Dominion Energy South Carolina (SCG) 10-K 23 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 20, 2018	Jun. 30, 2017
Document Information [Line Items]
Entity Registrant Name	SCANA CORP
Entity Central Index Key	754,737
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		142,638,371
Entity Public Float			$ 9,542,487,952
SCE&G
Document Information [Line Items]
Entity Registrant Name	SOUTH CAROLINA ELECTRIC & GAS CO
Entity Central Index Key	91,882
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding	40,296,147

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Assets
Utility Plant In Service	$ 14,370	$ 13,444
Accumulated Depreciation and Amortization	(4,611)	(4,446)
Construction Work in Progress	471	4,845
Nuclear Fuel, Net of Accumulated Amortization	208	271
Goodwill, Net of Writedown of $230	210	210
Utility Plant, Net	10,648	14,324
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	270	276
Assets held in trust, net-nuclear decommissioning	136	123
Other investments	68	76
Nonutility Property and Investments, Net	474	475
Current Assets:
Cash and cash equivalents	409	208
Receivables, net of allowance for uncollectible accounts	665	616
Income taxes	198	142
Accounts and Other Receivables, Net, Current	105	127
Inventories (at average cost):
Fuel	143	136
Materials and supplies	161	155
Prepaid Expense	99	105
Derivative financial instrument		0
Other Assets, Current	17	17
Total Current Assets	1,851	1,506
Deferred Debits and Other Assets:
Regulatory assets	5,580	2,130
Other	186	272
Regulated Entity, Other Assets, Noncurrent	5,766	2,402
Total	18,739	18,707
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,390	2,390
Retained Earnings, Unappropriated	2,915	3,384
Accumulated Other Comprehensive Income (Loss), Net of Tax	(50)	(49)
Common equity	5,255	5,725
Long-term Debt, Excluding Current Maturities	5,906	6,473
Total Capitalization	11,161	12,198
Current Liabilities:
Short-term borrowings	350	941
Long-term Debt, Current Maturities	727	17
Accounts payable	438	404
Customer deposits and customer prepayments	112	168
Taxes accrued	214	201
Interest accrued	87	84
Dividends declared	86	80
Derivative financial instruments	6	35
Other	93	135
Total Current Liabilities	2,113	2,065
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,261	2,159
Asset retirement obligations	568	558
Pension and other postretirement benefits	360	373
Unrecognized tax benefits	19	219
Regulatory liabilities	3,059	930
Other	198	205
Total Deferred Credits and Other Liabilities	5,465	4,444
Commitments and Contingencies (Note 10)	0	0
Total	18,739	18,707
SCE&G
Assets
Utility Plant In Service	12,161	11,510
Accumulated Depreciation and Amortization	(4,124)	(3,991)
Construction Work in Progress	375	4,813
Nuclear Fuel, Net of Accumulated Amortization	208	271
Utility Plant, Net	8,620	12,603
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	71	69
Assets held in trust, net-nuclear decommissioning	136	123
Other investments	2	3
Nonutility Property and Investments, Net	209	195
Current Assets:
Cash and cash equivalents	395	164
Receivables, net of allowance for uncollectible accounts	390	378
Income taxes	198	53
Due from Affiliate, Current	32	16
Accounts and Other Receivables, Net, Current	85	94
Inventories (at average cost):
Fuel	90	83
Materials and supplies	149	143
Prepayments	82	88
Derivative financial instrument	54	0
Other Assets, Current	2	1
Total Current Assets	1,477	1,020
Deferred Debits and Other Assets:
Regulatory assets	5,476	2,030
Other	164	243
Regulated Entity, Other Assets, Noncurrent	5,640	2,273
Total	15,946	16,091
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,860	2,860
Retained Earnings, Unappropriated	1,982	2,481
Accumulated Other Comprehensive Income (Loss), Net of Tax	(4)	(3)
Common equity	4,838	5,338
Stockholders' Equity Attributable to Noncontrolling Interest	142	134
Total Equity	4,980	5,472
Long-term Debt, Excluding Current Maturities	4,441	5,154
Total Capitalization	9,421	10,626
Current Liabilities:
Short-term borrowings	252	804
Long-term Debt, Current Maturities	723	12
Accounts payable	251	247
Due to Affiliate, Current	102	122
Customer deposits and customer prepayments	70	126
Taxes accrued	208	195
Interest accrued	67	68
Dividends declared	82	79
Derivative financial instruments	2	28
Other	47	55
Total Current Liabilities	1,804	1,736
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,173	1,939
Asset retirement obligations	529	522
Pension and other postretirement benefits	217	232
Unrecognized tax benefits	19	236
Regulatory liabilities	2,667	695
Other	97	89
Due to Affiliate, Noncurrent	19	16
Total Deferred Credits and Other Liabilities	4,721	3,729
Commitments and Contingencies (Note 10)	0	0
Total	$ 15,946	$ 16,091

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Public Utilities, Property, Plant and Equipment, Net	$ 10,648	$ 14,324
Regulated Entity, Other Assets, Noncurrent	5,766	2,402
Nonutility property, accumulated depreciation	133	138
Receivables, net of allowance for uncollectible accounts	6	6
Assets, Current	$ 1,851	$ 1,506
Common Stock, Shares, Outstanding	143	143
SCE&G
Public Utilities, Property, Plant and Equipment, Net	$ 8,620	$ 12,603
Regulated Entity, Other Assets, Noncurrent	5,640	2,273
Receivables, net of allowance for uncollectible accounts	4	3
Assets, Current	$ 1,477	$ 1,020
Common Stock, Shares, Outstanding	40.3	40.3
VIEs | SCE&G
Public Utilities, Property, Plant and Equipment, Net	$ 711	$ 756
Regulated Entity, Other Assets, Noncurrent	50	52
Assets, Current	$ 191	$ 85

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Revenues:
Electric Domestic Regulated Revenue	$ 2,659	$ 2,614	$ 2,551
Regulated Operating Revenue, Gas	874	788	811
Gas-nonregulated	874	825	1,018
Regulated and Unregulated Operating Revenue	4,407	4,227	4,380
Utilities Operating Expense [Abstract]
Fuel used in electric generation	594	576	660
Purchased power	80	64	52
Gas purchased for resale	1,156	1,054	1,287
Other operation and maintenance	737	755	715
Utilities Operating Expense, Impairments	1,118
Depreciation and amortization	382	371	358
Other taxes	264	254	234
Utilities Operating Expense	4,331	3,074	3,306
Gain (Loss) On Disposition Of Regulated Business Net Of Transaction Costs			234
Operating Income	76	1,153	1,308
Other Nonoperating Income (Expense)	(56)	(55)	(42)
Other Income (Expense):
Other income	79	64	75
Other expenses	(46)	(38)	(60)
Gain (Loss) On Disposition Of Unregulated Business Net Of Transaction Costs			107
Interest charges, net of allowance for borrowed funds used during construction	(363)	(342)	(318)
Allowance for equity funds used during construction	23	29	27
Total Other Expense	56	55	42
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(231)	866	1,139
Income Tax Expense (Benefit)	(112)	271	393
Income Available to Common Shareholders	$ (119)	$ 595	$ 746
Earnings Per Share, Basic and Diluted	$ (0.83)	$ 4.16	$ 5.22
Dividends Common Stock Declared	$ 350	$ 329	$ 312
Weighted Average Common Shares Outstanding (millions)
Weighted Average Number of Shares Outstanding, Basic	143	143	143
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 2.45	$ 2.30	$ 2.18
SCE&G
Operating Revenues:
Regulated Operating Revenue	$ 3,070	$ 2,986	$ 2,930
Utilities Operating Expense [Abstract]
Utilities Operating Expense, Impairments	1,118
Utilities Operating Expense	3,160	1,973	1,996
Operating Income	(90)	1,013	934
Other Income (Expense):
Other income	45	29	31
Other expenses	(25)	(24)	(31)
Interest charges, net of allowance for borrowed funds used during construction	(288)	(270)	(248)
Allowance for equity funds used during construction	15	26	25
Total Other Expense	35	31	25
Income Tax Expense (Benefit)	(171)	248	231
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(172)	526	480
Net Income (Loss) Attributable to Noncontrolling Interest	13	13	14
Earnings Available to Common Shareholder	(185)	513	466
Subsidiaries [Member] | SCE&G
Operating Revenues:
Electric Domestic Regulated Revenue	2,659	2,614	2,551
Regulated Operating Revenue, Gas	405	366	372
Utilities Operating Expense [Abstract]
Fuel used in electric generation	465	472	559
Purchased power	80	64	52
Gas purchased for resale	206	174	162
Other operation and maintenance	417	403	380
Utilities Operating Expense, Impairments	1,118
Depreciation and amortization	312	302	294
Other taxes	241	227	211
Other Nonoperating Income (Expense)	35	31	25
Other Income (Expense):
Interest charges, net of allowance for borrowed funds used during construction	(288)	(270)	(248)
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	(343)	774	711
Income Tax Expense (Benefit)	(171)	248	231
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(172)	526	480
Net Income (Loss) Attributable to Noncontrolling Interest	13	13	14
Earnings Available to Common Shareholder	(185)	513	466
Dividends Common Stock Declared	323	305	285
Affiliated Entity [Member] | SCE&G
Operating Revenues:
Electric Domestic Regulated Revenue	5	5	6
Regulated Operating Revenue, Gas	1	1	1
Utilities Operating Expense [Abstract]
Fuel used in electric generation	129	104	102
Gas purchased for resale	0	9	31
Other operation and maintenance	187	211	199
Other taxes	$ 5	$ 7	$ 6

CONSOLIDATED STATEMENTS OF INC5

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Interest charges, allowance for borrowed funds used during construction	$ 18	$ 19	$ 15
SCE&G
Interest charges, allowance for borrowed funds used during construction	$ 15	$ 18	$ 14

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Available to Common Shareholders	$ (119)	$ 595	$ 746
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Net of Tax	(7)	4	(12)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	(1)	17	(10)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	0	(1)	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	0	(1)	0
Other Comprehensive Income (Loss), Net of Tax	(1)	16	10
Net Income (Loss) Attributable to Parent [Abstract]
Total Comprehensive Income (Loss)	(120)	611	756
SCE&G
Other Comprehensive Income (Loss), Net of Tax			0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(172)	526	480
Other Comprehensive Income (Loss)
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax	0		0
Less comprehensive income attributable to noncontrolling interest	13	13	14
Net Income (Loss) Attributable to Parent [Abstract]
Total Comprehensive Income (Loss)	(173)	526	480
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	(172)	526	480
SCEG excluding VIEs [Member]
Income Available to Common Shareholders	(185)	513	466
Net Income (Loss) Attributable to Parent [Abstract]
Total Comprehensive Income (Loss)	(185)	513	466
Interest Rate Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	7	7	7
Commodity Contract [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (1)	$ 6	$ 15

