alternative Customer Benefits Plan (Alternative Plan). The testimony filed by Dominion Energy in connection with the Alternative Plan indicates that customers would receive refunds totaling approximately $1.91 billion with approximately $1.0 billion being refunded evenly over 20 years and approximately $880 million credited to customers over approximately ten years instead of the up-front, one time rate credit of $1.3 billion originally proposed in the Joint Petition. In addition, such testimony indicates that approximately $2.3 billion in costs related to the Nuclear Project would not be recovered in connection with the Alternative Plan, instead of the $1.7 billion originally proposed. The parties to the Joint Petition estimate that these changes would result in customer bill reductions of approximately 14% (including the effects of the Tax Act). The Alternative Plan also contemplates the purchase of an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers. The ORS has filed direct and rebuttal testimony and a pre-hearing brief related to the Concurrent Dockets. In these filings, the ORS has proposed (ORS Plan) that the SCPSC reduce SCE&G's electric rates during the 12 months following the effective date of its order by approximately $561 million compared to rates that would otherwise be in effect when the temporary rate reduction under Act 258 expires. This proposal includes reductions due to assumed merger synergies, the use of an ROE of 9.1% rather than 10.25% (which proposed ROE would be applied to a smaller rate base after all adjustments specified by the ORS), the ORS calculation of savings from the Tax Act (which exceeds SCE&G's calculation), the refund of amounts deferred as subject to refund that arise from the Tax Act and other adjustments. After 12 months (after amounts subject to refund have been returned to customers), the ORS proposes that SCE&G's electric rates be modified to an amount that would be approximately $528 million lower annually compared to rates that would otherwise be in effect when the temporary rate reduction under Act 258 expires. On October 25, 2018, in testimony filed in connection with the Concurrent Dockets, a representative of Dominion Energy noted that (1) the ORS Plan, if adopted, would be devastating not only to the proposed merger but also to SCE&G's future and to the interests of SCE&G's customers and the state of South Carolina in reliable electric service at just and reasonable rates and (2) there is currently pending litigation in the South Carolina state courts in which the judge has indicated that he is considering issuing an order that would violate the "no change in law" provision of the Merger Agreement, and that if such an order were issued or the ORS Plan is adopted, the merger would be unable to close. On October 26, 2018, Santee Cooper filed a pre-hearing brief with respect to the Joint Petition. In its filing, Santee Cooper requested that the SCPSC not approve a merger between SCANA and Dominion Energy as being in the public interest unless SCANA and Dominion Energy commit to creating a fund of approximately $351 million to mitigate the financial impact of the abandonment of the Nuclear Project on Santee Cooper's wholesale and retail customers. Santee Cooper proposes that the cost of creating such a fund should not be recoverable from SCE&G's customers. On November 1, 2018, the SCPSC began hearing from the parties to the Concurrent Dockets regarding the merits of the Joint Petition and related issues, and as noted above, pursuant to S. 954 the SCPSC is required to issue an order related to the Joint Petition no later than December 21, 2018. No assurance can be given as to the timing or outcome of efforts to consummate the Merger Agreement or to obtain approval of the Joint Petition. On May 9, 2018, SCE&G completed its purchase of CEC, the existing 540-MW natural gas fired power plant referred to above, for approximately $180 million . As disclosed in Note 10 to the Company's and Consolidated SCE&G's Form 10-K for December 31, 2017, an impairment loss recorded in the fourth quarter of 2017 included $180 million related to SCE&G's commitment to not seek recovery from customers for the acquisition cost of this natural gas fired power plant, and accordingly, this amount was recorded as a reduction to unrecovered Nuclear Project costs within regulatory assets on the Company's and Consolidated SCE&G's consolidated balance sheets at December 31, 2017. As such, the Company's and Consolidated SCE&G's condensed consolidated balance sheet as of September 30, 2018 reflect the cost for CEC within Utility Plant in Service, and the $180 million impairment initially recorded as unrecovered Nuclear Project costs within regulatory assets is now reflected within Accumulated Depreciation and Amortization, which results in the carrying value of CEC being entirely written off. SCE&G’s commitment to not seek recovery from customers for the acquisition cost of CEC was one element of certain broader rate mitigation proposals contained within the Joint Petition and the Alternative Plan. Assuming that the SCPSC approves either of the mitigating proposals as outlined in the Joint Petition or approves the Alternative Plan, SCE&G will not seek recovery of CEC acquisition costs. Impairment Considerations At September 30, 2018, SCE&G estimated that revised rates collections previously approved under the BLRA totaled approximately $445 million annually. SCE&G estimates that such revised rates collections for 2018 would be reduced by approximately $279 million if Act 258 remains in effect and is implemented through December 21, 2018, which is the expected pendency of the SCPSC proceeding with respect to the Joint Petition. New rates are expected to be ordered by the SCPSC in connection with its order on the Joint Petition, which order is to be issued no later than December 21, 2018. On a cumulative basis, at September 30, 2018, SCE&G estimated that revised rates collections previously approved under the BLRA totaled approximately $2.1 billion , which amount reflects the impacts of Act 258. For each of the quarters ended June 30, 2018, September 30, 2018 and December 31, 2018, SCANA's Board of Directors declared a dividend of $0.1237 per share, which represents an approximately 80% reduction from the $0.6125 per share paid on SCANA’s common stock for the first quarter of 2018. This reduction corresponds to the portion of the dividend attributable to SCE&G's electric operations and serves to partially mitigate the liquidity impacts arising from the reduced revenues and cash flows resulting from the implementation of Act 258. Under the current regulatory construct in South Carolina, pursuant to the BLRA or through other means, the ability of SCE&G to recover costs incurred in connection with Unit 2 and Unit 3, and a reasonable return on them, will be subject to review and approval by the SCPSC. In light of the contentious nature of activity involving the General Assembly and other officials and the Request being considered by the SCPSC that could result in the suspension of all rates currently being collected under the BLRA, as well as the return of such amounts previously collected, there is significant uncertainty as to SCE&G’s ultimate ability to recover its costs of Unit 2 and Unit 3 and a return on them from its customers. See also Claims and Litigation herein for additional discussion regarding the constitutionality of the BLRA. SCE&G continues to contest the specific challenges described above. However, based on the consideration of those challenges, and particularly in light of SCE&G's proposed solution announced on November 16, 2017 and details in the Joint Petition filed by SCE&G and Dominion Energy with the SCPSC on January 12, 2018, the Company and Consolidated SCE&G determined that a disallowance of recovery of part of the cost of the abandoned Nuclear Project is both probable and reasonably estimable under applicable accounting guidance. In addition, the Company and Consolidated SCE&G determined that full recovery of certain other related costs deferred within regulatory assets is less than probable. As a result, in 2017 the Company and Consolidated SCE&G recognized a pre-tax impairment loss totaling $1.118 billion ( $690 million net of tax). Also, in the first quarter of 2018, the Company and Consolidated SCE&G recognized an additional pre-tax impairment loss of approximately $3.6 million ( $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. It is reasonably possible that a change in estimated impairment loss could occur in the near term and could be material; however, all such changes cannot be reasonably estimated. The impairment loss recorded in 2017 reflects impacts similar to those that would have resulted had the proposed solution announced on November 16, 2017 been implemented. If the merger benefits and cost recovery plan outlined in the Joint Petition are implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $1.7 billion (approximately $1.3 billion net of tax) would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $813 million recorded within regulatory assets, the write-off of unrecovered Nuclear Project costs of approximately $86 million recorded within Utility Plant, and the recording of additional liabilities for customer refunds totaling approximately $1.875 billion, net of approximately $1.065 billion , which amount represents the monetization of guaranty settlement recorded within regulatory liabilities less amounts that may be required to satisfy contractor liens. If the Alternative Plan were implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $2.3 billion (approximately $1.7 billion net of tax) would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $1.368 billion recorded within regulatory assets, the write-off of unrecovered Nuclear Project costs of approximately $86 million recorded within Utility Plant, and the recording of additional liabilities for customer refunds of approximately $880 million. In addition, the Alternative Plan provides for the refunding of the existing regulatory liability associated with the monetization of guaranty settlement over 20 years less amounts that may be required to satisfy contractor liens. If (i) the SCPSC does not approve the Joint Petition or the Alternative Plan and instead approves the Request by the ORS; (ii) the BLRA is found to be unconstitutional; or (iii) the General Assembly further amends or revokes the BLRA or approves other legislation with a similar effect, the Company and Consolidated SCE&G may be required to record an additional impairment loss (in excess of the $1.118 billion above) and other charges totaling approximately $5.0 billion (approximately $3.7 billion net of tax). This additional impairment loss would result from the write-off of approximately $3.960 billion in regulatory assets (comprised of remaining unrecovered Nuclear Project costs of $4.140 billion offset by $180 million in previously impaired costs related to CEC, which would result from the proposals put forward in the Joint Petition or the Alternative Plan not being approved by the SCPSC) and the refund of revised rates collections under the BLRA described above of approximately $2.1 billion (comprised of the revised rates collections on a cumulative basis as of September 30, 2018 and reflective of the impacts of Act 258), net of approximately $1.065 billion, which amount represents the monetization of guaranty settlement recorded within regulatory liabilities less amounts that may be required to satisfy contractor liens. The Company and Consolidated SCE&G do not currently anticipate that any amounts collected prior to April 1, 2018, will be subject to refund (other than amounts arising from the effects of the Tax Act); however, no assurance can be given as to the outcome of this matter. See Claims and Litigation herein for additional discussion regarding the constitutionality of the BLRA. At September 30, 2018, the Company and Consolidated SCE&G included considerations of the impact of Act 258 in the evaluation as to their ability to recover the remaining Nuclear Project costs and a reasonable return on those costs. Because Act 258 explicitly provides for an experimental rate that is temporary and does not disallow any of the costs currently deferred as a regulatory asset, and because the experimental rate is to be replaced by rates that the SCPSC is to determine and order no later than December 21, 2018, the Company and Consolidated SCE&G have concluded that additional impairment charges related to unrecovered Nuclear Project costs are not probable, and the recording of such charges would not be appropriate, at this time. However, if a disallowance were ordered or the rates under Act 258 were made other than temporary by the SCPSC in the Joint Petition proceeding, the Company and Consolidated SCE&G would reevaluate this conclusion. Were the rates under Act 258 made other than temporary following the SCPSC's final decision on the Joint Petition, and without consideration of any other factors that may be embodied in such an order, an additional pre-tax impairment charge totaling approximately $1.7 billion may be required. In addition to the matters above, in the Joint Petition, the Company and Consolidated SCE&G proposed to remove from BLRA capital costs their investment in transmission assets that have been or will be placed in service and have not been abandoned. As of September 30, 2018, such investment in these assets total approximately $376 million (approximately $365 million within utility plant, net and approximately $11 million within regulatory assets, which amount represents certain deferred operating costs). The Company and Consolidated SCE&G believe that this investment represents assets that are or will be used to