CONSOLIDATED STATEMENTS OF COM7

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ 2	$ 2	$ (7)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	4	4	4
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax	4	4	9
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	$ 0	$ 0	$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flows from Operating Activities
Net Income (Loss) Available to Common Stockholders, Basic	$ (119)	$ 595	$ 746
Adjustments to reconcile net income to net cash provided from operating activities:
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal			(355)
Utilities Operating Expense, Impairments	1,118
Deferred income taxes, net	(911)	242	(31)
Depreciation and amortization	406	389	368
Amortization of nuclear fuel	44	57	46
Allowance for equity funds used during construction	(23)	(29)	(27)
Carrying cost recovery	(34)	(17)	(12)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	56	112	(188)
Increase (Decrease) in Income Taxes Receivable	(56)	(142)
Increase (Decrease) in Inventories	93	43	16
Increase (Decrease) in Prepaid Expense	5	(11)	(211)
Increase (Decrease) in Other Regulatory Assets	(181)	114	31
Increase (Decrease) in Regulatory liabilities	1,051	(2)	(1)
Increase (Decrease) in Accounts Payable	24	44	(78)
Unrecognized tax benefits, increase (decrease)	(224)	175	31
Increase (Decrease) in Taxes accrued	13	(41)	61
Increase (Decrease) in Obligation, Pension and Other Postretirement Benefits	(20)	51	(6)
Increase (Decrease) in Derivative Assets and Liabilities	(3)	(9)	(9)
Changes in other assets	47	44	3
Changes in other liabilities	(77)	81	(23)
Net Cash Provided from Operating Activities	1,169	1,092	1,059
Cash Flows From Investing Activities
Property additions and construction expenditures	(1,225)	(1,579)	(1,153)
Proceeds from Sale of Property, Plant, and Equipment		0	647
Proceeds from Sale of Other Receivables	1,096
Proceeds from investments (including derivative collateral posted)	145	860	1,117
Purchase of investments (including derivative collateral posted)	(143)	(788)	(1,018)
Payments upon interest rate contract settlement	(39)	(113)	(263)
Payments for (Proceeds from) Hedge, Investing Activities			10
Net Cash Used for Investing Activities	(166)	(1,620)	(660)
Cash Flows from Financing Activities
Proceeds from Issuance of Common Stock			14
Proceeds from issuance of long-term debt	150	592	491
Repayments of Long-term Debt	(17)	(117)	(166)
Dividends	(344)	(325)	(309)
Short-term borrowings, net	(591)	410	(387)
Proceeds from (Payments for) Other Financing Activities	0	0	(3)
Net Cash Provided From Financing Activities	(802)	560	(360)
Net (Decrease) Increase in Cash and Cash Equivalents	201	32	39
Cash and Cash Equivalents, January 1	208	176	137
Cash and Cash Equivalents, December 31	409	208	176
Supplemental Cash Flow Information
Cash paid for-Interest (net of capitalized interest )	346	328	306
Cash paid for-Income taxes	2	229	184
Proceeds from Income Tax Refunds	184	166
Cash Flow, Noncash Investing and Financing Activities Disclosure
Accrued construction expenditures	139	109	244
Capital Lease Obligations Incurred	8	15	6
SCE&G
Cash Flows from Operating Activities
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(172)	526	480
Adjustments to reconcile net income to net cash provided from operating activities:
Utilities Operating Expense, Impairments	1,118
Deferred income taxes, net	(780)	207	8
Depreciation and amortization	323	310	294
Amortization of nuclear fuel	44	57	46
Allowance for equity funds used during construction	(15)	(26)	(25)
Carrying cost recovery	(34)	(17)	(12)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	32	47	(85)
Increase (Decrease) in Due from Affiliates, Current	12	(3)	16
Increase (Decrease) in Income Taxes Receivable	(145)	(53)
Increase (Decrease) in Inventories	60	35	24
Increase (Decrease) in Prepaid Expense	(6)	4	(70)
Increase (Decrease) in Other Regulatory Assets	(185)	94	29
Increase (Decrease) in Regulatory liabilities	899	(5)	(3)
Increase (Decrease) in Accounts Payable	20	8	11
Unrecognized tax benefits, increase (decrease)	(241)	192	31
Increase (Decrease) in Due to Affiliates, Current	(28)	13	(17)
Increase (Decrease) in Taxes accrued	13	(104)	129
Increase (Decrease) in Obligation, Pension and Other Postretirement Benefits	(21)	39	(5)
Changes in other assets	46	99	(57)
Changes in other liabilities	(43)	58	(28)
Increase (Decrease) in Due to Affiliates	3	(1)	(6)
Net Cash Provided from Operating Activities	1,006	922	1,078
Cash Flows From Investing Activities
Property additions and construction expenditures	(928)	(1,399)	(1,008)
Proceeds from Sale of Other Receivables	1,096
Proceeds from investments (including derivative collateral posted)	118	794	975
Purchase of investments (including derivative collateral posted)	(122)	(740)	(887)
Payments upon interest rate contract settlement	(39)	(113)	(263)
Payments for (Proceeds from) Hedge, Investing Activities		0	10
Proceeds from Investment In Affiliate	0	9	71
Investment In Affiliate	(28)
Net Cash Used for Investing Activities	97	(1,449)	(1,102)
Cash Flows from Financing Activities
Proceeds from issuance of long-term debt	0	494	491
Repayments of Long-term Debt	(12)	(112)	(11)
Dividends	(319)	(301)	(285)
Short-term borrowings, net	(552)	384	(289)
Short-term borrowings-affiliate,net	8	(4)	(50)
Contributions from parent	3	100	204
Payment to Parent representing the return of Contribution Proceeds	0		(4)
Proceeds from (Payments for) Other Financing Activities	0		(2)
Net Cash Provided From Financing Activities	(872)	561	54
Net (Decrease) Increase in Cash and Cash Equivalents	231	34	30
Cash and Cash Equivalents, January 1	164	130	100
Cash and Cash Equivalents, December 31	395	164	130
Supplemental Cash Flow Information
Cash paid for-Interest (net of capitalized interest )	269	251	228
Cash paid for-Income taxes	47	289	89
Proceeds from Income Tax Refunds	145	189	84
Cash Flow, Noncash Investing and Financing Activities Disclosure
Accrued construction expenditures	99	95	230
Capital Lease Obligations Incurred	$ 8	$ 14	$ 6

CONSOLIDATED STATEMENTS OF CAS9

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parentheticals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash paid for interest, capitalized interest	$ 18	$ 19	$ 15
SCE&G
Cash paid for interest, capitalized interest	$ 15	$ 18	$ 14

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON EQUITY - USD ($) shares in Millions, $ in Millions	Total	AOCI Attributable to Parent [Member]	SCE&G	SCEG excluding VIEs [Member]	SCEG and GENCO [Member]	Subsidiaries [Member]SCE&G
Common Stock, Value, Outstanding				$ 2,560
Stockholders' Equity Attributable to Noncontrolling Interest					$ 123
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			$ 4,757
Stockholders' Equity Attributable to Parent at Dec. 31, 2014	$ 4,987
Shares, Outstanding at Dec. 31, 2014	143			40
Stockholders' Equity before Treasury Stock at Dec. 31, 2014	$ 2,388
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2014	(63)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax at Dec. 31, 2014	(12)
Retained Earnings, Unappropriated at Dec. 31, 2014	2,684			$ 2,077
Treasury Stock, Value at Dec. 31, 2014	(10)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2014	$ (75)			(3)
Stock Issued During Period, Shares, New Issues	0
Stock Issued During Period, Value, Other	$ 14
Stock Repurchased During Period, Value	2
Common stock issued	12
Dividends, Common Stock	(312)					$ (285)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	10
Net Income (Loss) Attributable to Noncontrolling Interest			14		14	14
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			480			480
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent			0	0
Contributions from parent			204		0
Dividends			(286)	(278)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(8)
Other Comprehensive Income (Loss), Net of Tax	10		0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(12)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	22
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Reclassified During Period, Net of Tax	0		0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	756		480	466
Proceeds from Contribution from Parent, net of return of Proceeds			200	200
Income Available to Common Shareholders	$ 746			$ 466
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 2.18
Shares, Outstanding at Dec. 31, 2015	143			40
Stockholders' Equity before Treasury Stock at Dec. 31, 2015	$ 2,402
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2015	(53)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax at Dec. 31, 2015	(12)
Retained Earnings, Unappropriated at Dec. 31, 2015	3,118			$ 2,265
Treasury Stock, Value at Dec. 31, 2015	(12)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2015	(65)			(3)
Stockholders' Equity Attributable to Parent at Dec. 31, 2015	5,443
Common Stock, Value, Outstanding				2,760
Stockholders' Equity Attributable to Noncontrolling Interest					129
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			5,151
AOCI before Tax, Attributable to Parent	(22)	$ (12)
Dividends, Common Stock	(329)					(305)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	17
Net Income (Loss) Attributable to Noncontrolling Interest			13		13	13
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			526			526
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent			0	0
Contributions from parent			100		0
Dividends			(305)	(297)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(8)
Other Comprehensive Income (Loss), Net of Tax	16
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	4
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	(1)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	13
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Reclassified During Period, Net of Tax	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	611		526	513
Proceeds from Contribution from Parent, net of return of Proceeds			100	100
Income Available to Common Shareholders	$ 595			$ 513
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 2.30
Shares, Outstanding at Dec. 31, 2016	143			40
Stockholders' Equity before Treasury Stock at Dec. 31, 2016	$ 2,402
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2016	(36)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax at Dec. 31, 2016	(13)
Retained Earnings, Unappropriated at Dec. 31, 2016	3,384		2,481	$ 2,481
Treasury Stock, Value at Dec. 31, 2016	(12)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2016	(49)			(3)
Stockholders' Equity Attributable to Parent at Dec. 31, 2016	5,725		5,338
Common Stock, Value, Outstanding	2,390		2,860	2,860
Stockholders' Equity Attributable to Noncontrolling Interest			134		134
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			5,472
AOCI before Tax, Attributable to Parent	(13)	3
Dividends, Common Stock	(350)					(323)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(1)
Net Income (Loss) Attributable to Noncontrolling Interest			13		13	13
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			(172)			$ (172)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent			(1)	(1)
Contributions from parent			3		3
Dividends			(322)	(314)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(8)
Other Comprehensive Income (Loss), Net of Tax	(1)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(7)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	6
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Reclassified During Period, Net of Tax	0		0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(120)		(173)	(185)
Proceeds from Contribution from Parent, net of return of Proceeds	3			0
Income Available to Common Shareholders	$ (119)			$ (185)
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 2.45
Shares, Outstanding at Dec. 31, 2017	143			40
Stockholders' Equity before Treasury Stock at Dec. 31, 2017	$ 2,402
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2017	(37)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax at Dec. 31, 2017	(13)
Retained Earnings, Unappropriated at Dec. 31, 2017	2,915		1,982	$ 1,982
Treasury Stock, Value at Dec. 31, 2017	(12)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2017	(50)			(4)
Stockholders' Equity Attributable to Parent at Dec. 31, 2017	5,255		4,838
Common Stock, Value, Outstanding	2,390		2,860	$ 2,860
Stockholders' Equity Attributable to Noncontrolling Interest			142		$ 142
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			$ 4,980
AOCI before Tax, Attributable to Parent	$ (6)	$ (7)

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2017
Significant Accounting Policies
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization and Principles of Consolidation The Company SCANA, a South Carolina corporation, is a holding company. The Company engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina, the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia and conducts other energy-related business. The accompanying consolidated financial statements reflect the accounts of SCANA, the following wholly-owned subsidiaries, and subsidiaries that formerly were wholly-owned during the periods presented. Regulated businesses Nonregulated businesses South Carolina Electric & Gas Company SCANA Energy Marketing, Inc. South Carolina Fuel Company, Inc. SCANA Services, Inc. South Carolina Generating Company, Inc. SCANA Corporate Security Services, Inc. Public Service Company of North Carolina, Incorporated SCANA Communications Holdings, Inc. SCANA reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. Discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. Consolidated SCE&G SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA, a South Carolina corporation. Consolidated SCE&G engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina. SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $503 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 4. Dispositions In the first quarter of 2015, SCANA sold CGT and SCI. CGT was an interstate natural gas pipeline regulated by FERC that transported natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provided fiber optic communications and other services and built, managed and leased communications towers in several southeastern states, and it was sold to Spirit Communications. These sales resulted in recognition of pre-tax gains totaling approximately $342 million . The pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the Company's consolidated statement of operations. CGT and SCI operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment. The sales of CGT and SCI did not represent a strategic shift that had a major effect on the Company's operations; therefore, these sales did not meet the criteria for classification as discontinued operations. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. No estimate is made for legal costs expected to be incurred in connection with loss contingencies. Such costs are recorded when incurred. Utility Plant Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense. AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 5.6% for 2017, 5.3% for 2016, and 6.1% for 2015. Consolidated SCE&G calculated AFC using average composite rates of 3.9% for 2017, 4.7% for 2016, and 5.6% for 2015. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred. Provisions for depreciation and amortization are recorded using the straight-line method based on the estimated service lives of the various classes of property, and in most cases, include provisions for future cost of removal. In 2015, SCE&G adopted lower depreciation rates for electric and common plant, as approved by the SCPSC and further described in Note 2. In addition, CGT was sold in the first quarter of 2015 (see Dispositions herein) and excluded from the 2015 calculation of composite weighted average depreciation rates. The composite weighted average depreciation rates for utility plant assets were as follows: 2017 2016 2015 SCE&G 2.55 % 2.56 % 2.55 % GENCO 2.66 % 2.66 % 2.66 % PSNC Energy 3.03 % 2.90 % 2.94 % Weighted average of above 2.63 % 2.61 % 2.61 % Consolidated SCE&G 2.55 % 2.56 % 2.56 % SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in Fuel used in electric generation and recovered through the fuel cost component of retail electric rates. Jointly Owned Utility Plant SCE&G jointly owns and is the operator of Unit 1. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. Unit 2 and Unit 3 have been reclassified from construction work in progress to a regulatory asset as a result of the decision to stop their construction. See additional discussion at Note 2. As of December 31, 2017 2016 Unit 1 Unit 1 Unit 2 and Unit 3 Percent owned 66.7% 66.7% 55.0% Plant in service $ 1.5 billion $ 1.3 billion — Accumulated depreciation $ 637.6 million $ 634.4 million — Construction work in progress $ 110.1 million $ 167.7 million $ 4.2 billion Included within other receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for the units. These amounts totaled $53.8 million at December 31, 2017 and $76.2 million at December 31, 2016. Major Maintenance Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred. SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2017, and 2016, SCE&G incurred $26.1 million and $23.8 million , respectively, for turbine maintenance. Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 million annually for its portion of the nuclear refueling outages scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which SCE&G was responsible totaled $1.8 million in 2016 in preparation for the Spring 2017 outage and $23.2 million in 2017. Goodwill The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company tests goodwill for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed. Accounting guidance adopted by the Company gives it the option to perform a qualitative assessment of impairment ("step zero"). Based on this qualitative assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to proceed with a two-step quantitative assessment. If the quantitative assessment becomes necessary, step one requires estimation of the fair value of the reporting unit and the comparison of that amount to its carrying value. If this step indicates an impairment (a carrying value in excess of fair value), then step two, measurement of the amount of the goodwill impairment (if any), is required. Should a write-down be required, such a charge would be treated as an operating expense. For each period presented, assets with a carrying value of $210 million for PSNC Energy (Gas Distribution segment), net of a writedown of $230 million taken in 2002, were classified as goodwill. The Company utilized the step zero qualitative assessment in its evaluations as of January 1, 2018 and as of January 1, 2017 and was not required to use the two-step quantitative assessment. Nuclear Decommissioning Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $786.4 million , stated in 2016 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. Under SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ( $3.2 million pre-tax in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. The asset balance held in trust reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Unit 1 on an after-tax basis. Cash and Cash Equivalents Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds. Receivables Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described below. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $220.9 million at December 31, 2017 and $178.9 million at December 31, 2016 for the Company. Unbilled revenues totaled $140.3 million at December 31, 2017 and $117.6 million at December 31, 2016 for Consolidated SCE&G. Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station. Inventories Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable. PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 39% and 40% of PSNC Energy’s natural gas inventory at December 31, 2017 and December 31, 2016, respectively, with a carrying value of $11.5 million and $9.8 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. Income Taxes SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 5 for a discussion of the impact of adjustments recorded upon enactment of the Tax Act. Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions. Regulatory Assets and Regulatory Liabilities The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods different from the periods in which the costs would be charged to expense, or record revenues in periods different from the periods in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified in the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively. Debt Issuance Premiums, Discounts and Other Costs Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges. Environmental An environmental assessment program is maintained to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred. Statement of Operations Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within Operating Income and the 2015 gain on the sale of SCI within Other Income (Expense). Revenue Recognition Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed. Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings. SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews. SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. PSNC Energy is authorized by the NCUC to utilize a CUT which allows it to adjust base rates semi-annually for residential and commercial customers based on average per customer consumption, whether impacted by weather or other factors. Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of income. Earnings (Loss) Per Share The Company computes basic earnings (loss) per share by dividing net income (loss) by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings (loss) per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. New Accounting Matters Recently Adopted In the first quarter of 2017, the Company and Consolidated SCE&G adopted the following accounting guidance issued by the FASB. The adoption of this guidance had no impact on their respective financial statements except as indicated. • Guidance issued in August 2014 requires an entity's management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern. See related disclosure at Note 10. • Guidance issued in July 2015 requires most inventory to be measured at the lower of cost and net realizable value. • Guidance issued in October 2016 requires entities to recognize the income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer occurs. 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, and its adoption had no impact on its financial statements. Pending Adoption In the first quarter of 2018, the Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB. • Guidance issued in May 2014 for revenue arising from contracts with customers supersedes most prior revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides for a five-step analysis in determining when and how revenue is recognized, and requires revenue recognition to depict the transfer of promised goods or services to customers, based on the transfer of control, in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In addition, this guidance requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The analysis of contracts with customers to which the guidance might be applicable has been completed and activities of the FASB's Transition Resource Group for Revenue Recognition, particularly as they relate to the treatment of CIAC, ARP and the collectability of revenue of utilities subject to rate regulation have been considered. Specifically, the Company and Consolidated SCE&G have concluded that their use of CIAC is outside the scope of the new revenue recognition guidance. The Company and Consolidated SCE&G have determined that aspects of SCE&G’s WNA and, for the Company, PSNC Energy's CUT allow for revenue adjustments to be recognized prior to amounts being reflected in customer bills. These revenue adjustments, which give rise to regulatory assets or liabilities, represent ARPs that are outside the scope of the new guidance and will be reported as Other operating revenue separately from revenue from contracts with customers on the statement of operations. An evaluation of the enhanced disclosure requirements is being completed, including determining the appropriate disaggregation of revenue. The Company and Consolidated SCE&G will adopt this guidance using the modified retrospective method, and comparative periods will not be restated. In connection with this adoption, the Company has determined that its gas marketing subsidiary serves as an agent for gas distribution services in its retail market. Accordingly, certain pass through charges that the Company currently records within Gas-nonregulated revenues, and which are entirely offset within Gas purchased for resale, in the future will be recorded net on the statements of operations. The Company and Consolidated SCE&G do not anticipate that the adoption of this guidance will have any material impacts on their respective financial statements, but its adoption will result in additional disclosures. The adoption of this guidance will not result in a cumulative effect adjustment to beginning retained earnings. • Guidance issued in January 2016 changes how entities measure certain equity investments and financial liabilities, among other things. Entities will be required to make a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective, with certain exceptions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will have a significant impact on their respective financial statements. • 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. The adoption of this guidance will have no impact on the financial statements of the Company and Consolidated SCE&G. • Guidance issued in November 2016 clarifies how restricted cash should be presented on the statement of cash flows, and entities must apply the guidance retrospectively to all periods presented. The adoption of this guidance will have no impact on the financial statements of the Company and Consolidated SCE&G. • Guidance issued in March 2017 changes the required presentation of net periodic pension and postretirement benefit costs. Under this guidance, such costs will be separated into service cost components and other components. The service cost components will be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components will be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component will be eligible for capitalization in assets. Entities must apply this guidance on a retrospective basis for the presentation of the service cost component and the other components, and on a prospective basis for the capitalization of only the service cost component. As permitted, service cost and other costs disclosed in related footnotes to previously issued financial statements will be used when estimating retrospective changes for such costs in the income statements for prior periods. Due to regulatory overlay, non-service cost components related to regulated operations that are capitalized in assets under current accounting guidance will be deferred within regulatory assets in the future. As a result, the adoption of this guidance will not have a material impact on the financial statements of the Company and Consolidated SCE&G. 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, and without consideration of any regulatory accounting requirements which may apply, 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 January 2018, FASB amended this accounting guidance to provide an optional transition practical expedient that would allow adopters to not evaluate under the new guidance existing or expired land easements that were not previously accounted for as leases under existing guidance. The new guidance is effective for years beginning in 2019, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements other than increasing amounts reported for assets and liabilities on the balance sheet and changing the place on their respective statements of operations on which certain expenses are recorded. No impact on net income (loss) is expected. The identification and analysis of leasing and related contracts to which the guidance might be applicable has begun. In addition, the Company and Consolidated SCE&G have begun implementation of a third party software tool that will assist with initial adoption and ongoing compliance. Specifically, preliminary system configuration has been completed and data from certain leases are being entered. 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 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, though early adoption is permitted, and have not determined what impact such adoption will have 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 must adopt this guidance beginning in 2019, including interim periods, though the guidance may be adopted earlier. The Company and Consoli
SCE&G
Significant Accounting Policies
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization and Principles of Consolidation The Company SCANA, a South Carolina corporation, is a holding company. The Company engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina, the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia and conducts other energy-related business. The accompanying consolidated financial statements reflect the accounts of SCANA, the following wholly-owned subsidiaries, and subsidiaries that formerly were wholly-owned during the periods presented. Regulated businesses Nonregulated businesses South Carolina Electric & Gas Company SCANA Energy Marketing, Inc. South Carolina Fuel Company, Inc. SCANA Services, Inc. South Carolina Generating Company, Inc. SCANA Corporate Security Services, Inc. Public Service Company of North Carolina, Incorporated SCANA Communications Holdings, Inc. SCANA reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. Discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. Consolidated SCE&G SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA, a South Carolina corporation. Consolidated SCE&G engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina. SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $503 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 4. Dispositions In the first quarter of 2015, SCANA sold CGT and SCI. CGT was an interstate natural gas pipeline regulated by FERC that transported natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provided fiber optic communications and other services and built, managed and leased communications towers in several southeastern states, and it was sold to Spirit Communications. These sales resulted in recognition of pre-tax gains totaling approximately $342 million . The pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the Company's consolidated statement of operations. CGT and SCI operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment. The sales of CGT and SCI did not represent a strategic shift that had a major effect on the Company's operations; therefore, these sales did not meet the criteria for classification as discontinued operations. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. No estimate is made for legal costs expected to be incurred in connection with loss contingencies. Such costs are recorded when incurred. Utility Plant Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense. AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 5.6% for 2017, 5.3% for 2016, and 6.1% for 2015. Consolidated SCE&G calculated AFC using average composite rates of 3.9% for 2017, 4.7% for 2016, and 5.6% for 2015. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred. Provisions for depreciation and amortization are recorded using the straight-line method based on the estimated service lives of the various classes of property, and in most cases, include provisions for future cost of removal. In 2015, SCE&G adopted lower depreciation rates for electric and common plant, as approved by the SCPSC and further described in Note 2. In addition, CGT was sold in the first quarter of 2015 (see Dispositions herein) and excluded from the 2015 calculation of composite weighted average depreciation rates. The composite weighted average depreciation rates for utility plant assets were as follows: 2017 2016 2015 SCE&G 2.55 % 2.56 % 2.55 % GENCO 2.66 % 2.66 % 2.66 % PSNC Energy 3.03 % 2.90 % 2.94 % Weighted average of above 2.63 % 2.61 % 2.61 % Consolidated SCE&G 2.55 % 2.56 % 2.56 % SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in Fuel used in electric generation and recovered through the fuel cost component of retail electric rates. Jointly Owned Utility Plant SCE&G jointly owns and is the operator of Unit 1. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. Unit 2 and Unit 3 have been reclassified from construction work in progress to a regulatory asset as a result of the decision to stop their construction. See additional discussion at Note 2. As of December 31, 2017 2016 Unit 1 Unit 1 Unit 2 and Unit 3 Percent owned 66.7% 66.7% 55.0% Plant in service $ 1.5 billion $ 1.3 billion — Accumulated depreciation $ 637.6 million $ 634.4 million — Construction work in progress $ 110.1 million $ 167.7 million $ 4.2 billion Included within other receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for the units. These amounts totaled $53.8 million at December 31, 2017 and $76.2 million at December 31, 2016. Major Maintenance Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred. SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2017, and 2016, SCE&G incurred $26.1 million and $23.8 million , respectively, for turbine maintenance. Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 million annually for its portion of the nuclear refueling outages scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which SCE&G was responsible totaled $1.8 million in 2016 in preparation for the Spring 2017 outage and $23.2 million in 2017. Goodwill The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company tests goodwill for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed. Accounting guidance adopted by the Company gives it the option to perform a qualitative assessment of impairment ("step zero"). Based on this qualitative assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to proceed with a two-step quantitative assessment. If the quantitative assessment becomes necessary, step one requires estimation of the fair value of the reporting unit and the comparison of that amount to its carrying value. If this step indicates an impairment (a carrying value in excess of fair value), then step two, measurement of the amount of the goodwill impairment (if any), is required. Should a write-down be required, such a charge would be treated as an operating expense. For each period presented, assets with a carrying value of $210 million for PSNC Energy (Gas Distribution segment), net of a writedown of $230 million taken in 2002, were classified as goodwill. The Company utilized the step zero qualitative assessment in its evaluations as of January 1, 2018 and as of January 1, 2017 and was not required to use the two-step quantitative assessment. Nuclear Decommissioning Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $786.4 million , stated in 2016 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. Under SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ( $3.2 million pre-tax in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. The asset balance held in trust reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Unit 1 on an after-tax basis. Cash and Cash Equivalents Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds. Receivables Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described below. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $220.9 million at December 31, 2017 and $178.9 million at December 31, 2016 for the Company. Unbilled revenues totaled $140.3 million at December 31, 2017 and $117.6 million at December 31, 2016 for Consolidated SCE&G. Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station. Inventories Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable. PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 39% and 40% of PSNC Energy’s natural gas inventory at December 31, 2017 and December 31, 2016, respectively, with a carrying value of $11.5 million and $9.8 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. Income Taxes SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 5 for a discussion of the impact of adjustments recorded upon enactment of the Tax Act. Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions. Regulatory Assets and Regulatory Liabilities The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods different from the periods in which the costs would be charged to expense, or record revenues in periods different from the periods in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified in the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively. Debt Issuance Premiums, Discounts and Other Costs Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges. Environmental An environmental assessment program is maintained to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred. Statement of Operations Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within Operating Income and the 2015 gain on the sale of SCI within Other Income (Expense). Revenue Recognition Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed. Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings. SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews. SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. PSNC Energy is authorized by the NCUC to utilize a CUT which allows it to adjust base rates semi-annually for residential and commercial customers based on average per customer consumption, whether impacted by weather or other factors. Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of income. Earnings (Loss) Per Share The Company computes basic earnings (loss) per share by dividing net income (loss) by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings (loss) per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. New Accounting Matters Recently Adopted In the first quarter of 2017, the Company and Consolidated SCE&G adopted the following accounting guidance issued by the FASB. The adoption of this guidance had no impact on their respective financial statements except as indicated. • Guidance issued in August 2014 requires an entity's management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern. See related disclosure at Note 10. • Guidance issued in July 2015 requires most inventory to be measured at the lower of cost and net realizable value. • Guidance issued in October 2016 requires entities to recognize the income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer occurs. 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, and its adoption had no impact on its financial statements. Pending Adoption In the first quarter of 2018, the Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB. • Guidance issued in May 2014 for revenue arising from contracts with customers supersedes most prior revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides for a five-step analysis in determining when and how revenue is recognized, and requires revenue recognition to depict the transfer of promised goods or services to customers, based on the transfer of control, in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In addition, this guidance requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The analysis of contracts with customers to which the guidance might be applicable has been completed and activities of the FASB's Transition Resource Group for Revenue Recognition, particularly as they relate to the treatment of CIAC, ARP and the collectability of revenue of utilities subject to rate regulation have been considered. Specifically, the Company and Consolidated SCE&G have concluded that their use of CIAC is outside the scope of the new revenue recognition guidance. The Company and Consolidated SCE&G have determined that aspects of SCE&G’s WNA and, for the Company, PSNC Energy's CUT allow for revenue adjustments to be recognized prior to amounts being reflected in customer bills. These revenue adjustments, which give rise to regulatory assets or liabilities, represent ARPs that are outside the scope of the new guidance and will be reported as Other operating revenue separately from revenue from contracts with customers on the statement of operations. An evaluation of the enhanced disclosure requirements is being completed, including determining the appropriate disaggregation of revenue. The Company and Consolidated SCE&G will adopt this guidance using the modified retrospective method, and comparative periods will not be restated. In connection with this adoption, the Company has determined that its gas marketing subsidiary serves as an agent for gas distribution services in its retail market. Accordingly, certain pass through charges that the Company currently records within Gas-nonregulated revenues, and which are entirely offset within Gas purchased for resale, in the future will be recorded net on the statements of operations. The Company and Consolidated SCE&G do not anticipate that the adoption of this guidance will have any material impacts on their respective financial statements, but its adoption will result in additional disclosures. The adoption of this guidance will not result in a cumulative effect adjustment to beginning retained earnings. • Guidance issued in January 2016 changes how entities measure certain equity investments and financial liabilities, among other things. Entities will be required to make a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective, with certain exceptions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will have a significant impact on their respective financial statements. • 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. The adoption of this guidance will have no impact on the financial statements of the Company and Consolidated SCE&G. • Guidance issued in November 2016 clarifies how restricted cash should be presented on the statement of cash flows, and entities must apply the guidance retrospectively to all periods presented. The adoption of this guidance will have no impact on the financial statements of the Company and Consolidated SCE&G. • Guidance issued in March 2017 changes the required presentation of net periodic pension and postretirement benefit costs. Under this guidance, such costs will be separated into service cost components and other components. The service cost components will be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components will be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component will be eligible for capitalization in assets. Entities must apply this guidance on a retrospective basis for the presentation of the service cost component and the other components, and on a prospective basis for the capitalization of only the service cost component. As permitted, service cost and other costs disclosed in related footnotes to previously issued financial statements will be used when estimating retrospective changes for such costs in the income statements for prior periods. Due to regulatory overlay, non-service cost components related to regulated operations that are capitalized in assets under current accounting guidance will be deferred within regulatory assets in the future. As a result, the adoption of this guidance will not have a material impact on the financial statements of the Company and Consolidated SCE&G. 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, and without consideration of any regulatory accounting requirements which may apply, 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 January 2018, FASB amended this accounting guidance to provide an optional transition practical expedient that would allow adopters to not evaluate under the new guidance existing or expired land easements that were not previously accounted for as leases under existing guidance. The new guidance is effective for years beginning in 2019, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements other than increasing amounts reported for assets and liabilities on the balance sheet and changing the place on their respective statements of operations on which certain expenses are recorded. No impact on net income (loss) is expected. The identification and analysis of leasing and related contracts to which the guidance might be applicable has begun. In addition, the Company and Consolidated SCE&G have begun implementation of a third party software tool that will assist with initial adoption and ongoing compliance. Specifically, preliminary system configuration has been completed and data from certain leases are being entered. 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 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, though early adoption is permitted, and have not determined what impact such adoption will have 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 must adopt this guidance beginning in 2019, including interim periods, though the guidance may be adopted earlier. The Company and Consolid