SEGMENT OF BUSINESS INFORMATION

SEGMENT OF BUSINESS INFORMATION	9 Months Ended
	Sep. 30, 2018
Segment Reporting Information [Line Items]
Segment Reporting Disclosure [Text Block]	SEGMENT OF BUSINESS INFORMATION Regulated operations measure profitability using operating income; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. The Gas Marketing segment measures profitability using net income. The Company's Gas Distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented. The Company Millions of dollars External Revenue Intersegment Revenue Operating Income (Loss) Net Income Three Months Ended September 30, 2018 Electric Operations $ 669 — $ 217 n/a Gas Distribution 122 — (10 ) n/a Gas Marketing 135 $ 35 n/a $ 1 All Other — 124 — (30 ) Adjustments/Eliminations — (159 ) (24 ) 96 Consolidated Total $ 926 — $ 183 $ 67 Nine Months Ended September 30, 2018 Electric Operations $ 1,767 $ 3 $ 396 n/a Gas Distribution 631 1 107 n/a Gas Marketing 550 95 n/a $ 21 All Other — 347 — (79 ) Adjustments/Eliminations — (446 ) (28 ) 302 Consolidated Total $ 2,948 — $ 475 $ 244 Three Months Ended September 30, 2017 Electric Operations $ 786 $ 1 $ 127 n/a Gas Distribution 123 — (7 ) n/a Gas Marketing 167 35 n/a $ 1 All Other — 90 — (7 ) Adjustments/Eliminations — (126 ) 2 40 Consolidated Total $ 1,076 — $ 122 $ 34 Nine Months Ended September 30, 2017 Electric Operations $ 2,042 $ 4 $ 555 n/a Gas Distribution 584 1 110 n/a Gas Marketing 623 93 n/a $ 17 All Other — 286 — (14 ) Adjustments/Eliminations — (384 ) 28 323 Consolidated Total $ 3,249 — $ 693 $ 326 Consolidated SCE&G Millions of dollars External Revenue Operating Income (Loss) Comprehensive Income Available to Common Shareholder Three Months Ended September 30, 2018 Electric Operations $ 670 $ 216 n/a Gas Distribution 69 (4 ) n/a Adjustments/Eliminations — — $ 98 Consolidated Total $ 739 $ 212 $ 98 Nine Months Ended September 30, 2018 Electric Operations $ 1,770 $ 396 n/a Gas Distribution 304 44 n/a Adjustments/Eliminations — — $ 248 Consolidated Total $ 2,074 $ 440 $ 248 Three Months Ended September 30, 2017 Electric Operations $ 787 $ 126 n/a Gas Distribution 69 (2 ) n/a Adjustments/Eliminations — — $ 39 Consolidated Total $ 856 $ 124 $ 39 Nine Months Ended September 30, 2017 Electric Operations $ 2,046 $ 555 n/a Gas Distribution 285 42 n/a Adjustments/Eliminations — — $ 270 Consolidated Total $ 2,331 $ 597 $ 270 Segment Assets The Company Consolidated SCE&G September 30, December 31, September 30, December 31, Millions of dollars 2018 2017 2018 2017 Electric Operations $ 12,046 $ 11,979 $ 12,046 $ 11,979 Gas Distribution 3,384 3,259 909 869 Gas Marketing 204 230 n/a n/a All Other 1,071 1,042 n/a n/a Adjustments/Eliminations 2,111 2,229 3,174 3,098 Consolidated Total $ 18,816 $ 18,739 $ 16,129 $ 15,946
SCEG
Segment Reporting Information [Line Items]
Segment Reporting Disclosure [Text Block]	SEGMENT OF BUSINESS INFORMATION Regulated operations measure profitability using operating income; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. The Gas Marketing segment measures profitability using net income. The Company's Gas Distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented. The Company Millions of dollars External Revenue Intersegment Revenue Operating Income (Loss) Net Income Three Months Ended September 30, 2018 Electric Operations $ 669 — $ 217 n/a Gas Distribution 122 — (10 ) n/a Gas Marketing 135 $ 35 n/a $ 1 All Other — 124 — (30 ) Adjustments/Eliminations — (159 ) (24 ) 96 Consolidated Total $ 926 — $ 183 $ 67 Nine Months Ended September 30, 2018 Electric Operations $ 1,767 $ 3 $ 396 n/a Gas Distribution 631 1 107 n/a Gas Marketing 550 95 n/a $ 21 All Other — 347 — (79 ) Adjustments/Eliminations — (446 ) (28 ) 302 Consolidated Total $ 2,948 — $ 475 $ 244 Three Months Ended September 30, 2017 Electric Operations $ 786 $ 1 $ 127 n/a Gas Distribution 123 — (7 ) n/a Gas Marketing 167 35 n/a $ 1 All Other — 90 — (7 ) Adjustments/Eliminations — (126 ) 2 40 Consolidated Total $ 1,076 — $ 122 $ 34 Nine Months Ended September 30, 2017 Electric Operations $ 2,042 $ 4 $ 555 n/a Gas Distribution 584 1 110 n/a Gas Marketing 623 93 n/a $ 17 All Other — 286 — (14 ) Adjustments/Eliminations — (384 ) 28 323 Consolidated Total $ 3,249 — $ 693 $ 326 Consolidated SCE&G Millions of dollars External Revenue Operating Income (Loss) Comprehensive Income Available to Common Shareholder Three Months Ended September 30, 2018 Electric Operations $ 670 $ 216 n/a Gas Distribution 69 (4 ) n/a Adjustments/Eliminations — — $ 98 Consolidated Total $ 739 $ 212 $ 98 Nine Months Ended September 30, 2018 Electric Operations $ 1,770 $ 396 n/a Gas Distribution 304 44 n/a Adjustments/Eliminations — — $ 248 Consolidated Total $ 2,074 $ 440 $ 248 Three Months Ended September 30, 2017 Electric Operations $ 787 $ 126 n/a Gas Distribution 69 (2 ) n/a Adjustments/Eliminations — — $ 39 Consolidated Total $ 856 $ 124 $ 39 Nine Months Ended September 30, 2017 Electric Operations $ 2,046 $ 555 n/a Gas Distribution 285 42 n/a Adjustments/Eliminations — — $ 270 Consolidated Total $ 2,331 $ 597 $ 270 Segment Assets The Company Consolidated SCE&G September 30, December 31, September 30, December 31, Millions of dollars 2018 2017 2018 2017 Electric Operations $ 12,046 $ 11,979 $ 12,046 $ 11,979 Gas Distribution 3,384 3,259 909 869 Gas Marketing 204 230 n/a n/a All Other 1,071 1,042 n/a n/a Adjustments/Eliminations 2,111 2,229 3,174 3,098 Consolidated Total $ 18,816 $ 18,739 $ 16,129 $ 15,946

AFFILIATED TRANSACTIONS

AFFILIATED TRANSACTIONS	9 Months Ended
	Sep. 30, 2018
Related Party Transaction [Line Items]
Related Party Transactions Disclosure [Text Block]	AFFILIATED TRANSACTIONS The Company and Consolidated SCE&G: SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Three Months Ended September 30, Nine Months Ended September 30, Millions of Dollars 2018 2017 2018 2017 Purchases from Canadys Refined Coal, LLC $ 45.2 $ 47.5 $ 122.5 $ 144.9 Sales to Canadys Refined Coal, LLC 44.9 47.2 121.8 144.0 Millions of Dollars September 30, 2018 December 31, 2017 Receivable from Canadys Refined Coal, LLC $ 8.5 $ 4.9 Payable to Canadys Refined Coal, LLC 8.5 4.9 Consolidated SCE&G: SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in Other operation and maintenance - nonconsolidated affiliate and Other Income (Expense), net on the consolidated statements of comprehensive income. Consolidated SCE&G has provided $71.0 million in funding to a rabbi trust consolidated with SCANA in connection with the potential change in control arising from the Merger Agreement. This funding is recorded as long-term Other affiliate assets on the condensed consolidated balance sheet of Consolidated SCE&G. Three Months Ended September 30, Nine Months Ended September 30, Millions of Dollars 2018 2017 2018 2017 Purchases from SCANA Energy $ 35.0 $ 35.3 $ 95.0 $ 93.4 Direct and Allocated Costs from SCANA Services 72.9 78.1 208.3 233.6 Millions of Dollars September 30, 2018 December 31, 2017 Payable to SCANA Energy $ 10.6 $ 10.0 Payable to SCANA Services 42.8 42.0 Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 5. Certain disclosures regarding SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 9.
SCEG
Related Party Transaction [Line Items]
Related Party Transactions Disclosure [Text Block]	AFFILIATED TRANSACTIONS The Company and Consolidated SCE&G: SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Three Months Ended September 30, Nine Months Ended September 30, Millions of Dollars 2018 2017 2018 2017 Purchases from Canadys Refined Coal, LLC $ 45.2 $ 47.5 $ 122.5 $ 144.9 Sales to Canadys Refined Coal, LLC 44.9 47.2 121.8 144.0 Millions of Dollars September 30, 2018 December 31, 2017 Receivable from Canadys Refined Coal, LLC $ 8.5 $ 4.9 Payable to Canadys Refined Coal, LLC 8.5 4.9 Consolidated SCE&G: SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in Other operation and maintenance - nonconsolidated affiliate and Other Income (Expense), net on the consolidated statements of comprehensive income. Consolidated SCE&G has provided $71.0 million in funding to a rabbi trust consolidated with SCANA in connection with the potential change in control arising from the Merger Agreement. This funding is recorded as long-term Other affiliate assets on the condensed consolidated balance sheet of Consolidated SCE&G. Three Months Ended September 30, Nine Months Ended September 30, Millions of Dollars 2018 2017 2018 2017 Purchases from SCANA Energy $ 35.0 $ 35.3 $ 95.0 $ 93.4 Direct and Allocated Costs from SCANA Services 72.9 78.1 208.3 233.6 Millions of Dollars September 30, 2018 December 31, 2017 Payable to SCANA Energy $ 10.6 $ 10.0 Payable to SCANA Services 42.8 42.0 Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 5. Certain disclosures regarding SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 9.

OTHER INCOME (EXPENSE), NET Not

OTHER INCOME (EXPENSE), NET Notes	9 Months Ended
	Sep. 30, 2018
Condensed Income Statements, Captions [Line Items]
Other Income and Other Expense Disclosure [Text Block]	OTHER INCOME (EXPENSE), NET Components of other income (expense), net are as follows: The Company Consolidated SCE&G Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended September 30, September 30, September 30, September 30, Millions of dollars 2018 2017 2018 2017 2018 2017 2018 2017 Revenues from contracts with customers $ 4 — $ 14 — $ 1 — $ 4 — Other income 8 $ 28 144 $ 61 5 $ 21 135 $ 36 Other expense (14 ) (9 ) (34 ) (33 ) (10 ) (7 ) (22 ) (23 ) Allowance for equity funds used during construction 5 — 12 17 3 (3 ) 7 13 Other income (expense), net $ 3 $ 19 $ 136 $ 45 $ (1 ) $ 11 $ 124 $ 26 The recording of revenue from contracts with customers within other income (expense) arose upon the adoption of related accounting guidance described in Note 1 and Note 3, and as permitted, prior periods have not been restated. Other income in 2018 includes gains from the settlement of interest rate derivatives of approximately $115 million (see Note 7). Non-service cost components of pension and other postretirement benefits are included in Other expense.
SCEG
Condensed Income Statements, Captions [Line Items]
Other Income and Other Expense Disclosure [Text Block]	OTHER INCOME (EXPENSE), NET Components of other income (expense), net are as follows: The Company Consolidated SCE&G Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended September 30, September 30, September 30, September 30, Millions of dollars 2018 2017 2018 2017 2018 2017 2018 2017 Revenues from contracts with customers $ 4 — $ 14 — $ 1 — $ 4 — Other income 8 $ 28 144 $ 61 5 $ 21 135 $ 36 Other expense (14 ) (9 ) (34 ) (33 ) (10 ) (7 ) (22 ) (23 ) Allowance for equity funds used during construction 5 — 12 17 3 (3 ) 7 13 Other income (expense), net $ 3 $ 19 $ 136 $ 45 $ (1 ) $ 11 $ 124 $ 26 The recording of revenue from contracts with customers within other income (expense) arose upon the adoption of related accounting guidance described in Note 1 and Note 3, and as permitted, prior periods have not been restated. Other income in 2018 includes gains from the settlement of interest rate derivatives of approximately $115 million (see Note 7). Non-service cost components of pension and other postretirement benefits are included in Other expense.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 30, 2018
Significant Accounting Policies
Basis Of Consolidation And Variable Interest Entities [Policy Text Block]	Basis of Consolidation and Variable Interest Entities The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $495 million ) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5.
Income Statement policy [Policy Text Block]	Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 11) are presented within Operating Income, and other activities are presented within Other Income (Expense).
Asset Management and Supply Service Agreements	Asset Management and Supply Service Agreement PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 45% and 39% of PSNC Energy’s natural gas inventory at September 30, 2018 and December 31, 2017, respectively, with a carrying value of $14.3 million and $11.5 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to customers. This agreement expires on March 31, 2019.
Earnings Per Share [Text Block]	Earnings Per Share The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.
Reclassification, Policy [Policy Text Block]	Reclassifications In the statement of operations, amounts reported for 2017 under the captions “Other income,” “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net.” Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated.
SCEG
Significant Accounting Policies
Basis Of Consolidation And Variable Interest Entities [Policy Text Block]	Basis of Consolidation and Variable Interest Entities The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $495 million ) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5.
Income Statement policy [Policy Text Block]	Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 11) are presented within Operating Income, and other activities are presented within Other Income (Expense).
Reclassification, Policy [Policy Text Block]	Reclassifications In the statement of operations, amounts reported for 2017 under the captions “Other income,” “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net.” Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES RECLASSIFICATION (Tables)	9 Months Ended
	Sep. 30, 2018
Condensed Statement of Income Captions [Line Items]
Statement of Income [Table Text Block]	Increase (Decrease) Millions of dollars The Company Consolidated SCE&G September 30, 2017 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended Other operation and maintenance $ (2 ) $ (8 ) $ (1 ) $ (6 ) Total Operating Expenses (2 ) (8 ) (1 ) (6 ) Operating Income 2 8 1 6 Other Income (Expense), Net (2 ) (8 ) (1 ) (6 )
SCEG
Condensed Statement of Income Captions [Line Items]
Statement of Income [Table Text Block]	Increase (Decrease) Millions of dollars The Company Consolidated SCE&G September 30, 2017 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended Other operation and maintenance $ (2 ) $ (8 ) $ (1 ) $ (6 ) Total Operating Expenses (2 ) (8 ) (1 ) (6 ) Operating Income 2 8 1 6 Other Income (Expense), Net (2 ) (8 ) (1 ) (6 )

RATE AND OTHER REGULATORY MAT_2

RATE AND OTHER REGULATORY MATTERS (Tables)	9 Months Ended
	Sep. 30, 2018
Public Utilities, General Disclosures [Line Items]
Pipeline integrity management revenue requirement [Table Text Block]	Rates Effective Incremental Increase March 1, 2018 $14.7 million September 1, 2018 $1.1 million
Schedule of Regulatory Assets [Table Text Block]	The Company Consolidated SCE&G Millions of dollars September 30, December 31, September 30, December 31, Regulatory Assets: Unrecovered Nuclear Project costs $ 4,140 $ 3,976 $ 4,140 $ 3,976 AROs and related funding 448 434 423 410 Deferred employee benefit plan costs 282 305 254 273 Deferred losses on interest rate derivatives 446 456 446 456 Other unrecovered plant 96 105 96 105 DSM Programs 57 59 57 59 Pipeline integrity management costs 67 51 9 8 Environmental remediation costs 28 30 24 25 Deferred storm damage costs 29 24 29 24 Deferred transmission operating costs 11 — 11 — Other 135 140 134 140 Total Regulatory Assets $ 5,739 $ 5,580 $ 5,623 $ 5,476
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities: Monetization of guaranty settlement $ 1,098 $ 1,095 $ 1,098 $ 1,095 Accumulated deferred income taxes 1,075 1,076 916 914 Asset removal costs 775 757 539 527 Deferred gains on interest rate derivatives 77 131 77 131 Other 15 — 5 — Total Regulatory Liabilities $ 3,040 $ 3,059 $ 2,635 $ 2,667
SCEG
Public Utilities, General Disclosures [Line Items]
Schedule of Regulatory Assets [Table Text Block]	The Company Consolidated SCE&G Millions of dollars September 30, December 31, September 30, December 31, Regulatory Assets: Unrecovered Nuclear Project costs $ 4,140 $ 3,976 $ 4,140 $ 3,976 AROs and related funding 448 434 423 410 Deferred employee benefit plan costs 282 305 254 273 Deferred losses on interest rate derivatives 446 456 446 456 Other unrecovered plant 96 105 96 105 DSM Programs 57 59 57 59 Pipeline integrity management costs 67 51 9 8 Environmental remediation costs 28 30 24 25 Deferred storm damage costs 29 24 29 24 Deferred transmission operating costs 11 — 11 — Other 135 140 134 140 Total Regulatory Assets $ 5,739 $ 5,580 $ 5,623 $ 5,476
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities: Monetization of guaranty settlement $ 1,098 $ 1,095 $ 1,098 $ 1,095 Accumulated deferred income taxes 1,075 1,076 916 914 Asset removal costs 775 757 539 527 Deferred gains on interest rate derivatives 77 131 77 131 Other 15 — 5 — Total Regulatory Liabilities $ 3,040 $ 3,059 $ 2,635 $ 2,667

REVENUE RECOGNITION Revenue Rec

REVENUE RECOGNITION Revenue Recognition (Tables)	9 Months Ended
	Sep. 30, 2018
Disaggregation of Revenue [Table Text Block]	The Company Consolidated SCE&G PSNC Energy Gas-nonregulated Millions of dollars Electric Gas-regulated Gas-regulated Total Gas-regulated Three months ended September 30, 2018 Customer class: Residential $ 310 $ 25 $ 27 $ 52 $ 22 Commercial 231 19 19 38 14 Industrial 95 19 — 19 93 Other 31 6 7 13 6 Revenues from contracts with customers 667 69 53 122 135 Other operating revenues 3 — — — — Total Operating Revenues $ 670 $ 69 $ 53 $ 122 $ 135 Nine months ended September 30, 2018 Customer class: Residential $ 805 $ 145 $ 210 $ 355 $ 158 Commercial 571 80 85 165 64 Industrial 286 64 10 74 304 Other 99 13 22 35 24 Revenues from contracts with customers 1,761 302 327 629 550 Other operating revenues 9 1 1 2 — Total Operating Revenues $ 1,770 $ 303 $ 328 $ 631 $ 550
Capitalized Contract Cost [Table Text Block]	The Company and Consolidated SCE&G Millions of dollars Regulatory Assets January 1, 2018 $ 16.3 Additional costs — Amortization (1.1 ) Impairment — September 30, 2018 $ 15.2
SCEG
Disaggregation of Revenue [Table Text Block]	The Company Consolidated SCE&G PSNC Energy Gas-nonregulated Millions of dollars Electric Gas-regulated Gas-regulated Total Gas-regulated Three months ended September 30, 2018 Customer class: Residential $ 310 $ 25 $ 27 $ 52 $ 22 Commercial 231 19 19 38 14 Industrial 95 19 — 19 93 Other 31 6 7 13 6 Revenues from contracts with customers 667 69 53 122 135 Other operating revenues 3 — — — — Total Operating Revenues $ 670 $ 69 $ 53 $ 122 $ 135 Nine months ended September 30, 2018 Customer class: Residential $ 805 $ 145 $ 210 $ 355 $ 158 Commercial 571 80 85 165 64 Industrial 286 64 10 74 304 Other 99 13 22 35 24 Revenues from contracts with customers 1,761 302 327 629 550 Other operating revenues 9 1 1 2 — Total Operating Revenues $ 1,770 $ 303 $ 328 $ 631 $ 550
Capitalized Contract Cost [Table Text Block]	The Company and Consolidated SCE&G Millions of dollars Regulatory Assets January 1, 2018 $ 16.3 Additional costs — Amortization (1.1 ) Impairment — September 30, 2018 $ 15.2

LONG-TERM AND SHORT-TERM DEBT (

LONG-TERM AND SHORT-TERM DEBT (Tables)	9 Months Ended
	Sep. 30, 2018
Short-term Debt [Line Items]
Schedule of Line of Credit Facilities [Table Text Block]	September 30, 2018 (Millions of dollars) Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: + Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Three-year, expiring December 2018 200.0 — 200.0 — Total committed long-term 2,000.0 400.0 1,400.0 200.0 LOC advances 40.0 40.0 — — Weighted average interest rate 3.78 % — — Outstanding commercial paper (270 or fewer days) 314.2 3.7 173.2 137.3 Weighted average interest rate 3.20 % 3.21 % 3.13 % Letters of credit supported by LOC 37.6 37.3 0.3 — Available $ 1,608.2 $ 319.0 $ 1,226.5 $ 62.7 December 31, 2017 (Millions of dollars) Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Three-year, expiring December 2018 200.0 — 200.0 — Total committed long-term 2,000.0 400.0 1,400.0 200.0 Outstanding commercial paper (270 or fewer days) 350.3 — 251.6 98.7 Weighted average interest rate — 1.92 % 1.93 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,646.4 $ 397.0 $ 1,148.1 $ 101.3
SCEG
Short-term Debt [Line Items]
Schedule of Line of Credit Facilities [Table Text Block]	September 30, 2018 (Millions of dollars) Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: + Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Three-year, expiring December 2018 200.0 — 200.0 — Total committed long-term 2,000.0 400.0 1,400.0 200.0 LOC advances 40.0 40.0 — — Weighted average interest rate 3.78 % — — Outstanding commercial paper (270 or fewer days) 314.2 3.7 173.2 137.3 Weighted average interest rate 3.20 % 3.21 % 3.13 % Letters of credit supported by LOC 37.6 37.3 0.3 — Available $ 1,608.2 $ 319.0 $ 1,226.5 $ 62.7 December 31, 2017 (Millions of dollars) Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 500.0 — 500.0 — Three-year, expiring December 2018 200.0 — 200.0 — Total committed long-term 2,000.0 400.0 1,400.0 200.0 Outstanding commercial paper (270 or fewer days) 350.3 — 251.6 98.7 Weighted average interest rate — 1.92 % 1.93 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,646.4 $ 397.0 $ 1,148.1 $ 101.3