RATE AND OTHER REGULATORY MATTE

RATE AND OTHER REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2017
Rate Matters [Line Items]
Schedule of Regulatory Assets and Liabilities [Text Block]	RATE AND OTHER REGULATORY MATTERS Rate Matters Electric - Cost of Fuel SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties in which SCE&G agreed to decrease the total fuel cost component of retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, over the subsequent 12-month period beginning with the first billing cycle of May 2015. By order dated July 15, 2015, the SCPSC approved SCE&G's participation in a DER program and recovery of related costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G is to implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately 84.5 MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity. This nameplate capacity goal was achieved in 2017. By order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G reduced the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G also began to recover projected DER program costs of approximately $6.9 million beginning with the first billing cycle of May 2016. By order dated April 27, 2017, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component to produce a projected under recovery of $61.0 million over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately $16.5 million . Additionally, deferral of carrying costs will be allowed for base fuel component under-collected balances as they occur. In October 2017, the SCPSC initiated its 2018 annual review of base rates for fuel costs. A public hearing for this annual review is scheduled for April 10, 2018. Electric - Base Rates Pursuant to an SCPSC order, SCE&G has removed from rate base certain deferred income tax assets arising from capital expenditures related to Unit 2 and Unit 3 and accrued carrying costs on those amounts during periods in which they were not included in rate base. Such carrying costs were determined at SCE&G’s weighted average long-term debt borrowing rate and were recorded as a regulatory asset and other income. Carrying costs totaled $18.8 million and $14.0 million during 2017 and 2016, respectively. As part of the impairment loss described in Note 10, accumulated carrying costs related to the Nuclear Project totaling $51.0 million were written off. The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues (both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below: Year Effective Amount 2017 First billing cycle of May $37.0 million 2016 First billing cycle of May $37.6 million 2015 First billing cycle of May $32.0 million By order dated April 29, 2016, the SCPSC approved SCE&G’s request to increase its pension costs rider. The increased pension rider was designed to allow SCE&G to recover projected pension costs, including under-collections, over a 12-month period, beginning with the first billing cycle in May 2016. By order dated March 1, 2017, the SCPSC approved SCE&G’s request to decrease its pension costs rider. The change in the pension rider decreased annual revenue by approximately $11.9 million . The pension rider is designed to allow SCE&G to recover projected pension costs, net of the previously over-collected balance, over a 12-month period, beginning with the first billing cycle in May 2017. In December 2017, the ORS filed a petition with the SCPSC requesting all investor-owned utilities under the SCPSC’s jurisdiction to report the impact of the Tax Act on their individual company’s operations. The Tax Act contains provisions that lower the federal corporate tax rate from 35% to 21% effective January 1, 2018. The petition requested that utilities file an estimate of the Tax Act’s effects on their most recent test year information available, including an explanation of those effects, and requested that utilities propose procedures for changing rates to reflect the impacts. Lastly, the petition requested that the SCPSC state in its order that rates in effect as of January 1, 2018, be subject to refund so that ratepayers receive the benefit of the tax law changes as of January 1, 2018. By order dated January 10, 2018, the SCPSC granted the ORS petition but did not state that rates in effect as of January 1, 2018 would be subject to refund. SCE&G provided its comments on January 24, 2018, concerning the timing and the format of the report. In January 2018, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved the filing would allow recovery of $37.0 million of costs and net lost revenues associated with DSM programs, along with an incentive to invest in such programs. Electric - BLRA and Joint Petition Under the BLRA, SCE&G filed revised rates with the SCPSC in 2015 and 2016 to incorporate the financing cost of incremental construction work in progress incurred for the Nuclear Project. Rate adjustments were based on SCE&G's updated cost of debt and capital structure and on an allowed ROE. No revised rates filing was pursued in 2017. The SCPSC approved recovery of the following amounts. Increase Effective for bills rendered on and after Amount Allowed ROE 2.7% November 27, 2016 $64.4 million 10.50% * 2.6% October 30, 2015 $64.5 million 11.00% *Applied prospectively for purposes of calculating revised rates under the BLRA on and after January 1, 2016. In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for Unit 2 and Unit 3 which had been developed in connection with the October 2015 Amendment (see Note 10). On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, the ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option. By order dated February 28, 2017, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement, and that denial was not appealed. The construction schedule approved by the SCPSC in November 2016 provided for contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Unit 2 and Unit 3, respectively. The approved capital cost schedule included incremental capital costs that totaled $831 million , raising SCE&G’s total project capital cost as then approved to an estimated amount of approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for the Nuclear Project from 10.5% to 10.25% . This revised ROE was to be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. In addition, SCE&G could not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request was denied because SCE&G was out of compliance with its approved capital cost schedule or BLRA construction milestone schedule, subject to certain extensions. See also Abandoned Nuclear Project in Note 10. Following WEC and WECTEC's bankruptcy filing on March 29, 2017, on June 22, 2017, the Friends of the Earth and the Sierra Club filed a complaint against SCE&G with the SCPSC, requesting that the SCPSC initiate a formal proceeding to direct SCE&G to immediately cease and desist from expending any further capital costs related to the construction of Unit 2 and Unit 3; to determine the prudence of acts and omissions by SCE&G in connection with this construction; to review and determine the prudence of abandonment of Unit 2 and Unit 3 and of the available least cost efficiency and renewable energy alternatives; and to remedy, abate and make due reparations for the rates charged to ratepayers related to the construction of Unit 2 and Unit 3. SCE&G filed its answer to the complaint and a motion to dismiss the complaint on July 19, 2017. On October 4, 2017, the SCPSC ordered proceedings under this complaint to be coordinated with proceedings for the Request filed by the ORS on September 26, 2017, described below, and allowed discovery to proceed. SCE&G's subsequent petition for rehearing and reconsideration was denied by the SCPSC on November 1, 2017. Proceedings related to this complaint have been consolidated with proceedings for the Request and the Joint Petition as described below. On August 1, 2017, SCE&G filed the Abandonment Petition with the SCPSC which sought recovery of costs expended on the construction of Unit 2 and Unit 3, including certain costs incurred subsequent to SCE&G's last revised rates update, other costs under the abandonment provisions of the BLRA, and affirmation of SCE&G's decision to abandon construction of Unit 2 and Unit 3, among other things. Subsequently, SCE&G management met with various stakeholders and members of the South Carolina General Assembly, including legislative leaders, to discuss the abandonment of the Nuclear Project and to hear their concerns. In response to those concerns, and to allow adequate time for governmental officials to conduct their reviews, SCE&G voluntarily withdrew the Abandonment Petition on August 15, 2017. See additional discussion at Note 10. 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, the ORS filed the Request with the SCPSC asking for an order directing SCE&G to immediately suspend all revised rates collections from customers which had been previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS relied upon the opinion from the Office of Attorney General to assert that it is not just and reasonable or in the public interest to allow SCE&G to continue collecting revised rates. Further, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS that should have been disclosed and that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the 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 September 28, 2017, SCE&G filed a Motion to Dismiss the Request and a Request for Briefing Schedule and Hearing on Motion to Dismiss. On September 28, 2017, the SCPSC deferred action on the Request and ordered a hearing officer to establish a briefing schedule and hearing date on SCE&G's motion. On October 17, 2017, the ORS filed with the SCPSC a motion to amend its request, in which 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. A hearing on the parties' motions was held on December 12, 2017, and included the state's Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, a large industrial customer, and several environmental groups. By order dated December 20, 2017, the SCPSC denied SCE&G’s Motion to Dismiss the Request and ordered that a hearing be set on the Request. In addition, the SCPSC ordered the ORS to perform a thorough inspection and audit, within 30 days, to determine the reasonableness of SCE&G’s retail electric rates and to determine the reasonableness of SCE&G’s statements regarding the potential effect that the removal of approximately $445 million in annual revenues, as requested by the ORS, could have on SCE&G. The SCPSC also granted the ORS’s motion to amend the Request and consider the monetization of the Toshiba payout along with any other related factors that may be appropriate in determining a fair and reasonable rate. SCE&G intends to vigorously contest the Request, but cannot give any assurance as to the timing or outcome of this matter. Proceedings for the Request, the complaint filed by Friends of the Earth and the Sierra Club on June 22, 2017, and the Joint Petition discussed below have been consolidated. On November 20, 2017, the ORS filed a letter with the SCPSC providing the ORS's preliminary list for stabilization and protection of the site where Unit 2 and Unit 3 are located and suggesting that the SCPSC have SCE&G respond to the ORS's November 20, 2017 letter and "explain why there is no violation of S.C. Code Ann. § 58-27-1300." The SCPSC granted the ORS's request, and SCE&G filed its response with the SCPSC on December 27, 2017. 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. A hearing on this matter has not yet been scheduled. On January 19, 2018, the ORS filed a report with the SCPSC in response to the SCPSC's order for a thorough inspection and audit of SCE&G's statements regarding potential adverse effects that could result from the removal of annual BLRA revenues. The ORS report relied on the analysis of bankruptcy counsel to conclude that the suspension of revised rates collections is unlikely to force SCE&G into bankruptcy. Notwithstanding this conclusion, the ORS predicted that there is 35% likelihood of an SCE&G bankruptcy if revised rates are terminated. The report also indicated that a full audit, as ordered by the SCPSC, would require upwards of 90 days to complete. SCE&G filed responses to the ORS report alleging numerous deficiencies in it, including that the report was not verified by an accountant and that it contained incorrect and misleading accounting conclusions, particularly with regard to the timing and magnitude of any impairment loss that would be required by GAAP. On January 31, 2018, the SCPSC ordered the ORS to complete this previously ordered thorough audit, inspection and examination of SCE&G's accounting records by March 30, 2018, encouraged them to employ the assistance of a utility financial professional if needed, and indicated that a request by the ORS for an extension of time would not be considered unreasonable. Gas - SCE&G The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: Year Action Amount 2017 2.2 % Increase $8.6 million 2016 1.2 % Increase $4.1 million 2015 No change — 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. The annual reviews conducted for each of the 12-month periods ended July 31, 2017, 2016 and 2015 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during each of the review periods were reasonable and prudent. See Electric - Base Rates for a discussion of the ORS petition related to the Tax Act, which also applies to Gas - SCE&G. Gas - PSNC Energy PSNC Energy's Rider D rate mechanism allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales. PSNC Energy establishes rates using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption. On October 28, 2016, the NCUC granted PSNC Energy a net annual increase of approximately $19.1 million , or 4.39% , in rates and charges to customers, and set PSNC Energy's authorized ROE at 9.7% . In addition, the NCUC has authorized PSNC Energy to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy has filed biannual applications to adjust its rates for this purpose, and the NCUC has approved those applications for the incremental annual revenue requirements, as follows: Rates Effective Incremental Increase March 1, 2017 $1.9 million September 1, 2017 $0.7 million In December 2017, in connection with PSNC Energy's 2017 Annual Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2017. On January 3, 2018, the NCUC sought reports from its jurisdictional utilities as to how they planned to respond to the Tax Act. In its response on February 1, 2018, PSNC Energy proposed certain adjustments to its rates that, if enacted, would serve to reduce amounts that are currently being collected from customers based on pre-Tax Act rates. PSNC Energy cannot determine when the NCUC may take action on 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 December 31, December 31, Millions of dollars 2017 2016 2017 2016 Regulatory Assets: Unrecovered Nuclear Project costs $ 3,976 — $ 3,976 — Accumulated deferred income taxes — $ 316 — $ 307 AROs and related funding 434 425 410 403 Deferred employee benefit plan costs 305 342 273 309 Deferred losses on interest rate derivatives 456 620 456 620 Other unrecovered plant 105 117 105 117 DSM Programs 59 59 59 59 Carrying costs on deferred tax assets related to the Nuclear Project — 32 — 32 Pipeline integrity management costs 51 33 8 6 Environmental remediation costs 30 32 25 26 Deferred storm damage costs 24 20 24 20 Deferred costs related to uncertain tax position — 15 — 15 Other 140 119 140 116 Total Regulatory Assets $ 5,580 $ 2,130 $ 5,476 $ 2,030 Regulatory Liabilities: Monetization of guaranty settlement $ 1,095 — $ 1,095 — Accumulated deferred income taxes 1,076 23 914 14 Asset removal costs 757 755 527 529 Deferred gains on interest rate derivatives 131 151 131 151 Other — 1 — 1 Total Regulatory Liabilities $ 3,059 $ 930 $ 2,667 $ 695 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. Other 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 that are the subject of regulatory proceedings as further discussed in Note 10. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts that are embodied in rate orders or current 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, 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 the transfer of certain assets described at Note 10. Accumulated deferred income taxes contained within regulatory assets represent deferred tax liabilities that arise from utility operations that have not been included in customer rates. A portion of these regulatory assets related to depreciation and are netted within regulatory liabilities in the current period. 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 except when such amounts are applied otherwise at the direction of the SCPSC. See also Note 10 for a discussion of certain amounts that were treated as impaired as of December 31, 2017. 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. Carrying costs on deferred tax assets related to the Nuclear Project were calculated on accumulated deferred income tax assets associated with Unit 2 and Unit 3 which were not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs were written off as a part of the impairment loss in 2017. See also Note 10. Pipeline integrity management costs represent operating and maintenance 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 December 31, 2017 costs of $26.6 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 total $6.9 million are being recovered over a five year period that will end in 2021 . Deferred storm damage costs represent costs incurred in excess of amounts previously collected through SCE&G's SCPSC-approved storm damage reserve, and for which SCE&G expects to receive future recovery through customer rates. Deferred costs related to uncertain tax position primarily represented the estimated amounts of domestic production activities deductions foregone as a result of the deduction of certain research and experimentation expenditures for income tax purposes, net of related tax credits, as well as accrued interest expense and other costs arising from this uncertain tax position. SCE&G's current customer rates reflect the availability of domestic production activities deductions. These net deferred costs were written off as a part of the impairment loss in 2017. See Note 5 and Note 10. Various other regulatory assets are expected to be recovered through rates over periods through 2047 . Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement, net of certain expenses. 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 5. Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future.
SCE&G
Rate Matters [Line Items]
Schedule of Regulatory Assets and Liabilities [Text Block]	RATE AND OTHER REGULATORY MATTERS Rate Matters Electric - Cost of Fuel SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties in which SCE&G agreed to decrease the total fuel cost component of retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, over the subsequent 12-month period beginning with the first billing cycle of May 2015. By order dated July 15, 2015, the SCPSC approved SCE&G's participation in a DER program and recovery of related costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G is to implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately 84.5 MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity. This nameplate capacity goal was achieved in 2017. By order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G reduced the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G also began to recover projected DER program costs of approximately $6.9 million beginning with the first billing cycle of May 2016. By order dated April 27, 2017, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component to produce a projected under recovery of $61.0 million over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately $16.5 million . Additionally, deferral of carrying costs will be allowed for base fuel component under-collected balances as they occur. In October 2017, the SCPSC initiated its 2018 annual review of base rates for fuel costs. A public hearing for this annual review is scheduled for April 10, 2018. Electric - Base Rates Pursuant to an SCPSC order, SCE&G has removed from rate base certain deferred income tax assets arising from capital expenditures related to Unit 2 and Unit 3 and accrued carrying costs on those amounts during periods in which they were not included in rate base. Such carrying costs were determined at SCE&G’s weighted average long-term debt borrowing rate and were recorded as a regulatory asset and other income. Carrying costs totaled $18.8 million and $14.0 million during 2017 and 2016, respectively. As part of the impairment loss described in Note 10, accumulated carrying costs related to the Nuclear Project totaling $51.0 million were written off. The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues (both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below: Year Effective Amount 2017 First billing cycle of May $37.0 million 2016 First billing cycle of May $37.6 million 2015 First billing cycle of May $32.0 million By order dated April 29, 2016, the SCPSC approved SCE&G’s request to increase its pension costs rider. The increased pension rider was designed to allow SCE&G to recover projected pension costs, including under-collections, over a 12-month period, beginning with the first billing cycle in May 2016. By order dated March 1, 2017, the SCPSC approved SCE&G’s request to decrease its pension costs rider. The change in the pension rider decreased annual revenue by approximately $11.9 million . The pension rider is designed to allow SCE&G to recover projected pension costs, net of the previously over-collected balance, over a 12-month period, beginning with the first billing cycle in May 2017. In December 2017, the ORS filed a petition with the SCPSC requesting all investor-owned utilities under the SCPSC’s jurisdiction to report the impact of the Tax Act on their individual company’s operations. The Tax Act contains provisions that lower the federal corporate tax rate from 35% to 21% effective January 1, 2018. The petition requested that utilities file an estimate of the Tax Act’s effects on their most recent test year information available, including an explanation of those effects, and requested that utilities propose procedures for changing rates to reflect the impacts. Lastly, the petition requested that the SCPSC state in its order that rates in effect as of January 1, 2018, be subject to refund so that ratepayers receive the benefit of the tax law changes as of January 1, 2018. By order dated January 10, 2018, the SCPSC granted the ORS petition but did not state that rates in effect as of January 1, 2018 would be subject to refund. SCE&G provided its comments on January 24, 2018, concerning the timing and the format of the report. In January 2018, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved the filing would allow recovery of $37.0 million of costs and net lost revenues associated with DSM programs, along with an incentive to invest in such programs. Electric - BLRA and Joint Petition Under the BLRA, SCE&G filed revised rates with the SCPSC in 2015 and 2016 to incorporate the financing cost of incremental construction work in progress incurred for the Nuclear Project. Rate adjustments were based on SCE&G's updated cost of debt and capital structure and on an allowed ROE. No revised rates filing was pursued in 2017. The SCPSC approved recovery of the following amounts. Increase Effective for bills rendered on and after Amount Allowed ROE 2.7% November 27, 2016 $64.4 million 10.50% * 2.6% October 30, 2015 $64.5 million 11.00% *Applied prospectively for purposes of calculating revised rates under the BLRA on and after January 1, 2016. In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for Unit 2 and Unit 3 which had been developed in connection with the October 2015 Amendment (see Note 10). On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, the ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option. By order dated February 28, 2017, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement, and that denial was not appealed. The construction schedule approved by the SCPSC in November 2016 provided for contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Unit 2 and Unit 3, respectively. The approved capital cost schedule included incremental capital costs that totaled $831 million , raising SCE&G’s total project capital cost as then approved to an estimated amount of approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for the Nuclear Project from 10.5% to 10.25% . This revised ROE was to be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. In addition, SCE&G could not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request was denied because SCE&G was out of compliance with its approved capital cost schedule or BLRA construction milestone schedule, subject to certain extensions. See also Abandoned Nuclear Project in Note 10. Following WEC and WECTEC's bankruptcy filing on March 29, 2017, on June 22, 2017, the Friends of the Earth and the Sierra Club filed a complaint against SCE&G with the SCPSC, requesting that the SCPSC initiate a formal proceeding to direct SCE&G to immediately cease and desist from expending any further capital costs related to the construction of Unit 2 and Unit 3; to determine the prudence of acts and omissions by SCE&G in connection with this construction; to review and determine the prudence of abandonment of Unit 2 and Unit 3 and of the available least cost efficiency and renewable energy alternatives; and to remedy, abate and make due reparations for the rates charged to ratepayers related to the construction of Unit 2 and Unit 3. SCE&G filed its answer to the complaint and a motion to dismiss the complaint on July 19, 2017. On October 4, 2017, the SCPSC ordered proceedings under this complaint to be coordinated with proceedings for the Request filed by the ORS on September 26, 2017, described below, and allowed discovery to proceed. SCE&G's subsequent petition for rehearing and reconsideration was denied by the SCPSC on November 1, 2017. Proceedings related to this complaint have been consolidated with proceedings for the Request and the Joint Petition as described below. On August 1, 2017, SCE&G filed the Abandonment Petition with the SCPSC which sought recovery of costs expended on the construction of Unit 2 and Unit 3, including certain costs incurred subsequent to SCE&G's last revised rates update, other costs under the abandonment provisions of the BLRA, and affirmation of SCE&G's decision to abandon construction of Unit 2 and Unit 3, among other things. Subsequently, SCE&G management met with various stakeholders and members of the South Carolina General Assembly, including legislative leaders, to discuss the abandonment of the Nuclear Project and to hear their concerns. In response to those concerns, and to allow adequate time for governmental officials to conduct their reviews, SCE&G voluntarily withdrew the Abandonment Petition on August 15, 2017. See additional discussion at Note 10. 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, the ORS filed the Request with the SCPSC asking for an order directing SCE&G to immediately suspend all revised rates collections from customers which had been previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS relied upon the opinion from the Office of Attorney General to assert that it is not just and reasonable or in the public interest to allow SCE&G to continue collecting revised rates. Further, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS that should have been disclosed and that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the 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 September 28, 2017, SCE&G filed a Motion to Dismiss the Request and a Request for Briefing Schedule and Hearing on Motion to Dismiss. On September 28, 2017, the SCPSC deferred action on the Request and ordered a hearing officer to establish a briefing schedule and hearing date on SCE&G's motion. On October 17, 2017, the ORS filed with the SCPSC a motion to amend its request, in which 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. A hearing on the parties' motions was held on December 12, 2017, and included the state's Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, a large industrial customer, and several environmental groups. By order dated December 20, 2017, the SCPSC denied SCE&G’s Motion to Dismiss the Request and ordered that a hearing be set on the Request. In addition, the SCPSC ordered the ORS to perform a thorough inspection and audit, within 30 days, to determine the reasonableness of SCE&G’s retail electric rates and to determine the reasonableness of SCE&G’s statements regarding the potential effect that the removal of approximately $445 million in annual revenues, as requested by the ORS, could have on SCE&G. The SCPSC also granted the ORS’s motion to amend the Request and consider the monetization of the Toshiba payout along with any other related factors that may be appropriate in determining a fair and reasonable rate. SCE&G intends to vigorously contest the Request, but cannot give any assurance as to the timing or outcome of this matter. Proceedings for the Request, the complaint filed by Friends of the Earth and the Sierra Club on June 22, 2017, and the Joint Petition discussed below have been consolidated. On November 20, 2017, the ORS filed a letter with the SCPSC providing the ORS's preliminary list for stabilization and protection of the site where Unit 2 and Unit 3 are located and suggesting that the SCPSC have SCE&G respond to the ORS's November 20, 2017 letter and "explain why there is no violation of S.C. Code Ann. § 58-27-1300." The SCPSC granted the ORS's request, and SCE&G filed its response with the SCPSC on December 27, 2017. 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. A hearing on this matter has not yet been scheduled. On January 19, 2018, the ORS filed a report with the SCPSC in response to the SCPSC's order for a thorough inspection and audit of SCE&G's statements regarding potential adverse effects that could result from the removal of annual BLRA revenues. The ORS report relied on the analysis of bankruptcy counsel to conclude that the suspension of revised rates collections is unlikely to force SCE&G into bankruptcy. Notwithstanding this conclusion, the ORS predicted that there is 35% likelihood of an SCE&G bankruptcy if revised rates are terminated. The report also indicated that a full audit, as ordered by the SCPSC, would require upwards of 90 days to complete. SCE&G filed responses to the ORS report alleging numerous deficiencies in it, including that the report was not verified by an accountant and that it contained incorrect and misleading accounting conclusions, particularly with regard to the timing and magnitude of any impairment loss that would be required by GAAP. On January 31, 2018, the SCPSC ordered the ORS to complete this previously ordered thorough audit, inspection and examination of SCE&G's accounting records by March 30, 2018, encouraged them to employ the assistance of a utility financial professional if needed, and indicated that a request by the ORS for an extension of time would not be considered unreasonable. Gas - SCE&G The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: Year Action Amount 2017 2.2 % Increase $8.6 million 2016 1.2 % Increase $4.1 million 2015 No change — 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. The annual reviews conducted for each of the 12-month periods ended July 31, 2017, 2016 and 2015 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during each of the review periods were reasonable and prudent. See Electric - Base Rates for a discussion of the ORS petition related to the Tax Act, which also applies to Gas - SCE&G. Gas - PSNC Energy PSNC Energy's Rider D rate mechanism allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales. PSNC Energy establishes rates using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption. On October 28, 2016, the NCUC granted PSNC Energy a net annual increase of approximately $19.1 million , or 4.39% , in rates and charges to customers, and set PSNC Energy's authorized ROE at 9.7% . In addition, the NCUC has authorized PSNC Energy to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy has filed biannual applications to adjust its rates for this purpose, and the NCUC has approved those applications for the incremental annual revenue requirements, as follows: Rates Effective Incremental Increase March 1, 2017 $1.9 million September 1, 2017 $0.7 million In December 2017, in connection with PSNC Energy's 2017 Annual Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2017. On January 3, 2018, the NCUC sought reports from its jurisdictional utilities as to how they planned to respond to the Tax Act. In its response on February 1, 2018, PSNC Energy proposed certain adjustments to its rates that, if enacted, would serve to reduce amounts that are currently being collected from customers based on pre-Tax Act rates. PSNC Energy cannot determine when the NCUC may take action on 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 December 31, December 31, Millions of dollars 2017 2016 2017 2016 Regulatory Assets: Unrecovered Nuclear Project costs $ 3,976 — $ 3,976 — Accumulated deferred income taxes — $ 316 — $ 307 AROs and related funding 434 425 410 403 Deferred employee benefit plan costs 305 342 273 309 Deferred losses on interest rate derivatives 456 620 456 620 Other unrecovered plant 105 117 105 117 DSM Programs 59 59 59 59 Carrying costs on deferred tax assets related to the Nuclear Project — 32 — 32 Pipeline integrity management costs 51 33 8 6 Environmental remediation costs 30 32 25 26 Deferred storm damage costs 24 20 24 20 Deferred costs related to uncertain tax position — 15 — 15 Other 140 119 140 116 Total Regulatory Assets $ 5,580 $ 2,130 $ 5,476 $ 2,030 Regulatory Liabilities: Monetization of guaranty settlement $ 1,095 — $ 1,095 — Accumulated deferred income taxes 1,076 23 914 14 Asset removal costs 757 755 527 529 Deferred gains on interest rate derivatives 131 151 131 151 Other — 1 — 1 Total Regulatory Liabilities $ 3,059 $ 930 $ 2,667 $ 695 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. Other 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 that are the subject of regulatory proceedings as further discussed in Note 10. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts that are embodied in rate orders or current 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, 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 the transfer of certain assets described at Note 10. Accumulated deferred income taxes contained within regulatory assets represent deferred tax liabilities that arise from utility operations that have not been included in customer rates. A portion of these regulatory assets related to depreciation and are netted within regulatory liabilities in the current period. 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 except when such amounts are applied otherwise at the direction of the SCPSC. See also Note 10 for a discussion of certain amounts that were treated as impaired as of December 31, 2017. 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. Carrying costs on deferred tax assets related to the Nuclear Project were calculated on accumulated deferred income tax assets associated with Unit 2 and Unit 3 which were not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs were written off as a part of the impairment loss in 2017. See also Note 10. Pipeline integrity management costs represent operating and maintenance 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 December 31, 2017 costs of $26.6 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 total $6.9 million are being recovered over a five year period that will end in 2021 . Deferred storm damage costs represent costs incurred in excess of amounts previously collected through SCE&G's SCPSC-approved storm damage reserve, and for which SCE&G expects to receive future recovery through customer rates. Deferred costs related to uncertain tax position primarily represented the estimated amounts of domestic production activities deductions foregone as a result of the deduction of certain research and experimentation expenditures for income tax purposes, net of related tax credits, as well as accrued interest expense and other costs arising from this uncertain tax position. SCE&G's current customer rates reflect the availability of domestic production activities deductions. These net deferred costs were written off as a part of the impairment loss in 2017. See Note 5 and Note 10. Various other regulatory assets are expected to be recovered through rates over periods through 2047 . Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement, net of certain expenses. 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 5. Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future.