DERIVATIVE FINANCIAL INSTRUME_2

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative [Line Items]
Schedule of Nonmonetary Notional Amounts of Outstanding Derivative Positions [Table Text Block]	The Company was party to natural gas derivative contracts outstanding in the following quantities: Commodity and Other Energy Management Contracts (in MMBTU) Hedge designation Gas Distribution Gas Marketing Total As of September 30, 2018 Commodity contracts 7,050,000 16,856,000 23,906,000 Energy management contracts (a) — 40,949,232 40,949,232 Total (a) 7,050,000 57,805,232 64,855,232 As of December 31, 2017 Commodity contracts 6,430,000 13,433,000 19,863,000 Energy management contracts (a) — 41,856,890 41,856,890 Total (a) 6,430,000 55,289,890 61,719,890 (a) Includes amounts related to basis swap contracts totaling 9,396,000 MMBTU in 2018 and 2,582,000 MMBTU in 2017.
Schedule of Derivative Instruments [Table Text Block]	The aggregate notional amounts of the interest rate swaps were as follows: Interest Rate Swaps The Company Consolidated SCE&G Millions of dollars September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 Designated as hedging instruments $ 106.8 $ 111.2 $ 36.4 $ 36.4 Not designated as hedging instruments 35.0 735.0 35.0 735.0
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown. Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of September 30, 2018 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 2 — $ 1 Other deferred credits and other liabilities — 16 — 6 Commodity contracts Prepayments $ 1 — — — Total $ 1 $ 18 — $ 7 Not designated as hedging instruments Interest rate contracts Other deferred credits and other liabilities — $ 2 — $ 2 Commodity contracts Prepayments $ 1 — — — Energy management contracts Prepayments 1 — — — Other current assets 1 — — — Other current liabilities — 2 — — Total $ 3 $ 4 — $ 2 The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of December 31, 2017 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 3 — $ 1 Other deferred credits and other liabilities — 24 — 9 Commodity contracts Prepayments — 2 — — Other current assets — 1 — — Total — $ 30 — $ 10 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 54 $ 1 $ 54 $ 1 Other deferred credits and other liabilities — 4 — 4 Commodity contracts Other current assets 1 — — — Energy management contracts Prepayments — 1 — — Other current assets 3 — — — Other deferred debits and other assets 1 — — — Derivative financial instruments — 2 — — Total $ 59 $ 8 $ 54 $ 5
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts (Loss) Reclassified from Deferred Accounts into Income Millions of dollars 2018 2017 Location 2018 2017 Three Months Ended September 30, Interest rate contracts — — Interest expense — — Nine Months Ended September 30, Interest rate contracts $ 2 $ (1 ) Interest expense $ (1 ) $ (1 ) The Company: Gain (Loss) Recognized in OCI, net of tax Gain (Loss) Reclassified from AOCI into Income, net of tax Millions of dollars 2018 2017 Location 2018 2017 Three Months Ended September 30, Interest rate contracts $ 1 — Interest expense $ (3 ) $ (2 ) Total $ 1 — $ (3 ) $ (2 ) Nine Months Ended September 30, Interest rate contracts $ 3 $ (1 ) Interest expense $ (7 ) $ (6 ) Commodity contracts 2 (4 ) Gas purchased for resale (2 ) 2 Total $ 5 $ (5 ) $ (9 ) $ (4 )
Derivatives Not Designated as Hedging Instruments [Table Text Block]	Derivatives Not designated as Hedging Instruments The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars 2018 2017 Location 2018 2017 Three Months Ended September 30, Interest rate contracts $ 1 $ (6 ) Interest Expense $ (1 ) $ (1 ) Nine Months Ended September 30, Interest rate contracts $ 66 $ (30 ) Interest Expense $ (2 ) $ (2 ) Other Income 115 —
Disclosure of Credit Derivatives [Table Text Block]	Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 20.8 $ 33.7 $ 8.7 $ 14.7 Fair value of collateral already posted 22.3 28.9 8.7 10.1 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ (1.5 ) $ 4.8 — $ 4.6 in Net Asset Position Aggregate fair value of derivatives in net asset position — $ 53.5 — $ 53.5 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — $ 53.5 — $ 53.5
Offseting Assets [Table Text Block]	Information related to the offsetting of derivative assets and derivative liabilities follows: Derivative Assets The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of September 30, 2018 Gross Amounts of Recognized Assets — $ 2 $ 2 $ 4 — Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position — 2 2 4 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 2 $ 2 $ 4 — Balance sheet location Prepayments $ 3 — Other current assets 1 — Total $ 4 — As of December 31, 2017 Gross Amounts of Recognized Assets $ 54 $ 1 $ 4 $ 59 $ 54 Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position 54 1 4 59 54 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 54 $ 1 $ 4 $ 59 $ 54 Balance sheet location Other current assets $ 58 $ 54 Other deferred debits and other assets 1 — Total $ 59 $ 54
Offsetting Liabilities [Table Text Block]	Derivative Liabilities Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of September 30, 2018 Gross Amounts of Recognized Liabilities $ 20 — $ 2 $ 22 $ 9 Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position 20 — 2 22 9 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (21 ) — (1 ) (22 ) (9 ) Net Amount $ (1 ) — $ 1 — — Balance sheet location Derivative financial instruments $ 2 $ 1 Other current liabilities 2 — Other deferred credits and other liabilities 18 8 Total $ 22 $ 9 As of December 31, 2017 Gross Amounts of Recognized Liabilities $ 32 $ 3 $ 3 $ 38 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 32 3 2 37 15 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted 28 — (1 ) 27 — Net Amount $ 60 $ 3 $ 1 $ 64 $ 15 Balance sheet location Other current assets $ 2 — Derivative financial instruments 7 $ 2 Other deferred credits and other liabilities 28 13 Total $ 37 $ 15
SCEG
Derivative [Line Items]
Schedule of Derivative Instruments [Table Text Block]	The aggregate notional amounts of the interest rate swaps were as follows: Interest Rate Swaps The Company Consolidated SCE&G Millions of dollars September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 Designated as hedging instruments $ 106.8 $ 111.2 $ 36.4 $ 36.4 Not designated as hedging instruments 35.0 735.0 35.0 735.0
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown. Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of September 30, 2018 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 2 — $ 1 Other deferred credits and other liabilities — 16 — 6 Commodity contracts Prepayments $ 1 — — — Total $ 1 $ 18 — $ 7 Not designated as hedging instruments Interest rate contracts Other deferred credits and other liabilities — $ 2 — $ 2 Commodity contracts Prepayments $ 1 — — — Energy management contracts Prepayments 1 — — — Other current assets 1 — — — Other current liabilities — 2 — — Total $ 3 $ 4 — $ 2 The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of December 31, 2017 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 3 — $ 1 Other deferred credits and other liabilities — 24 — 9 Commodity contracts Prepayments — 2 — — Other current assets — 1 — — Total — $ 30 — $ 10 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 54 $ 1 $ 54 $ 1 Other deferred credits and other liabilities — 4 — 4 Commodity contracts Other current assets 1 — — — Energy management contracts Prepayments — 1 — — Other current assets 3 — — — Other deferred debits and other assets 1 — — — Derivative financial instruments — 2 — — Total $ 59 $ 8 $ 54 $ 5
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts (Loss) Reclassified from Deferred Accounts into Income Millions of dollars 2018 2017 Location 2018 2017 Three Months Ended September 30, Interest rate contracts — — Interest expense — — Nine Months Ended September 30, Interest rate contracts $ 2 $ (1 ) Interest expense $ (1 ) $ (1 )
Derivatives Not Designated as Hedging Instruments [Table Text Block]	Derivatives Not designated as Hedging Instruments The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars 2018 2017 Location 2018 2017 Three Months Ended September 30, Interest rate contracts $ 1 $ (6 ) Interest Expense $ (1 ) $ (1 ) Nine Months Ended September 30, Interest rate contracts $ 66 $ (30 ) Interest Expense $ (2 ) $ (2 ) Other Income 115 — For
Disclosure of Credit Derivatives [Table Text Block]	Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 20.8 $ 33.7 $ 8.7 $ 14.7 Fair value of collateral already posted 22.3 28.9 8.7 10.1 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ (1.5 ) $ 4.8 — $ 4.6 in Net Asset Position Aggregate fair value of derivatives in net asset position — $ 53.5 — $ 53.5 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — $ 53.5 — $ 53.5
Offseting Assets [Table Text Block]	Information related to the offsetting of derivative assets and derivative liabilities follows: Derivative Assets The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of September 30, 2018 Gross Amounts of Recognized Assets — $ 2 $ 2 $ 4 — Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position — 2 2 4 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 2 $ 2 $ 4 — Balance sheet location Prepayments $ 3 — Other current assets 1 — Total $ 4 — As of December 31, 2017 Gross Amounts of Recognized Assets $ 54 $ 1 $ 4 $ 59 $ 54 Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position 54 1 4 59 54 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 54 $ 1 $ 4 $ 59 $ 54 Balance sheet location Other current assets $ 58 $ 54 Other deferred debits and other assets 1 — Total $ 59 $ 54
Offsetting Liabilities [Table Text Block]	Derivative Liabilities Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of September 30, 2018 Gross Amounts of Recognized Liabilities $ 20 — $ 2 $ 22 $ 9 Gross Amounts Offset in Statement of Financial Position — — — — — Net Amounts Presented in Statement of Financial Position 20 — 2 22 9 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (21 ) — (1 ) (22 ) (9 ) Net Amount $ (1 ) — $ 1 — — Balance sheet location Derivative financial instruments $ 2 $ 1 Other current liabilities 2 — Other deferred credits and other liabilities 18 8 Total $ 22 $ 9 As of December 31, 2017 Gross Amounts of Recognized Liabilities $ 32 $ 3 $ 3 $ 38 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 32 3 2 37 15 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted 28 — (1 ) 27 — Net Amount $ 60 $ 3 $ 1 $ 64 $ 15 Balance sheet location Other current assets $ 2 — Derivative financial instruments 7 $ 2 Other deferred credits and other liabilities 28 13 Total $ 37 $ 15

FAIR VALUE MEASUREMENTS, INCL_2

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: As of September 30, 2018 As of December 31, 2017 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 2 Level 1 Level 2 Level 1 Level 2 Assets: Available for sale securities $ 15 — — $ 119 — $ 100 — Held to maturity securities — $ 6 — — $ 6 — — Interest rate contracts — — — — 54 — $ 54 Commodity contracts 2 — — 1 — — — Energy management contracts — 2 — — 4 — — Liabilities: Interest rate contracts — 20 $ 9 — 32 — 15 Commodity contracts — — — 2 1 — — Energy management contracts — 4 — 1 4 — —
Fair Value, by Balance Sheet Grouping [Table Text Block]	Financial instruments for which the carrying amount may not equal estimated fair value were as follows: Long-Term Debt September 30, 2018 December 31, 2017 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,753.3 $ 6,980.8 $ 6,632.9 $ 7,399.7 Consolidated SCE&G 5,145.2 5,295.2 5,163.3 5,790.3
SCEG
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: As of September 30, 2018 As of December 31, 2017 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 2 Level 1 Level 2 Level 1 Level 2 Assets: Available for sale securities $ 15 — — $ 119 — $ 100 — Held to maturity securities — $ 6 — — $ 6 — — Interest rate contracts — — — — 54 — $ 54 Commodity contracts 2 — — 1 — — — Energy management contracts — 2 — — 4 — — Liabilities: Interest rate contracts — 20 $ 9 — 32 — 15 Commodity contracts — — — 2 1 — — Energy management contracts — 4 — 1 4 — —
Fair Value, by Balance Sheet Grouping [Table Text Block]	Financial instruments for which the carrying amount may not equal estimated fair value were as follows: Long-Term Debt September 30, 2018 December 31, 2017 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,753.3 $ 6,980.8 $ 6,632.9 $ 7,399.7 Consolidated SCE&G 5,145.2 5,295.2 5,163.3 5,790.3

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	9 Months Ended
	Sep. 30, 2018
Pension and Other Postretirement Benefit Plans
Schedule of Net Benefit Costs [Table Text Block]	The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2018 2017 Three months ended September 30, Service cost $ 5.9 $ 5.7 $ 1.1 $ 1.0 Interest cost 8.5 9.2 2.2 2.8 Expected return on assets (14.0 ) (13.4 ) — — Prior service cost amortization 0.1 0.4 — — Amortization of actuarial (gains) losses 3.7 4.4 (0.5 ) — Net periodic benefit cost $ 4.2 $ 6.3 $ 2.8 $ 3.8 Nine months ended September 30, Service cost $ 15.8 $ 16.3 $ 3.4 $ 3.4 Interest cost 25.6 28.0 7.6 8.6 Expected return on assets (42.6 ) (41.0 ) — — Prior service cost amortization 0.4 1.2 — — Amortization of actuarial losses 9.6 12.2 0.6 0.8 Net periodic benefit cost $ 8.8 $ 16.7 $ 11.6 $ 12.8 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2018 2017 Three months ended September 30, Service cost $ 4.8 $ 4.8 $ 0.9 $ 0.8 Interest cost 7.2 7.8 1.7 2.3 Expected return on assets (11.8 ) (11.4 ) — — Prior service cost amortization 0.1 0.3 — — Amortization of actuarial (gains) losses 3.1 3.7 (0.4 ) — Net periodic benefit cost $ 3.4 $ 5.2 $ 2.2 $ 3.1 Nine months ended September 30, Service cost $ 12.9 $ 13.6 $ 2.7 $ 2.8 Interest cost 21.6 24.0 6.0 7.1 Expected return on assets (36.0 ) (35.0 ) — — Prior service cost amortization 0.3 1.0 — — Amortization of actuarial losses 8.1 10.4 0.5 0.6 Net periodic benefit cost $ 6.9 $ 14.0 $ 9.2 $ 10.5
SCEG
Pension and Other Postretirement Benefit Plans
Schedule of Net Benefit Costs [Table Text Block]	Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2018 2017 2018 2017 Three months ended September 30, Service cost $ 4.8 $ 4.8 $ 0.9 $ 0.8 Interest cost 7.2 7.8 1.7 2.3 Expected return on assets (11.8 ) (11.4 ) — — Prior service cost amortization 0.1 0.3 — — Amortization of actuarial (gains) losses 3.1 3.7 (0.4 ) — Net periodic benefit cost $ 3.4 $ 5.2 $ 2.2 $ 3.1 Nine months ended September 30, Service cost $ 12.9 $ 13.6 $ 2.7 $ 2.8 Interest cost 21.6 24.0 6.0 7.1 Expected return on assets (36.0 ) (35.0 ) — — Prior service cost amortization 0.3 1.0 — — Amortization of actuarial losses 8.1 10.4 0.5 0.6 Net periodic benefit cost $ 6.9 $ 14.0 $ 9.2 $ 10.5