COMMON EQUITY

COMMON EQUITY	12 Months Ended
	Dec. 31, 2017
Schedule of Capitalization, Equity [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	COMMON EQUITY Authorized shares of SCANA common stock were 200 million as of December 31, 2017 and 2016. Authorized shares of SCE&G common stock were 50 million as of December 31, 2017 and 2016. Authorized shares of SCE&G preferred stock were 20 million , of which 1,000 shares, no par value, were held by SCANA as of December 31, 2017 and 2016. 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 (which as defined in the bond indenture equates to its retained earnings) or (2) in case there is no Surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, the Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At December 31, 2017 and 2016, retained earnings of approximately $93.9 million and $79.0 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 December 31, 2017, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million .
SCE&G
Schedule of Capitalization, Equity [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	3. COMMON EQUITY Authorized shares of SCANA common stock were 200 million as of December 31, 2017 and 2016. Authorized shares of SCE&G common stock were 50 million as of December 31, 2017 and 2016. Authorized shares of SCE&G preferred stock were 20 million , of which 1,000 shares, no par value, were held by SCANA as of December 31, 2017 and 2016. 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 (which as defined in the bond indenture equates to its retained earnings) or (2) in case there is no Surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, the Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At December 31, 2017 and 2016, retained earnings of approximately $93.9 million and $79.0 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 December 31, 2017, 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	12 Months Ended
	Dec. 31, 2017
Debt Instrument [Line Items]
Debt Disclosure [Text Block]	LONG-TERM AND SHORT-TERM DEBT Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows: The Company December 31, 2017 2016 Dollars in millions Maturity Balance Rate Balance Rate SCANA Medium Term Notes (unsecured) 2020 - 2022 $ 800 5.42 % $ 800 5.42 % SCANA Senior Notes (unsecured) (a) 2018 - 2034 75 2.18 % 79 1.63 % SCE&G First Mortgage Bonds (secured) 2018 - 2065 4,840 5.80 % 4,840 5.79 % GENCO Notes (secured) 2018 - 2024 207 5.94 % 213 5.93 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.52 % 122 3.51 % PSNC Energy Senior Debentures and Notes 2020 - 2046 600 5.19 % 450 5.53 % Other 2018 - 2027 28 2.83 % 27 2.76 % Total debt 6,672 6,531 Current maturities of long-term debt (727 ) (17 ) Unamortized discount, net (1 ) (1 ) Unamortized debt issuance costs (38 ) (40 ) Total long-term debt, net $ 5,906 $ 6,473 Consolidated SCE&G December 31, 2017 2016 Dollars in millions Maturity Balance Rate Balance Rate First Mortgage Bonds (secured) 2018 - 2065 $ 4,840 5.80 % $ 4,840 5.79 % GENCO Notes (secured) 2018 - 2024 207 5.94 % 213 5.93 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.52 % 122 3.51 % Other 2018 - 2027 28 2.83 % 26 2.76 % Total debt 5,197 5,201 Current maturities of long-term debt (723 ) (12 ) Unamortized premium, net 1 1 Unamortized debt issuance costs (34 ) (36 ) Total long-term debt, net $ 4,441 $ 5,154 (a) Variable rate notes hedged by a fixed interest rate swap (fixed rate of 6.17% ). (b) Includes variable rate debt of $67.8 million at December 31, 2017 (rate of 1.85% ) and 2016 (rate of 0.76% ) which are hedged by fixed swaps. In June 2016, SCE&G issued $425 million of 4.1% first mortgage bonds due June 15, 2046. Also in June 2016, SCE&G issued $75 million of 4.5% first mortgage bonds due June 1, 2064, which constituted a reopening of $300 million of 4.5% first mortgage bonds issued in May 2014. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes. In June 2017, PSNC Energy issued $150 million of 4.18% senior notes due June 30, 2047. In June 2016, PSNC Energy issued $100 million of 4.13% senior notes due June 22, 2046. Proceeds from these sales were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes. The Company's long-term debt maturities will be $727 million in 2018, $16 million in 2019, $366 million in 2020, $494 million in 2021 and $264 million in 2022. These amounts include, for Consolidated SCE&G, $723 million in 2018, $12 million in 2019, $11 million in 2020, $40 million in 2021 and $9 million in 2022. Substantially all electric utility plant is pledged as collateral in connection with long-term debt. SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be issued (Bond Ratio). For the year ended December 31, 2017, the Bond Ratio was 5.24 . Adjusted Net Earnings, as therein defined, excludes the impairment loss. Lines of Credit and Short-Term Borrowings At December 31, 2017 and 2016, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC-related obligations and commercial paper borrowings: Millions of dollars Total SCANA SCE&G PSNC Energy December 31, 2017 Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 $ 500.0 — $ 500.0 — Three-year, expiring December 2018 $ 200.0 — $ 200.0 — Total committed long-term $ 2,000.0 $ 400.0 $ 1,400.0 $ 200.0 Outstanding commercial paper (270 or fewer days) $ 350.3 — $ 251.6 $ 98.7 Weighted average interest rate — 1.92 % 1.93 % Letters of credit supported by LOC $ 3.3 $ 3.0 $ 0.3 — Available $ 1,646.4 $ 397.0 $ 1,148.1 $ 101.3 December 31, 2016 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) $ 940.5 $ 64.4 $ 804.3 $ 71.8 Weighted average interest rate 1.43 % 1.04 % 1.07 % Letters of credit supported by LOC $ 3.3 $ 3.0 $ 0.3 — Available $ 1,056.2 $ 332.6 $ 595.4 $ 128.2 SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to credit agreements in the amounts and for the terms described above. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N.A. and Morgan Stanley Bank, N.A. each provide 9.5% of the aggregate credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch, UBS Loan Finance LLC, MUFG Union Bank, N.A., and Branch Banking and Trust Company each provide 7.9 %, and Royal Bank of Canada and U.S. Bank National Association each provide 5.5% . Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented. 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 2018. 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. Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. The letters of credit expire, subject to renewal, in the fourth quarter of 2019. Consolidated SCE&G participates in a utility money pool with SCANA and certain other subsidiaries of SCANA. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. 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 . At December 31, 2016, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $29 million . On SCE&G's consolidated balance sheets, amounts due from an affiliate are included within Receivables-affiliated companies, and amounts due to an affiliate are included within Affiliated payables.
SCE&G
Debt Instrument [Line Items]
Debt Disclosure [Text Block]	LONG-TERM AND SHORT-TERM DEBT Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows: The Company December 31, 2017 2016 Dollars in millions Maturity Balance Rate Balance Rate SCANA Medium Term Notes (unsecured) 2020 - 2022 $ 800 5.42 % $ 800 5.42 % SCANA Senior Notes (unsecured) (a) 2018 - 2034 75 2.18 % 79 1.63 % SCE&G First Mortgage Bonds (secured) 2018 - 2065 4,840 5.80 % 4,840 5.79 % GENCO Notes (secured) 2018 - 2024 207 5.94 % 213 5.93 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.52 % 122 3.51 % PSNC Energy Senior Debentures and Notes 2020 - 2046 600 5.19 % 450 5.53 % Other 2018 - 2027 28 2.83 % 27 2.76 % Total debt 6,672 6,531 Current maturities of long-term debt (727 ) (17 ) Unamortized discount, net (1 ) (1 ) Unamortized debt issuance costs (38 ) (40 ) Total long-term debt, net $ 5,906 $ 6,473 Consolidated SCE&G December 31, 2017 2016 Dollars in millions Maturity Balance Rate Balance Rate First Mortgage Bonds (secured) 2018 - 2065 $ 4,840 5.80 % $ 4,840 5.79 % GENCO Notes (secured) 2018 - 2024 207 5.94 % 213 5.93 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.52 % 122 3.51 % Other 2018 - 2027 28 2.83 % 26 2.76 % Total debt 5,197 5,201 Current maturities of long-term debt (723 ) (12 ) Unamortized premium, net 1 1 Unamortized debt issuance costs (34 ) (36 ) Total long-term debt, net $ 4,441 $ 5,154 (a) Variable rate notes hedged by a fixed interest rate swap (fixed rate of 6.17% ). (b) Includes variable rate debt of $67.8 million at December 31, 2017 (rate of 1.85% ) and 2016 (rate of 0.76% ) which are hedged by fixed swaps. In June 2016, SCE&G issued $425 million of 4.1% first mortgage bonds due June 15, 2046. Also in June 2016, SCE&G issued $75 million of 4.5% first mortgage bonds due June 1, 2064, which constituted a reopening of $300 million of 4.5% first mortgage bonds issued in May 2014. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes. In June 2017, PSNC Energy issued $150 million of 4.18% senior notes due June 30, 2047. In June 2016, PSNC Energy issued $100 million of 4.13% senior notes due June 22, 2046. Proceeds from these sales were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes. The Company's long-term debt maturities will be $727 million in 2018, $16 million in 2019, $366 million in 2020, $494 million in 2021 and $264 million in 2022. These amounts include, for Consolidated SCE&G, $723 million in 2018, $12 million in 2019, $11 million in 2020, $40 million in 2021 and $9 million in 2022. Substantially all electric utility plant is pledged as collateral in connection with long-term debt. SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be issued (Bond Ratio). For the year ended December 31, 2017, the Bond Ratio was 5.24 . Adjusted Net Earnings, as therein defined, excludes the impairment loss. Lines of Credit and Short-Term Borrowings At December 31, 2017 and 2016, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC-related obligations and commercial paper borrowings: Millions of dollars Total SCANA SCE&G PSNC Energy December 31, 2017 Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 $ 500.0 — $ 500.0 — Three-year, expiring December 2018 $ 200.0 — $ 200.0 — Total committed long-term $ 2,000.0 $ 400.0 $ 1,400.0 $ 200.0 Outstanding commercial paper (270 or fewer days) $ 350.3 — $ 251.6 $ 98.7 Weighted average interest rate — 1.92 % 1.93 % Letters of credit supported by LOC $ 3.3 $ 3.0 $ 0.3 — Available $ 1,646.4 $ 397.0 $ 1,148.1 $ 101.3 December 31, 2016 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) $ 940.5 $ 64.4 $ 804.3 $ 71.8 Weighted average interest rate 1.43 % 1.04 % 1.07 % Letters of credit supported by LOC $ 3.3 $ 3.0 $ 0.3 — Available $ 1,056.2 $ 332.6 $ 595.4 $ 128.2 SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to credit agreements in the amounts and for the terms described above. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N.A. and Morgan Stanley Bank, N.A. each provide 9.5% of the aggregate credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch, UBS Loan Finance LLC, MUFG Union Bank, N.A., and Branch Banking and Trust Company each provide 7.9 %, and Royal Bank of Canada and U.S. Bank National Association each provide 5.5% . Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented. 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 2018. 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. Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. The letters of credit expire, subject to renewal, in the fourth quarter of 2019. Consolidated SCE&G participates in a utility money pool with SCANA and certain other subsidiaries of SCANA. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. 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 . At December 31, 2016, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $29 million . On SCE&G's consolidated balance sheets, amounts due from an affiliate are included within Receivables-affiliated companies, and amounts due to an affiliate are included within Affiliated payables.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2017
income tax [Line Items]
Income Tax Disclosure [Text Block]	INCOME TAXES Components of income tax expense (benefit) are as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Current taxes (benefit): Federal $ (414 ) $ 36 $ 382 $ (410 ) $ 50 $ 208 State 18 13 57 (18 ) 13 32 Total current taxes (benefit) (396 ) 49 439 (428 ) 63 240 Deferred tax (benefit) expense, net: Federal 323 203 (36 ) 261 167 (3 ) State (37 ) 21 (7 ) (2 ) 20 (3 ) Total deferred taxes (benefit) 286 224 (43 ) 259 187 (6 ) Investment tax credits: Amortization of amounts deferred-state — — (1 ) — — (1 ) Amortization of amounts deferred-federal (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Total investment tax credits (2 ) (2 ) (3 ) (2 ) (2 ) (3 ) Total income tax expense (benefit) $ (112 ) $ 271 $ 393 $ (171 ) $ 248 $ 231 The difference between actual income tax expense and the amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income is reconciled as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Net income (loss) $ (119 ) $ 595 $ 746 $ (185 ) $ 513 $ 466 Income tax expense (benefit) (112 ) 271 393 (171 ) 248 231 Noncontrolling interest — — — 13 13 14 Total pre-tax income (loss) $ (231 ) $ 866 $ 1,139 $ (343 ) $ 774 $ 711 Income taxes (benefit) on above at statutory federal income tax rate $ (81 ) $ 303 $ 399 $ (120 ) $ 271 $ 249 Increases (decreases) attributed to: State income taxes (less federal income tax effect) (7 ) 27 38 (8 ) 26 24 State investment tax credits (less federal income tax effect) (5 ) (5 ) (6 ) (5 ) (5 ) (6 ) Allowance for equity funds used during construction (8 ) (10 ) (9 ) (5 ) (9 ) (9 ) Deductible dividends—401(k) Retirement Savings Plan (9 ) (10 ) (10 ) — — — Amortization of federal investment tax credits (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Section 45 tax credits (8 ) (8 ) (9 ) (8 ) (8 ) (9 ) Domestic production activities deduction (18 ) (23 ) (18 ) (18 ) (23 ) (18 ) Remeasurement of deferred taxes upon enactment of Tax Act 30 — — (1 ) — — Realization of basis differences upon sale of subsidiaries — — 7 — — — Other differences, net (4 ) (1 ) 3 (4 ) (2 ) 2 Total income tax expense (benefit) $ (112 ) $ 271 $ 393 $ (171 ) $ 248 $ 231 The tax effects of significant temporary differences comprising net deferred tax liabilities are as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Deferred tax assets: Net operating loss and tax credit carryforward $ 600 — $ 541 — Toshiba settlement 273 — 273 — Nondeductible accruals 88 $ 148 42 $ 53 Asset retirement obligation, including nuclear decommissioning 141 213 132 200 Regulatory liability, non-property accumulated deferred income tax 54 — 54 — Financial instruments 15 22 — — Unamortized investment tax credits 8 15 8 15 Deferred fuel costs — 17 — 17 Other 6 10 5 8 Total deferred tax assets 1,185 425 1,055 293 Deferred tax liabilities: Property, plant and equipment 1,220 2,159 1,035 1,856 Regulatory asset, unrecovered nuclear plant costs 962 — 962 — Deferred employee benefit plan costs 60 105 53 93 Regulatory asset, asset retirement obligation 91 143 85 135 Regulatory asset, other unrecovered plant 27 45 27 45 Demand side management costs 16 23 16 23 Prepayments 21 32 19 30 Other 49 77 31 50 Total deferred tax liabilities 2,446 2,584 2,228 2,232 Net deferred tax liabilities $ 1,261 $ 2,159 $ 1,173 $ 1,939 The federal and state tax credits and NOL carryforwards are presented below: December 31, 2017 Millions of dollars The Company Consolidated SCE&G Expiration Year Federal NOL Carryforwards $ 2,052 $ 1,905 2037 Federal Tax Credits 35 35 2035 - 2037 Federal Charitable Carryforwards 7 5 2021 - 2022 State NOL Carryforwards 2,382 2,301 2037 State Charitable Carryforwards 3 2 2022 Total Tax Credits and NOL Carryforwards $ 4,479 $ 4,248 A valuation allowance is needed when it is more likely than not that all or a portion of a deferred tax asset will not be realized. In determining whether a valuation allowance is required, the Company and Consolidated SCE&G consider such factors as prior earnings history, expected future earnings, carryback and carryforward periods, and tax strategies that could potentially enhance the likelihood of the realization of a deferred tax asset. Based on this evaluation, management has concluded that a valuation allowance is not needed. In December 2017, the Tax Act was enacted, resulting in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory tax rate. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in deferred income tax balances within regulatory liabilities (see Note 2). In connection with this remeasurement, however, the Company recorded additional deferred income tax expense of approximately $30 million , and Consolidated SCE&G recorded a deferred income tax benefit of approximately $1 million in their respective statements of operations for the year ended December 31, 2017. Upon the eventual filing of the Company’s 2017 consolidated income tax return, adjustments to deferred income taxes and deferred income taxes may be recorded; however, these adjustments are not expected to have a material impact on the Company’s financial position, results of operations or cash flows. The State of North Carolina lowered its corporate income tax rate from 6.0% to 5.0% in 2015, 4.0% in 2016, 3% in 2017 and 2.5% effective January 1, 2019. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows. The Company files consolidated federal income tax returns which includes Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns. The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2009 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2015 as a result of claims discussed below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010. Changes in Unrecognized Tax Benefits The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Unrecognized tax benefits, January 1 $ 350 $ 49 $ 16 $ 350 $ 49 $ 16 Gross increases—uncertain tax positions in prior period — 94 33 — 94 33 Gross decreases—uncertain tax positions in prior period (273 ) — (2 ) (273 ) — (2 ) Gross increases—current period uncertain tax positions 21 207 2 21 207 2 Unrecognized tax benefits, December 31 $ 98 $ 350 $ 49 $ 98 $ 350 $ 49 During 2013 and 2014, the Company amended certain of its income tax returns to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). The Company also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016 and 2017, the Company claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the Nuclear Project, in its 2015 and 2016 income tax returns. The Company expects to claim similar deductions and credits in its 2017 tax return when it is filed in 2018. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. The IRS examined the claims in the amended returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2015 income tax returns, and it is expected that the IRS will also examine later returns. These IRC Section 174 income tax deductions and IRC Section 41 credits were considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities were recorded as unrecognized tax benefits in the financial statements. Following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G anticipate that an abandonment loss deduction under IRC Section 165 will be claimed on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, would instead 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 December 31, 2017. 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 December 31, 2017, 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 December 31, 2017. In connection with the research and experimentation deduction and credit claims reflected on the 2015 and 2016 income tax returns and similar claims made in determining taxable income for 2017, and under the terms 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 (see Note 2). However, as further described in Note 10, as of December 31, 2017, an impairment loss with respect to such deferred regulatory asset was recorded. SCE&G's current customer rates reflect the availability of domestic production activities deductions. Also under the terms 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. Amounts recorded for such interest income, interest expense or tax penalties have not been material for any period presented.
SCE&G
income tax [Line Items]
Income Tax Disclosure [Text Block]	INCOME TAXES Components of income tax expense (benefit) are as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Current taxes (benefit): Federal $ (414 ) $ 36 $ 382 $ (410 ) $ 50 $ 208 State 18 13 57 (18 ) 13 32 Total current taxes (benefit) (396 ) 49 439 (428 ) 63 240 Deferred tax (benefit) expense, net: Federal 323 203 (36 ) 261 167 (3 ) State (37 ) 21 (7 ) (2 ) 20 (3 ) Total deferred taxes (benefit) 286 224 (43 ) 259 187 (6 ) Investment tax credits: Amortization of amounts deferred-state — — (1 ) — — (1 ) Amortization of amounts deferred-federal (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Total investment tax credits (2 ) (2 ) (3 ) (2 ) (2 ) (3 ) Total income tax expense (benefit) $ (112 ) $ 271 $ 393 $ (171 ) $ 248 $ 231 The difference between actual income tax expense and the amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income is reconciled as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Net income (loss) $ (119 ) $ 595 $ 746 $ (185 ) $ 513 $ 466 Income tax expense (benefit) (112 ) 271 393 (171 ) 248 231 Noncontrolling interest — — — 13 13 14 Total pre-tax income (loss) $ (231 ) $ 866 $ 1,139 $ (343 ) $ 774 $ 711 Income taxes (benefit) on above at statutory federal income tax rate $ (81 ) $ 303 $ 399 $ (120 ) $ 271 $ 249 Increases (decreases) attributed to: State income taxes (less federal income tax effect) (7 ) 27 38 (8 ) 26 24 State investment tax credits (less federal income tax effect) (5 ) (5 ) (6 ) (5 ) (5 ) (6 ) Allowance for equity funds used during construction (8 ) (10 ) (9 ) (5 ) (9 ) (9 ) Deductible dividends—401(k) Retirement Savings Plan (9 ) (10 ) (10 ) — — — Amortization of federal investment tax credits (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Section 45 tax credits (8 ) (8 ) (9 ) (8 ) (8 ) (9 ) Domestic production activities deduction (18 ) (23 ) (18 ) (18 ) (23 ) (18 ) Remeasurement of deferred taxes upon enactment of Tax Act 30 — — (1 ) — — Realization of basis differences upon sale of subsidiaries — — 7 — — — Other differences, net (4 ) (1 ) 3 (4 ) (2 ) 2 Total income tax expense (benefit) $ (112 ) $ 271 $ 393 $ (171 ) $ 248 $ 231 The tax effects of significant temporary differences comprising net deferred tax liabilities are as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Deferred tax assets: Net operating loss and tax credit carryforward $ 600 — $ 541 — Toshiba settlement 273 — 273 — Nondeductible accruals 88 $ 148 42 $ 53 Asset retirement obligation, including nuclear decommissioning 141 213 132 200 Regulatory liability, non-property accumulated deferred income tax 54 — 54 — Financial instruments 15 22 — — Unamortized investment tax credits 8 15 8 15 Deferred fuel costs — 17 — 17 Other 6 10 5 8 Total deferred tax assets 1,185 425 1,055 293 Deferred tax liabilities: Property, plant and equipment 1,220 2,159 1,035 1,856 Regulatory asset, unrecovered nuclear plant costs 962 — 962 — Deferred employee benefit plan costs 60 105 53 93 Regulatory asset, asset retirement obligation 91 143 85 135 Regulatory asset, other unrecovered plant 27 45 27 45 Demand side management costs 16 23 16 23 Prepayments 21 32 19 30 Other 49 77 31 50 Total deferred tax liabilities 2,446 2,584 2,228 2,232 Net deferred tax liabilities $ 1,261 $ 2,159 $ 1,173 $ 1,939 The federal and state tax credits and NOL carryforwards are presented below: December 31, 2017 Millions of dollars The Company Consolidated SCE&G Expiration Year Federal NOL Carryforwards $ 2,052 $ 1,905 2037 Federal Tax Credits 35 35 2035 - 2037 Federal Charitable Carryforwards 7 5 2021 - 2022 State NOL Carryforwards 2,382 2,301 2037 State Charitable Carryforwards 3 2 2022 Total Tax Credits and NOL Carryforwards $ 4,479 $ 4,248 A valuation allowance is needed when it is more likely than not that all or a portion of a deferred tax asset will not be realized. In determining whether a valuation allowance is required, the Company and Consolidated SCE&G consider such factors as prior earnings history, expected future earnings, carryback and carryforward periods, and tax strategies that could potentially enhance the likelihood of the realization of a deferred tax asset. Based on this evaluation, management has concluded that a valuation allowance is not needed. In December 2017, the Tax Act was enacted, resulting in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory tax rate. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in deferred income tax balances within regulatory liabilities (see Note 2). In connection with this remeasurement, however, the Company recorded additional deferred income tax expense of approximately $30 million , and Consolidated SCE&G recorded a deferred income tax benefit of approximately $1 million in their respective statements of operations for the year ended December 31, 2017. Upon the eventual filing of the Company’s 2017 consolidated income tax return, adjustments to deferred income taxes and deferred income taxes may be recorded; however, these adjustments are not expected to have a material impact on the Company’s financial position, results of operations or cash flows. The State of North Carolina lowered its corporate income tax rate from 6.0% to 5.0% in 2015, 4.0% in 2016, 3% in 2017 and 2.5% effective January 1, 2019. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows. The Company files consolidated federal income tax returns which includes Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns. The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2009 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2015 as a result of claims discussed below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010. Changes in Unrecognized Tax Benefits The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Unrecognized tax benefits, January 1 $ 350 $ 49 $ 16 $ 350 $ 49 $ 16 Gross increases—uncertain tax positions in prior period — 94 33 — 94 33 Gross decreases—uncertain tax positions in prior period (273 ) — (2 ) (273 ) — (2 ) Gross increases—current period uncertain tax positions 21 207 2 21 207 2 Unrecognized tax benefits, December 31 $ 98 $ 350 $ 49 $ 98 $ 350 $ 49 During 2013 and 2014, the Company amended certain of its income tax returns to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). The Company also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016 and 2017, the Company claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the Nuclear Project, in its 2015 and 2016 income tax returns. The Company expects to claim similar deductions and credits in its 2017 tax return when it is filed in 2018. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. The IRS examined the claims in the amended returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2015 income tax returns, and it is expected that the IRS will also examine later returns. These IRC Section 174 income tax deductions and IRC Section 41 credits were considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities were recorded as unrecognized tax benefits in the financial statements. Following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G anticipate that an abandonment loss deduction under IRC Section 165 will be claimed on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, would instead 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 December 31, 2017. 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 December 31, 2017, 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 December 31, 2017. In connection with the research and experimentation deduction and credit claims reflected on the 2015 and 2016 income tax returns and similar claims made in determining taxable income for 2017, and under the terms 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 (see Note 2). However, as further described in Note 10, as of December 31, 2017, an impairment loss with respect to such deferred regulatory asset was recorded. SCE&G's current customer rates reflect the availability of domestic production activities deductions. Also under the terms 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. Amounts recorded for such interest income, interest expense or tax penalties have not been material for any period presented.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2017