SEGMENT OF BUSINESS INFORMATI_2

SEGMENT OF BUSINESS INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2018
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	The Company Millions of dollars External Revenue Intersegment Revenue Operating Income (Loss) Net Income Three Months Ended September 30, 2018 Electric Operations $ 669 — $ 217 n/a Gas Distribution 122 — (10 ) n/a Gas Marketing 135 $ 35 n/a $ 1 All Other — 124 — (30 ) Adjustments/Eliminations — (159 ) (24 ) 96 Consolidated Total $ 926 — $ 183 $ 67 Nine Months Ended September 30, 2018 Electric Operations $ 1,767 $ 3 $ 396 n/a Gas Distribution 631 1 107 n/a Gas Marketing 550 95 n/a $ 21 All Other — 347 — (79 ) Adjustments/Eliminations — (446 ) (28 ) 302 Consolidated Total $ 2,948 — $ 475 $ 244 Three Months Ended September 30, 2017 Electric Operations $ 786 $ 1 $ 127 n/a Gas Distribution 123 — (7 ) n/a Gas Marketing 167 35 n/a $ 1 All Other — 90 — (7 ) Adjustments/Eliminations — (126 ) 2 40 Consolidated Total $ 1,076 — $ 122 $ 34 Nine Months Ended September 30, 2017 Electric Operations $ 2,042 $ 4 $ 555 n/a Gas Distribution 584 1 110 n/a Gas Marketing 623 93 n/a $ 17 All Other — 286 — (14 ) Adjustments/Eliminations — (384 ) 28 323 Consolidated Total $ 3,249 — $ 693 $ 326 Consolidated SCE&G Millions of dollars External Revenue Operating Income (Loss) Comprehensive Income Available to Common Shareholder Three Months Ended September 30, 2018 Electric Operations $ 670 $ 216 n/a Gas Distribution 69 (4 ) n/a Adjustments/Eliminations — — $ 98 Consolidated Total $ 739 $ 212 $ 98 Nine Months Ended September 30, 2018 Electric Operations $ 1,770 $ 396 n/a Gas Distribution 304 44 n/a Adjustments/Eliminations — — $ 248 Consolidated Total $ 2,074 $ 440 $ 248 Three Months Ended September 30, 2017 Electric Operations $ 787 $ 126 n/a Gas Distribution 69 (2 ) n/a Adjustments/Eliminations — — $ 39 Consolidated Total $ 856 $ 124 $ 39 Nine Months Ended September 30, 2017 Electric Operations $ 2,046 $ 555 n/a Gas Distribution 285 42 n/a Adjustments/Eliminations — — $ 270 Consolidated Total $ 2,331 $ 597 $ 270 Segment Assets The Company Consolidated SCE&G September 30, December 31, September 30, December 31, Millions of dollars 2018 2017 2018 2017 Electric Operations $ 12,046 $ 11,979 $ 12,046 $ 11,979 Gas Distribution 3,384 3,259 909 869 Gas Marketing 204 230 n/a n/a All Other 1,071 1,042 n/a n/a Adjustments/Eliminations 2,111 2,229 3,174 3,098 Consolidated Total $ 18,816 $ 18,739 $ 16,129 $ 15,946
SCEG
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Consolidated SCE&G Millions of dollars External Revenue Operating Income (Loss) Comprehensive Income Available to Common Shareholder Three Months Ended September 30, 2018 Electric Operations $ 670 $ 216 n/a Gas Distribution 69 (4 ) n/a Adjustments/Eliminations — — $ 98 Consolidated Total $ 739 $ 212 $ 98 Nine Months Ended September 30, 2018 Electric Operations $ 1,770 $ 396 n/a Gas Distribution 304 44 n/a Adjustments/Eliminations — — $ 248 Consolidated Total $ 2,074 $ 440 $ 248 Three Months Ended September 30, 2017 Electric Operations $ 787 $ 126 n/a Gas Distribution 69 (2 ) n/a Adjustments/Eliminations — — $ 39 Consolidated Total $ 856 $ 124 $ 39 Nine Months Ended September 30, 2017 Electric Operations $ 2,046 $ 555 n/a Gas Distribution 285 42 n/a Adjustments/Eliminations — — $ 270 Consolidated Total $ 2,331 $ 597 $ 270 Segment Assets The Company Consolidated SCE&G September 30, December 31, September 30, December 31, Millions of dollars 2018 2017 2018 2017 Electric Operations $ 12,046 $ 11,979 $ 12,046 $ 11,979 Gas Distribution 3,384 3,259 909 869 Gas Marketing 204 230 n/a n/a All Other 1,071 1,042 n/a n/a Adjustments/Eliminations 2,111 2,229 3,174 3,098 Consolidated Total $ 18,816 $ 18,739 $ 16,129 $ 15,946

AFFILIATED TRANSACTIONS Related

AFFILIATED TRANSACTIONS Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2018
Related Party Transaction [Line Items]
Schedule of Related Party Transactions [Table Text Block]	Three Months Ended September 30, Nine Months Ended September 30, Millions of Dollars 2018 2017 2018 2017 Purchases from Canadys Refined Coal, LLC $ 45.2 $ 47.5 $ 122.5 $ 144.9 Sales to Canadys Refined Coal, LLC 44.9 47.2 121.8 144.0 Millions of Dollars September 30, 2018 December 31, 2017 Receivable from Canadys Refined Coal, LLC $ 8.5 $ 4.9 Payable to Canadys Refined Coal, LLC 8.5 4.9 Three Months Ended September 30, Nine Months Ended September 30, Millions of Dollars 2018 2017 2018 2017 Purchases from SCANA Energy $ 35.0 $ 35.3 $ 95.0 $ 93.4 Direct and Allocated Costs from SCANA Services 72.9 78.1 208.3 233.6 Millions of Dollars September 30, 2018 December 31, 2017 Payable to SCANA Energy $ 10.6 $ 10.0 Payable to SCANA Services 42.8 42.0
Related Party Transactions Disclosure [Text Block]	AFFILIATED TRANSACTIONS The Company and Consolidated SCE&G: SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Three Months Ended September 30, Nine Months Ended September 30, Millions of Dollars 2018 2017 2018 2017 Purchases from Canadys Refined Coal, LLC $ 45.2 $ 47.5 $ 122.5 $ 144.9 Sales to Canadys Refined Coal, LLC 44.9 47.2 121.8 144.0 Millions of Dollars September 30, 2018 December 31, 2017 Receivable from Canadys Refined Coal, LLC $ 8.5 $ 4.9 Payable to Canadys Refined Coal, LLC 8.5 4.9 Consolidated SCE&G: SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in Other operation and maintenance - nonconsolidated affiliate and Other Income (Expense), net on the consolidated statements of comprehensive income. Consolidated SCE&G has provided $71.0 million in funding to a rabbi trust consolidated with SCANA in connection with the potential change in control arising from the Merger Agreement. This funding is recorded as long-term Other affiliate assets on the condensed consolidated balance sheet of Consolidated SCE&G. Three Months Ended September 30, Nine Months Ended September 30, Millions of Dollars 2018 2017 2018 2017 Purchases from SCANA Energy $ 35.0 $ 35.3 $ 95.0 $ 93.4 Direct and Allocated Costs from SCANA Services 72.9 78.1 208.3 233.6 Millions of Dollars September 30, 2018 December 31, 2017 Payable to SCANA Energy $ 10.6 $ 10.0 Payable to SCANA Services 42.8 42.0 Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 5. Certain disclosures regarding SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 9.
SCEG
Related Party Transaction [Line Items]
Schedule of Related Party Transactions [Table Text Block]	Three Months Ended September 30, Nine Months Ended September 30, Millions of Dollars 2018 2017 2018 2017 Purchases from SCANA Energy $ 35.0 $ 35.3 $ 95.0 $ 93.4 Direct and Allocated Costs from SCANA Services 72.9 78.1 208.3 233.6 Millions of Dollars September 30, 2018 December 31, 2017 Payable to SCANA Energy $ 10.6 $ 10.0 Payable to SCANA Services 42.8 42.0 Three Months Ended September 30, Nine Months Ended September 30, Millions of Dollars 2018 2017 2018 2017 Purchases from Canadys Refined Coal, LLC $ 45.2 $ 47.5 $ 122.5 $ 144.9 Sales to Canadys Refined Coal, LLC 44.9 47.2 121.8 144.0 Millions of Dollars September 30, 2018 December 31, 2017 Receivable from Canadys Refined Coal, LLC $ 8.5 $ 4.9 Payable to Canadys Refined Coal, LLC 8.5 4.9
Related Party Transactions Disclosure [Text Block]	AFFILIATED TRANSACTIONS The Company and Consolidated SCE&G: SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Three Months Ended September 30, Nine Months Ended September 30, Millions of Dollars 2018 2017 2018 2017 Purchases from Canadys Refined Coal, LLC $ 45.2 $ 47.5 $ 122.5 $ 144.9 Sales to Canadys Refined Coal, LLC 44.9 47.2 121.8 144.0 Millions of Dollars September 30, 2018 December 31, 2017 Receivable from Canadys Refined Coal, LLC $ 8.5 $ 4.9 Payable to Canadys Refined Coal, LLC 8.5 4.9 Consolidated SCE&G: SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in Other operation and maintenance - nonconsolidated affiliate and Other Income (Expense), net on the consolidated statements of comprehensive income. Consolidated SCE&G has provided $71.0 million in funding to a rabbi trust consolidated with SCANA in connection with the potential change in control arising from the Merger Agreement. This funding is recorded as long-term Other affiliate assets on the condensed consolidated balance sheet of Consolidated SCE&G. Three Months Ended September 30, Nine Months Ended September 30, Millions of Dollars 2018 2017 2018 2017 Purchases from SCANA Energy $ 35.0 $ 35.3 $ 95.0 $ 93.4 Direct and Allocated Costs from SCANA Services 72.9 78.1 208.3 233.6 Millions of Dollars September 30, 2018 December 31, 2017 Payable to SCANA Energy $ 10.6 $ 10.0 Payable to SCANA Services 42.8 42.0 Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 5. Certain disclosures regarding SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 9.

OTHER INCOME (EXPENSE), NET Oth

OTHER INCOME (EXPENSE), NET Other Income (Expense) (Tables)	9 Months Ended
	Sep. 30, 2018
Schedule of Other Nonoperating Income (Expense) [Table Text Block]	The Company Consolidated SCE&G Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended September 30, September 30, September 30, September 30, Millions of dollars 2018 2017 2018 2017 2018 2017 2018 2017 Revenues from contracts with customers $ 4 — $ 14 — $ 1 — $ 4 — Other income 8 $ 28 144 $ 61 5 $ 21 135 $ 36 Other expense (14 ) (9 ) (34 ) (33 ) (10 ) (7 ) (22 ) (23 ) Allowance for equity funds used during construction 5 — 12 17 3 (3 ) 7 13 Other income (expense), net $ 3 $ 19 $ 136 $ 45 $ (1 ) $ 11 $ 124 $ 26
SCEG
Schedule of Other Nonoperating Income (Expense) [Table Text Block]	The Company Consolidated SCE&G Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended September 30, September 30, September 30, September 30, Millions of dollars 2018 2017 2018 2017 2018 2017 2018 2017 Revenues from contracts with customers $ 4 — $ 14 — $ 1 — $ 4 — Other income 8 $ 28 144 $ 61 5 $ 21 135 $ 36 Other expense (14 ) (9 ) (34 ) (33 ) (10 ) (7 ) (22 ) (23 ) Allowance for equity funds used during construction 5 — 12 17 3 (3 ) 7 13 Other income (expense), net $ 3 $ 19 $ 136 $ 45 $ (1 ) $ 11 $ 124 $ 26

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)MW	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Reclassification Operations and Maintenance Expense	$ (2)		$ (8)
Reclassification Total Operating Expense	(2)		(8)
Reclassification Operating Income	2		8
Reclassification Other Income(Expense)	(2)		(8)
Property, Plant and Equipment, Net		$ 269		$ 270
SCEG
Reclassification Operations and Maintenance Expense	(1)		(6)
Reclassification Total Operating Expense	(1)		(6)
Reclassification Operating Income	1		6
Reclassification Other Income(Expense)	$ (1)		$ (6)
Property, Plant and Equipment, Net		73		$ 71
Genco
Property, Plant and Equipment, Net		$ 495
Power Generation Capacity Megawatts | MW		605
PSNC Energy [Member]
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)		45.00%		39.00%
Natural gas inventory, carrying amount		$ 14.3		$ 11.5
PercentOfStorageFeesCreditedToRatePayers		75.00%

RATE AND OTHER REGULATORY MAT_3

RATE AND OTHER REGULATORY MATTERS (Details) - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Dec. 31, 2018	Mar. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Jan. 01, 2019
Rate Matters [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent			21.00%	35.00%	35.00%
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery			$ 0.035
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA			18.00%
Change in Retail Electric Rates Approved Under BLRA			$ 0.032
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 31,000,000
Asset Retirement Obligation Costs [Member]
Rate Matters [Line Items]
Regulatory Noncurrent Asset Amortization Period			107 years
Environmental Restoration Costs [Member]
Rate Matters [Line Items]
MPG environmental remediation			17
SCEG
Rate Matters [Line Items]
Refund to Customer Related to Tax Act			$ 61,000,000
SCPSC Order, Recovery Of Projected DER Program Costs			29,300,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery			1,300,000
SCPSC Order, Annual DSM Program Rate Rider Recovery Amount			33,000,000
Public Utilities changes in Retail Natural Gas Rates Approved under RSA	$ 19,700,000
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates	4.61%
SCEG | Pension costs, electric [Member]
Rate Matters [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority			2,000,000
SCEG | Pension costs, gas [Member]
Rate Matters [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority			1,000,000
SCANA [Member]
Rate Matters [Line Items]
Refund to Customer Related to Tax Act			3,800,000
PSNC Energy
Rate Matters [Line Items]
Proposed Merger Credits						$ 1,250,000
Refund to Customer Related to Tax Act			$ 10,100,000
MPG environmental remediation			4.2
Pipeline integrity mgmt annual revenue requirement approved by NCUC		$ 14,700,000

RATE AND OTHER REGULATORY MAT_4

RATE AND OTHER REGULATORY MATTERS (Details 2) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Mar. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Regulatory Assets
Asset Impairment Charges		$ 4	$ 210
Regulatory Liability, Noncurrent		3,040		$ 3,059
Regulatory Assets, Noncurrent		5,739		5,580
SCEG
Regulatory Assets
Asset Impairment Charges		4	$ 210
Regulatory Liability, Noncurrent		2,635		2,667
Regulatory Assets, Noncurrent		5,623		5,476
PSNC Energy [Member]
Regulatory Assets
Pipeline integrity mgmt annual revenue requirement approved by NCUC	$ 14.7
Pipeline integrity management costs, amount deferred pending future approval of rate recovery		$ 44.9
MPG environmental remediation		4.2
Pipeline integrity management costs, amount recovering beginning November 2016		$ 4.1
Settlement Proceeds [Member] | Summer Station Unit 2 and Unit 3 [Domain]
Regulatory Assets
Regulatory Liability, Noncurrent		1,098		1,095
Settlement Proceeds [Member] | SCEG
Regulatory Assets
Regulatory Liability, Noncurrent		1,098		1,095
Deferred Income Tax Charge [Member]
Regulatory Assets
Regulatory Liability, Noncurrent		1,075		1,076
Deferred Income Tax Charge [Member] | SCEG
Regulatory Assets
Regulatory Liability, Noncurrent		916		914
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Liability, Noncurrent		775		757
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Liability, Noncurrent		539		527
Deferred gains on interest rate derivatives [Member]
Regulatory Assets
Regulatory Liability, Noncurrent		77		131
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Assets
Regulatory Liability, Noncurrent		77		131
Other Regulatory Liability [Member]
Regulatory Assets
Regulatory Liability, Noncurrent		15
Other Regulatory Liability [Member] | SCEG
Regulatory Assets
Regulatory Liability, Noncurrent		5		0
Unrecovered nuclear project costs post impairment [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		$ 4,140		3,976
Unrecovered nuclear project costs post impairment [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent				3,976
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Asset, Amortization Period		107 years
Regulatory Assets, Noncurrent		$ 448		434
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		423		410
Pension Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		282		305
Pension Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		254		273
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		446		456
Deferred Losses On Interest Rate Derivatives [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		446		456
unrecovered plant [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		96		105
unrecovered plant [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		96		105
Demand Side Management programs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		$ 57		59
Demand Side Management programs [Member] | SCEG
Regulatory Assets
Regulatory Asset, Amortization Period		5 years
Regulatory Assets, Noncurrent		$ 57		59
Pipeline integrity management costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		67		51
Pipeline integrity management costs [Member] | SCEG
Regulatory Assets
Pipeline integrity management costs, annual amortization amount		1.9
Regulatory Assets, Noncurrent		$ 9		8
Environmental Restoration Costs [Member]
Regulatory Assets
MPG environmental remediation		17
Regulatory Assets, Noncurrent		$ 28		30
Environmental Restoration Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		24		25
Storm Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent		29		24
Storm Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		$ 29		24
Other Regulatory Assets [Member]
Regulatory Assets
Regulatory Asset Recovery Assessments		2,047
Regulatory Assets, Noncurrent		$ 135		140
Other Regulatory Assets [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		134		$ 140
Deferred transmission operating costs [Member] [Domain]
Regulatory Assets
Regulatory Assets, Noncurrent		11
Deferred transmission operating costs [Member] [Domain] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent		$ 11

RATE AND OTHER REGULATORY MAT_5

RATE AND OTHER REGULATORY MATTERS (Details 3) - USD ($) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%	35.00%
Regulatory Liabilities	$ 3,040		$ 3,059
SCEG
Regulatory Liabilities [Line Items]
Refund to Customer Related to Tax Act	61
Regulatory Liabilities	2,635		2,667
PSNC Energy [Member]
Regulatory Liabilities [Line Items]
Refund to Customer Related to Tax Act	10.1
Settlement Proceeds [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	1,098		1,095
Deferred Income Tax Charge [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	1,075		1,076
Deferred Income Tax Charge [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	916		914
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	775		757
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	539		527
Deferred gains on interest rate derivatives [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	77		131
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	77		131
Other Regulatory Liability [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	15
Other Regulatory Liability [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 5		$ 0

REVENUE RECOGNITION (Details)

REVENUE RECOGNITION (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Electric Regulated Revenue	$ 669	$ 786	$ 1,767	$ 2,042
Regulated Operating Revenue, Gas	122	123	631	584
Total Operating Revenues Gas	122		629
SCEG
Electric Regulated Revenue	669	786	1,767	2,042
Regulated Operating Revenue, Gas	69	69	303	284
Capitalized Contract Cost, Net	15.2		15.2		$ 16.3
Regulated Operating Revenue	739	856	2,074	2,331
Capitalized Contract Cost, Amortization			(1.1)
Electric Operations
Electric Regulated Revenue		786		2,042
Electric Operations | SCEG
Electric Regulated Revenue		$ 787		$ 2,046
Disaggregation of Revenue [Table Text Block]	667		1,761
Other Revenues	3		9
Regulated Operating Revenue	670		1,770
Residential [Member]
Total Operating Revenues Gas	52		355
Gas -non regulated revenues	22		158
Residential [Member] | SCEG
Electric Regulated Revenue	310		805
Regulated Operating Revenue, Gas	25		145
Residential [Member] | PSNC Energy [Member]
Regulated Operating Revenue, Gas	27		210
Wholesale [Member]
Total Operating Revenues Gas	13		35
Gas -non regulated revenues	6		24
Wholesale [Member] | SCEG
Electric Regulated Revenue	31		99
Regulated Operating Revenue, Gas	6		13
Wholesale [Member] | PSNC Energy [Member]
Regulated Operating Revenue, Gas	7		22
Industrial [Member]
Total Operating Revenues Gas	19		74
Gas -non regulated revenues	93		304
Industrial [Member] | SCEG
Electric Regulated Revenue	95		286
Regulated Operating Revenue, Gas	19		64
Industrial [Member] | PSNC Energy [Member]
Regulated Operating Revenue, Gas	0		10
Commercial [Member]
Total Operating Revenues Gas	38		165
Gas -non regulated revenues	14		64
Commercial [Member] | SCEG
Electric Regulated Revenue	231		571
Regulated Operating Revenue, Gas	19		80
Commercial [Member] | PSNC Energy [Member]
Regulated Operating Revenue, Gas	19		85
Gas Distribution
Total Operating Revenues Gas	122		631
Other Revenues	0		2
Gas Distribution | SCEG
Disaggregation of Revenue [Table Text Block]	69		302
Other Revenues	0		1
Regulated Operating Revenue	69		303
Gas Distribution | PSNC Energy [Member]
Disaggregation of Revenue [Table Text Block]	53		327
Other Revenues	0		1
Regulated Operating Revenue	53		328
Gas Marketing segment [Member]
Disaggregation of Revenue [Table Text Block]	135		550
Other Revenues	0		0
Regulated Operating Revenue	$ 135		$ 550

REVENUE RECOGNITION Contract Co

REVENUE RECOGNITION Contract Costs (Details) - SCEG - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Capitalized Contract Cost, Amortization	$ (1.1)
Capitalized Contract Cost, Net	15.2	$ 16.3
Capitalized Contract Cost, Gross	$ 0

COMMON EQUITY (Details)

COMMON EQUITY (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Schedule of Capitalization, Equity [Line Items]
Dividend Payment Restrictions Schedule, Description			0.6125
Common Stock, Shares Authorized	200		200
Common Stock, Shares, Outstanding	143		143		143
SCEG
Schedule of Capitalization, Equity [Line Items]
Retained Earnings, Appropriated	$ 99.9	$ 83.9	$ 99.9	$ 83.9
Common Stock, Shares Authorized	50		50
Common Stock, Shares, Outstanding	40.3		40.3		40.3
Preferred Stock, Shares Authorized	20		20
Preferred Stock, Shares Outstanding	0		0
PSNC Energy [Member]
Schedule of Capitalization, Equity [Line Items]
Dividend Payment Restrictions Schedule, Description			$30 million plus 85%
Cash distributions in allowed in excess			$ 100
Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 0	0	(2)	2
Interest Rate Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(3)	(2)	(7)	(6)
Gas Purchased for Resale [Member] [Member] | Cash Flow Hedging [Member] | Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net			2	(2)
Interest Expense [Member] | Cash Flow Hedging [Member] | Interest Rate Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 3	$ 2	$ 7	$ 6

LONG-TERM AND SHORT-TERM DEBT_2

LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($)	6 Months Ended		9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Related Party Transaction, Due from (to) Related Party, Current			$ 195,000,000	$ 28,000,000
Proceeds from Issuance of First Mortgage Bond			300,000,000
SCEG
Debt Instrument [Line Items]
Debt Instrument, Face Amount			67,800,000	67,800,000
Related Party Transaction, Due from (to) Related Party, Current			177,000,000	$ 37,000,000
Proceeds from Issuance of First Mortgage Bond			400,000,000
Genco
Debt Instrument [Line Items]
Secured Debt			160,000,000
Interest Expense, Debt			$ 0.0606
PSNC Energy [Member]
Debt Instrument [Line Items]
Senior Notes	$ 100,000,000	$ 150,000,000
Debt Instrument, Interest Rate, Increase (Decrease)	4.33%	4.18%

LONG-TERM AND SHORT-TERM DEBT_3

LONG-TERM AND SHORT-TERM DEBT (Details 2) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Interest Income, Related Party	$ 1	$ 3
Interest Expense, Related Party	1.1	2.5
Proceeds from Issuance of First Mortgage Bond		$ 300
interest rate on first mortgage bonds issued		4.25%
Borrowings under credit agreement		$ 100
Related Party Transaction, Due from (to) Related Party, Current	195	195	$ 28
Line of Credit Facility, Maximum Borrowing Capacity	2,000	2,000	2,000
Borrowings under LOC		40
Long-term Line of Credit	1,800	$ 1,800
Weighted Average interest rate on LOC borrowing		0.00%
Commercial Paper	314.2	$ 314.2	350.3
Letters of Credit Outstanding, Amount	37.6	37.6	3.3
Line of Credit Facility, Remaining Borrowing Capacity	1,608.2	1,608.2	1,646.4
Commercial paper borrowing limit	600	600
Repayments of First Mortgage Bond		$ 250
interest rate first mortgage bonds redeemed		6.50%
First Mortgage Bond rate [Domain]
Debt Instrument [Line Items]
interest rate on first mortgage bonds issued		3.50%
five year credit [Domain]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,300	$ 1,300	1,300
SCANA [Member]
Debt Instrument [Line Items]
Borrowings under credit agreement		40
Line of Credit Facility, Maximum Borrowing Capacity	400	$ 400	400
Weighted Average interest rate on LOC borrowing		3.78%
Commercial Paper	$ 3.7	$ 3.7	$ 0
Debt, Weighted Average Interest Rate	3.20%	3.20%	0.00%
Letters of Credit Outstanding, Amount	$ 37.3	$ 37.3	$ 3
Line of Credit Facility, Remaining Borrowing Capacity	319	319	397
SCEG including Fuel Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,400	1,400	1,400
Borrowings under LOC		0
Commercial Paper	$ 173.2	$ 173.2	$ 251.6
Debt, Weighted Average Interest Rate	3.21%	3.21%	1.92%
Letters of Credit Outstanding, Amount	$ 0.3	$ 0.3	$ 0.3
Line of Credit Facility, Remaining Borrowing Capacity	1,226.5	1,226.5	1,148.1
Commercial paper borrowing limit	1,600	1,600
Genco
Debt Instrument [Line Items]
Commercial paper borrowing limit	200	200
Fuel Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	500	500	500
Long-Term Line of Credit - SC Fuel Co only	500	500	500
SCEG
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond		400
Related Party Transaction, Due from (to) Related Party, Current	177	177	37
Line of Credit Facility, Maximum Borrowing Capacity	700	700	700
Long-term Line of Credit	1,200	1,200
Long-term Line of Credit - SCE&G only	200	200	200
Repayments of First Mortgage Bond		$ 300
interest rate first mortgage bonds redeemed		5.25%
PSNC Energy [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200	$ 200	200
Commercial Paper	$ 137.3	$ 137.3	$ 98.7
Debt, Weighted Average Interest Rate	3.13%	3.13%	1.93%
Line of Credit Facility, Remaining Borrowing Capacity	$ 62.7	$ 62.7	$ 101.3

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($)	3 Months Ended	9 Months Ended		12 Months Ended
	Mar. 31, 2019	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		$ 98,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate		98,000,000
Decrease in Unrecognized Tax Benefits is Reasonably Possible		11,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Accrued		1.4
Deferred Tax Liabilities, Deferred Expense, Reserves and Accruals		$ 6,800,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	2.50%	3.00%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	35.00%	35.00%
SCEG
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		$ 98,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate		98,000,000
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound		0
Decrease in Unrecognized Tax Benefits is Reasonably Possible		11,000,000
SCANA [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		$ 19,000,000

DERIVATIVE FINANCIAL INSTRUME_3

DERIVATIVE FINANCIAL INSTRUMENTS (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2018USD ($)MMBTU	Dec. 31, 2017MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	64,855,232	61,719,890
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,050,000	6,430,000
Gas Marketing segment [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	57,805,232	55,289,890
Commodity Contract
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	23,906,000	19,863,000
Commodity Contract | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,050,000	6,430,000
Commodity Contract | Gas Marketing segment [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	16,856,000	13,433,000
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	40,949,232	41,856,890
Energy Related Derivative [Member] | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0	0
Energy Related Derivative [Member] | Gas Marketing segment [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	40,949,232	41,856,890
Energy Related Derivative [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	9,396,000	2,582,000

DERIVATIVE FINANCIAL INSTRUME_4

DERIVATIVE FINANCIAL INSTRUMENTS Fair Value on Balance Sheet (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 4	$ 59
Derivative Liability, Fair Value, Gross Liability	22	38
Interest Rate Contract
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	54
Derivative Liability, Fair Value, Gross Liability	20	32
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2	1
Derivative Liability, Fair Value, Gross Liability	0	3
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2	4
Derivative Liability, Fair Value, Gross Liability	2	3
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1	0
Derivative Liability, Fair Value, Gross Liability	18	30
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	106.8	111.2
Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	2	3
Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	16	24
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1	0
Derivative Liability, Fair Value, Gross Liability	0	2
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Derivative Liability, Fair Value, Gross Liability		1
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	3	59
Derivative Liability, Fair Value, Gross Liability	4	8
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	35	735
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		1
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		54
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	2	4
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] | Commodity Contract [Member] | Other Current Assets [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
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	2
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1	0
Derivative Liability, Fair Value, Gross Liability		1
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1	3
Derivative Liability, Fair Value, Gross Liability		0
SCEG | Interest Rate Contract
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	54
Derivative Liability, Fair Value, Gross Liability	9	15
SCEG | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	7	10
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	36.4	36.4
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1	1
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	6	9
SCEG | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	54
Derivative Liability, Fair Value, Gross Liability	2	5
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	35	735
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		1
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		54
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 2	$ 4

DERIVATIVE FINANCIAL INSTRUME_5

DERIVATIVE FINANCIAL INSTRUMENTS On Income Statement (Details) - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ 1	$ 1	$ 3	$ 0	$ (3)	$ (2)	$ 5	$ (5)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ (3)	$ (2)	$ (4)	$ (2)	$ (2)		$ (9)	$ (4)
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant			insignificant			insignificant	insignificant
Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 0			$ 0			$ 2	$ (2)
Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax							2	(4)
Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	3			2			7	6
Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	1			0			3	(1)
Gas Purchased for Resale [Member] [Member] | Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net							(2)	2
Gas Purchased for Resale [Member] [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred							0.5
Interest Expense [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred							7.9
Interest Expense [Member] | Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (3)			$ (2)			$ (7)	$ (6)
SCEG
Derivative [Line Items]
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant			insignificant			insignificant	insignificant
Not Designated as Hedging Instrument [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ 1			$ (6)			$ 66	$ (30)
Not Designated as Hedging Instrument [Member] | Other Nonoperating Income (Expense) [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income				(1)				(2)
Not Designated as Hedging Instrument [Member] | Interest Expense [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(1)						(2)
Not Designated as Hedging Instrument [Member] | Interest Expense [Member] | Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred							(2.8)
Not Designated as Hedging Instrument [Member] | Other Income [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income							115
Designated as Hedging Instrument [Member] | Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net				0			2	(1)
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred							(1)
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ 0			$ 0			$ (1)	$ (1)

DERIVATIVE FINANCIAL INSTRUME_6

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Credit Risk) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Derivative [Line Items]
Letter of Credit Available Commodity Derivatives asset position	$ 0.3		$ 0.3		$ 1.2
Commodity Derivative, Net Asset Position, Aggregate Fair Value	2.9		2.9		4
Collateral Already Posted, Aggregate Fair Value	22.3		22.3		28.9
Additional Collateral, Aggregate Fair Value	(1.5)		(1.5)		(4.8)
Derivative, Net Liability Position, Aggregate Fair Value	20.8		20.8		33.7
Cash collateral to request from interest rate derivative counterparty	0		0		53.5
Interest Rate Derivative, net asset position, Aggregate Fair Value	0		0		53.5
SCEG
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	8.7		8.7		10.1
Additional Collateral, Aggregate Fair Value	0		0		(4.6)
Derivative, Net Liability Position, Aggregate Fair Value	8.7		8.7		14.7
Cash collateral to request from interest rate derivative counterparty	0		0		53.5
Interest Rate Derivative, net asset position, Aggregate Fair Value	0		0		$ 53.5
Not Designated as Hedging Instrument [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	1	$ (6)	66	$ (30)
Designated as Hedging Instrument [Member] | Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net		0	2	(1)
Interest Expense [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(1)		(2)
Interest Expense [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ 0	$ 0	(1)	$ (1)
Other Income [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income			$ 115

DERIVATIVE FINANCIAL INSTRUME_7

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments Offsetting Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 4	$ 59
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset	4	59
Derivative Liability, Fair Value, Gross Liability	22	38
Derivative Liability, Fair Value, Gross Asset	0	(1)
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative, Collateral, Right to Reclaim Cash	22	27
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	64
Derivative Liability	22	37
Derivative, Collateral, Obligation to Return Securities	0	0
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	4	59
Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	2	7
Prepayments [Member]
Derivative [Line Items]
Derivative Asset	3
Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	1	58
Derivative Liability		2
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset		1
Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	18	28
Other Liabilities	2
Interest Rate Contract
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	54
Derivative Asset	0	54
Derivative Liability, Fair Value, Gross Liability	20	32
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative, Collateral, Right to Reclaim Cash	21	28
Derivative Liability, Fair Value, Amount Offset Against Collateral	(1)	60
Derivative Liability	20	32
Derivative, Collateral, Obligation to Return Securities	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0	54
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2	1
Derivative Asset, Fair Value, Gross Liability	0
Derivative Asset	2	1
Derivative Liability, Fair Value, Gross Liability	0	3
Derivative Liability, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	3
Derivative Liability	0	3
Derivative Asset, Fair Value, Amount Offset Against Collateral	2	1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2	4
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset	2	4
Derivative Liability, Fair Value, Gross Liability	2	3
Derivative Liability, Fair Value, Gross Asset	0	(1)
Derivative, Collateral, Right to Reclaim Cash	1	1
Derivative Liability, Fair Value, Amount Offset Against Collateral	1	1
Derivative Liability	2	2
Derivative Asset, Fair Value, Amount Offset Against Collateral	2	4
SCEG
Derivative [Line Items]
Derivative Asset	0	54
Derivative Liability	9	15
SCEG | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	1	2
SCEG | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset		54
SCEG | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset		0
SCEG | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	8	13
SCEG | Interest Rate Contract
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	54
Derivative Asset	0	54
Derivative Liability, Fair Value, Gross Liability	9	15
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative, Collateral, Right to Reclaim Cash	9	0
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	15
Derivative Liability	9	15
Derivative, Collateral, Obligation to Return Securities	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	$ 0	$ 54

FAIR VALUE MEASUREMENTS, INCL_3

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	$ 15	$ 119
Held-to-maturity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	6	6
Interest Rate Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	54
Liabilities, Fair Value Disclosure	20	32
Commodity Contract | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	2	1
Liabilities, Fair Value Disclosure	0	2
Commodity Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	0
Liabilities, Fair Value Disclosure	0	1
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	0
Liabilities, Fair Value Disclosure	0	1
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	2	4
Liabilities, Fair Value Disclosure	4	4
SCEG | Available-for-sale Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure		100
SCEG | Interest Rate Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	54
Liabilities, Fair Value Disclosure	$ 9	$ 15

FAIR VALUE MEASUREMENTS, INCL_4

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 6,753.3	$ 6,632.9
Long-term Debt, Fair Value	6,980.8	7,399.7
SCEG
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	5,145.2	5,163.3
Long-term Debt, Fair Value	$ 5,295.2	$ 5,790.3

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pension and Other Postretirement Benefit Plans
Pension Contributions			No
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 5.9	$ 5.7	$ 15.8	$ 16.3
Interest cost	8.5	9.2	25.6	28
Expected return on assets	(14)	(13.4)	(42.6)	(41)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.4	0.4	1.2
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.7	4.4	9.6	12.2
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	4.2	6.3	8.8	16.7
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.1	1	3.4	3.4
Interest cost	2.2	2.8	7.6	8.6
Expected return on assets	0	0	0	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0	0	0	0
Defined Benefit Plan, Actuarial Net (Gains) Losses	(0.5)	0	0.6	0.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	2.8	3.8	$ 11.6	12.8
SCEG
Pension and Other Postretirement Benefit Plans
Pension Contributions			No
SCEG | Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	4.8	4.8	$ 12.9	13.6
Interest cost	7.2	7.8	21.6	24
Expected return on assets	(11.8)	(11.4)	(36)	(35)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.3	0.3	1
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.1	3.7	8.1	10.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	3.4	5.2	6.9	14
SCEG | Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	0.9	0.8	2.7	2.8
Interest cost	1.7	2.3	6	7.1
Expected return on assets	0	0	0	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0	0	0	0
Defined Benefit Plan, Actuarial Net (Gains) Losses	(0.4)	0	0.5	0.6
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 2.2	$ 3.1	$ 9.2	$ 10.5

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Details)	3 Months Ended				9 Months Ended		12 Months Ended
	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Commitments and contingencies
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 31,000,000
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments		$ 180,000,000			180,000,000
Sales and Excise Tax Payable		410,000,000			410,000,000
Utilities Operating Loss, Impairment, Net of Taxes		3,700,000,000	$ 2,700,000					$ 690,000,000
Impairment loss write off		3,960,000,000
Regulatory Request to Lower Revenues	$ 279,000,000				445,000,000
Utilities Operating Expense, Impairments		0	$ 3,600,000	$ 210,000,000	4,000,000	$ 210,000,000		1,118,000,000
Remaining Impairment Loss		5,000,000,000
Long-term Line of Credit		1,800,000,000			1,800,000,000
Costs Not to Be Recovered, Alternate Merger Plan		2,300,000,000			$ 2,300,000,000
Estimated Percentage Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances					14.00%
SCPSC Order Percentage Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances					5.00%
Long-term Debt, Current Maturities		18,000,000			$ 18,000,000			727,000,000
Short-term borrowings		314,000,000			314,000,000			350,000,000
Impairment Cost, Additional Liabilities, Post Merger					1,700,000,000
Transmission Assets related to BLRA Capital Costs		376,000,000			376,000,000
Impairment Cost, Additional Liabilities, Post Merger Utility Plant Alternative Plan					86,000,000
Customer Fees, Refunds Payments, Additional Liability Alternative Plan		1,880,000,000			1,880,000,000
Impairment Cost, Additional Liabilities, Post Merger Utility Plant					86,000,000
Monetization Settlement Exceeding Costs Incurred, Post Merger		1,000,000,000			1,000,000,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery					0.035
Guarantee Settlement Receipts					2,200,000,000
Asset Impairment Charges					4,000,000	210,000,000
Monetization Settlement Exceeding Costs Incurred					1,997,000,000
Estimate of aggregate amount of subcontractor and vendor liens filed					290,000,000
Estimated Litigation Liability		75,000,000			75,000,000
Operating Leases, Future Minimum Payments Due		9,000,000			9,000,000
Summer Station Unit 2 and Unit 3 [Domain]
Commitments and contingencies
Customer Refundable Fees, Refund Payments, Post Merger					1,300,000,000
Customer Refundable Fees, Alternative Plan					1,910,000,000
Customer Refundable Fees, Alternative Plan over 20 yrs					1,000,000,000
Customer Credits, Alternative Plan over 10 yrs					880,000,000
Debt Instrument, Periodic Payment, Interest					335,000,000
Short-term borrowings		314,000,000			314,000,000
Impairment Cost, Additional Liabilities, Post Merger					800,000,000
Unrecovered Nuclear Project Costs		4,140,000,000			4,140,000,000
Impairment Cost, Additional Liabilities, Post Merger Alternative Plan					1,368,000,000
SCEG
Commitments and contingencies
Regulatory Request to Lower Revenues					2,100,000,000
Utilities Operating Expense, Impairments				$ 210,000,000	4,000,000	210,000,000
Long-term Line of Credit		1,200,000,000			1,200,000,000
Long-term Debt, Current Maturities		14,000,000			14,000,000			723,000,000
Short-term borrowings		173,000,000			173,000,000			$ 252,000,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery					1,300,000
Guarantee Settlement Receipts					1,200,000,000
Asset Impairment Charges					4,000,000	$ 210,000,000
Monetization Settlement Exceeding Costs Incurred					1,098,000,000
Estimate of aggregate amount of subcontractor and vendor liens filed					33,000,000
Operating Leases, Future Minimum Payments Due		3,000,000			3,000,000
Nuclear Insurance
Maximum liability assessment per reactor for each nuclear incident					127,300,000
Maximum Insurance Coverage For Each Nuclear Plant by ANI		450,000,000			450,000,000
Federal Limit on Public Liability Claims from Nuclear Incident Approximate					13,100,000,000
Maximum Federal Limit on Public Liability Claims Per Reactor for Each Year					18,900,000
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3					84,800,000
Maximum Federal Limit on Public Liability Claims Per Incident for Each Year					$ 12,600,000
Inflation adjustment period for nuclear insurance					5
NEIL Maximum Insurance Coverage To Nuclear Facility For Property Damage And Outage Costs From Non-Nuclear Event					$ 2,330,000,000
NEIL Maximum Insurance Coverage of Accidental Property Damage		2,750,000,000			2,750,000,000
EMANI Maximum Retrospective Premium Assessment					2,000,000
EMANI Maximum Insurance Coverage for Summer Station Unit 1 For Property Damage And Outage Costs From Non-Nuclear Event					415,000,000
NEIL Maximum Prosepective Insurance Premium Per Nuclear Incident					23,400,000
NEIL Maximum Insurance Coverage to Nuclear Facility for Property Damage and Outage Costs		2,750,000,000			2,750,000,000
Environmental
Environmental Remediation Costs Recognized in Regulatory Assets		$ 23,600,000			$ 23,600,000
Number of MGP decommissioned sites that contain residues of byproduct chemicals		4			4
Number Of States Required To Reduce Emissions Under CSAPR		28			28
Site Contingency MGP Estimated Environmental Remediation Costs					$ 9,600,000
Environmental Exit Costs, Reasonably Possible Additional Loss					8,000,000
SCEG | SCEG
Commitments and contingencies
Debt Instrument, Periodic Payment, Interest					255,000,000
Short-term borrowings		$ 173,000,000			173,000,000
Summer Station Unit 2 and Unit 3 [Domain]
Commitments and contingencies
Transmission Assets related to BLRA Capital Costs		$ 365,000,000			365,000,000
Estimate of aggregate amount of subcontractor and vendor liens filed					$ 60,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share		55.00%			55.00%
Summer Station Unit 2 and Unit 3 [Domain]
Commitments and contingencies
Impairment Cost, Additional Liabilities, Post Merger, Net of Tax	$ 1,000,000,000						$ 1,000,000,000
Impairment Cost, Additional Liabilities, Post Merger Alternate Plan							$ 2,300,000,000

SEGMENT OF BUSINESS INFORMATI_3

SEGMENT OF BUSINESS INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Electric Regulated Revenue	$ 669			$ 786			$ 1,767	$ 2,042
Revenues	0			0			0	0
Net Income (Loss) Available to Common Stockholders, Basic	67	$ 8	$ 169	34	$ 121	$ 171	244	326
Operating Income	183			122			475	693
Regulated Operating Revenue, Gas	122			123			631	584
Regulated and Unregulated Operating Revenue	926			1,076			2,948	3,249
Segment Assets	18,816						18,816		$ 18,739
Electric Operations
Segment Reporting Information [Line Items]
Electric Regulated Revenue				786				2,042
Revenues	0			1			3	4
Operating Income	217			127			396	555
Segment Assets	12,046						12,046		11,979
Gas Distribution
Segment Reporting Information [Line Items]
Revenues	0			0			1	1
Operating Income	(10)			(7)			107	110
Regulated and Unregulated Operating Revenue	122			123			631	584
Segment Assets	3,384						3,384		3,259
Gas Marketing [Member]
Segment Reporting Information [Line Items]
Revenues	35			35			95	93
Net Income (Loss) Available to Common Stockholders, Basic	1			1			21	17
Regulated and Unregulated Operating Revenue	135			167			550	623
Segment Assets	204						204		230
All Other [member]
Segment Reporting Information [Line Items]
Revenues	124			90			347	286
Net Income (Loss) Available to Common Stockholders, Basic	(30)			(7)			(79)	(14)
Operating Income	0			0			0	0
Regulated and Unregulated Operating Revenue	0			0			0	0
Segment Assets	1,071						1,071		1,042
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Revenues	(159)			(126)			(446)	(384)
Net Income (Loss) Available to Common Stockholders, Basic	96			40			302	323
Operating Income	(24)			2			(28)	28
Regulated and Unregulated Operating Revenue	0			0			0	0
Segment Assets	2,111						2,111		2,229
SCEG
Segment Reporting Information [Line Items]
Electric Regulated Revenue	669			786			1,767	2,042
Operating Income	212			124			440	597
Regulated Operating Revenue, Gas	69			69			303	284
Net Income (Loss) Attributable to Parent	98			39			248	270
Regulated Operating Revenue	739			856			2,074	2,331
Segment Assets	16,129						16,129		15,946
SCEG | Electric Operations
Segment Reporting Information [Line Items]
Electric Regulated Revenue				787				2,046
Operating Income	216			126			396	555
Regulated Operating Revenue	670						1,770
Segment Assets	12,046						12,046		11,979
SCEG | Gas Distribution
Segment Reporting Information [Line Items]
Operating Income	(4)			(2)			44	42
Regulated and Unregulated Operating Revenue				69			304	285
Regulated Operating Revenue	69						303
Segment Assets	909						909		869
SCEG | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Operating Income	0			0			0	0
Regulated and Unregulated Operating Revenue	0			0			0	0
Net Income (Loss) Attributable to Parent	98			$ 39			248	$ 270
Segment Assets	$ 3,174						$ 3,174		$ 3,098

AFFILIATED TRANSACTIONS (Detail

AFFILIATED TRANSACTIONS (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Related Party Transaction [Line Items]
Advances to Affiliate	$ 71,000,000		$ 71,000,000
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Due from (to) Related Party	$ 8,500,000		$ 8,500,000		$ 4,900,000
Equity Method Investment, Ownership Percentage	40.00%		40.00%
Related Party Transaction, Purchases from Related Party	$ 45,200,000	$ 47,500,000	$ 122,500,000	$ 144,900,000
Sales to Affiliates	44,900,000	47,200,000	121,800,000	144,000,000
Due to Related Parties	8,500,000		8,500,000		4,900,000
Energy Marketing [Member]
Related Party Transaction [Line Items]
Due to Affiliate, Current	10,600,000		10,600,000		10,000,000
Related Party Transaction, Purchases from Related Party	35,000	35,300,000	95,000,000	93,400,000
SCANA Services [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	72,900,000	$ 78,100,000	208,300,000	$ 233,600,000
Accounts Payable, Related Parties, Current	42,800,000		42,800,000		42,000,000
SCEG
Related Party Transaction [Line Items]
Due to Affiliate, Current	259,000,000		259,000,000		102,000,000
Due from Affiliate, Current	$ 186,000,000		$ 186,000,000		$ 32,000,000

OTHER INCOME (EXPENSE), NET O_2

OTHER INCOME (EXPENSE), NET Other Income (Expense) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue from Contract with Customer, Including Assessed Tax	$ 4		$ 14
Other income	8	$ 28	144	$ 61
Other Nonoperating Expense	(14)	(9)	(34)	(33)
Public Utilities, Allowance for Funds Used During Construction, Additions	5	0	12	17
Other Nonoperating Income (Expense)	3	19	136	45
SCEG
Revenue from Contract with Customer, Including Assessed Tax	1		4	0
Other income	5	21	135	36
Other Nonoperating Expense	(10)	(7)	(22)	(23)
Public Utilities, Allowance for Funds Used During Construction, Additions	3	(3)	7	13
Other Nonoperating Income (Expense)	$ (1)	$ 11	124	$ 26
Other Income [Member] | Interest Rate Contract | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income			$ 115