Derivative [Line Items]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	6. 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 Audit Committee of 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 are not designated for accounting purposes as cash flow hedges and fair value changes and settlement amounts related to them have been recorded as regulatory assets and liabilities. Settlement losses on swaps have generally been amortized over the lives of subsequent debt issuances and gains have been amortized to interest expense or may be applied as otherwise directed by the SCPSC. However, see Note 10 for a discussion of the impairment of previously deferred regulatory asset amounts related to settlement losses on swaps that had been entered into for debt that was anticipated to be issued in connection with the Nuclear Project. 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 December 31, 2017 Commodity 6,430,000 13,433,000 19,863,000 Energy Management (a) — 41,856,890 41,856,890 Total (a) 6,430,000 55,289,890 61,719,890 As of December 31, 2016 Commodity 4,510,000 11,947,000 16,457,000 Energy Management (a) — 67,447,223 67,447,223 Total (a) 4,510,000 79,394,223 83,904,223 (a) Includes amounts related to basis swap contracts totaling 2,582,000 MMBTU in 2017 and 730,721 MMBTU in 2016. The aggregate notional amounts of the interest rate swaps were as follows: The Company Consolidated SCE&G Millions of dollars December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Designated as hedging instruments $ 111.2 $ 115.6 $ 36.4 $ 36.4 Not designated as hedging instruments 735.0 1,285.0 735.0 1,285.0 The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown. Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of December 31, 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 liabilities 1 Total — $ 30 — $ 10 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets 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 As of December 31, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 24 8 Commodity contracts Prepayments $ 5 Other current assets 1 Total $ 6 $ 28 — $ 9 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 71 $ 71 Derivative financial instruments $ 27 $ 27 Other deferred credits and other liabilities 3 3 Commodity contracts Other current assets 3 Energy management contracts Prepayments 6 2 Other current assets 2 1 Other deferred debits and other assets 2 Derivative financial instruments 4 Other deferred credits and other liabilities 2 Total $ 84 $ 39 $ 71 $ 30 Derivatives Designated as Fair Value Hedges The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented. Derivatives in Cash Flow Hedging Relationships The effect of derivative instruments on the consolidated statements of income is as follows: The Company and Consolidated SCE&G: Loss Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2017 Interest rate contracts $ (2 ) Interest expense $ (2 ) Year Ended December 31, 2016 Interest rate contracts — Interest expense $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (3 ) Interest expense $ (3 ) The Company: Gain or (Loss) Recognized in OCI, net of tax Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2017 Interest rate contracts — Interest expense $ (7 ) Commodity contracts $ (7 ) Gas purchased for resale 1 Total $ (7 ) $ (6 ) Year Ended December 31, 2016 Interest rate contracts $ (1 ) Interest expense $ (7 ) Commodity contracts 5 Gas purchased for resale (6 ) Total $ 4 $ (13 ) Year Ended December 31, 2015 Interest rate contracts $ (2 ) Interest expense $ (7 ) Commodity contracts (10 ) Gas purchased for resale (15 ) Total $ (12 ) $ (22 ) As of December 31, 2017, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $3.3 million as an increase to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.2 million as an increase to interest expense, assuming financial markets remain at their current levels. As of December 31, 2017, all of the Company’s commodity cash flow hedges settle by their terms before the end of the fourth quarter of 2020. As of December 31, 2017, 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 $1.5 million as an increase to interest expense assuming financial markets remain at their current levels. Hedge Ineffectiveness For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant for all periods presented. Derivatives Not Designated as Hedging Instruments The Company and Consolidated SCE&G: Loss Deferred in Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars Regulatory Accounts Location Amount Year Ended December 31, 2017 Interest rate contracts $ (32 ) Interest Expense $ (3 ) Interest rate contracts Impairment Loss (173 ) Year Ended December 31, 2016 Interest rate contracts $ (34 ) Other income $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (69 ) Other income $ 5 Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. For more discussion of amounts reclassified to Impairment Loss, see Note 10. As of December 31, 2017, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from interest rate swaps not designated as cash flow hedges will include approximately $2.7 million as an increase to interest expense. Credit Risk Considerations Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral. Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 33.7 $ 50.3 $ 14.7 $ 30.3 Fair value of collateral already posted 28.9 29.2 10.1 9.2 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 4.8 21.1 4.6 21.1 in Net Asset Position Aggregate fair value of derivatives in net asset position $ 53.5 $ 62.9 $ 53.5 $ 62.0 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 62.9 53.5 62.0 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 $1.2 million related to $4.0 million in commodity derivatives that are in a net asset position at December 31, 2017, compared to letters of credit of $1.5 million related to derivatives of $9.0 million at December 31, 2016, if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting derivative assets follows: Derivative Assets The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 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 As of December 31, 2016 Gross Amounts of Recognized Assets $ 71 $ 9 $ 10 $ 90 $ 71 Gross Amounts Offset in Statement of Financial Position (4 ) (4 ) Net Amounts Presented in Statement of Financial Position 71 9 6 86 71 Gross Amounts Not Offset - Financial Instruments (9 ) (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Received Net Amount $ 62 $ 9 $ 6 $ 77 $ 62 Balance sheet location Prepayments $ 9 Other current assets 5 Other deferred debits and other assets 72 $ 71 Total $ 86 $ 71 Information related to the offsetting of derivative liabilities follows: Derivative Liabilities The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 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 As of December 31, 2016 Gross Amounts of Recognized Liabilities $ 58 $ 9 $ 67 $ 39 Gross Amounts Offset in Statement of Financial Position (3 ) (3 ) Net Amounts Presented in Statement of Financial Position 58 — 6 64 39 Gross Amounts Not Offset - Financial Instruments (9 ) (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Posted (29 ) (29 ) (9 ) Net Amount $ 20 — $ 6 $ 26 $ 21 Balance sheet location Derivative financial instruments $ 35 $ 28 Other deferred credits and other liabilities 29 11 Total $ 64 $ 39
SCE&G
Derivative [Line Items]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	6. 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 Audit Committee of 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 are not designated for accounting purposes as cash flow hedges and fair value changes and settlement amounts related to them have been recorded as regulatory assets and liabilities. Settlement losses on swaps have generally been amortized over the lives of subsequent debt issuances and gains have been amortized to interest expense or may be applied as otherwise directed by the SCPSC. However, see Note 10 for a discussion of the impairment of previously deferred regulatory asset amounts related to settlement losses on swaps that had been entered into for debt that was anticipated to be issued in connection with the Nuclear Project. 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 December 31, 2017 Commodity 6,430,000 13,433,000 19,863,000 Energy Management (a) — 41,856,890 41,856,890 Total (a) 6,430,000 55,289,890 61,719,890 As of December 31, 2016 Commodity 4,510,000 11,947,000 16,457,000 Energy Management (a) — 67,447,223 67,447,223 Total (a) 4,510,000 79,394,223 83,904,223 (a) Includes amounts related to basis swap contracts totaling 2,582,000 MMBTU in 2017 and 730,721 MMBTU in 2016. The aggregate notional amounts of the interest rate swaps were as follows: The Company Consolidated SCE&G Millions of dollars December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Designated as hedging instruments $ 111.2 $ 115.6 $ 36.4 $ 36.4 Not designated as hedging instruments 735.0 1,285.0 735.0 1,285.0 The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown. Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of December 31, 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 liabilities 1 Total — $ 30 — $ 10 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets 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 As of December 31, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 24 8 Commodity contracts Prepayments $ 5 Other current assets 1 Total $ 6 $ 28 — $ 9 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 71 $ 71 Derivative financial instruments $ 27 $ 27 Other deferred credits and other liabilities 3 3 Commodity contracts Other current assets 3 Energy management contracts Prepayments 6 2 Other current assets 2 1 Other deferred debits and other assets 2 Derivative financial instruments 4 Other deferred credits and other liabilities 2 Total $ 84 $ 39 $ 71 $ 30 Derivatives Designated as Fair Value Hedges The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented. Derivatives in Cash Flow Hedging Relationships The effect of derivative instruments on the consolidated statements of income is as follows: The Company and Consolidated SCE&G: Loss Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2017 Interest rate contracts $ (2 ) Interest expense $ (2 ) Year Ended December 31, 2016 Interest rate contracts — Interest expense $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (3 ) Interest expense $ (3 ) The Company: Gain or (Loss) Recognized in OCI, net of tax Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2017 Interest rate contracts — Interest expense $ (7 ) Commodity contracts $ (7 ) Gas purchased for resale 1 Total $ (7 ) $ (6 ) Year Ended December 31, 2016 Interest rate contracts $ (1 ) Interest expense $ (7 ) Commodity contracts 5 Gas purchased for resale (6 ) Total $ 4 $ (13 ) Year Ended December 31, 2015 Interest rate contracts $ (2 ) Interest expense $ (7 ) Commodity contracts (10 ) Gas purchased for resale (15 ) Total $ (12 ) $ (22 ) As of December 31, 2017, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $3.3 million as an increase to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.2 million as an increase to interest expense, assuming financial markets remain at their current levels. As of December 31, 2017, all of the Company’s commodity cash flow hedges settle by their terms before the end of the fourth quarter of 2020. As of December 31, 2017, 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 $1.5 million as an increase to interest expense assuming financial markets remain at their current levels. Hedge Ineffectiveness For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant for all periods presented. Derivatives Not Designated as Hedging Instruments The Company and Consolidated SCE&G: Loss Deferred in Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars Regulatory Accounts Location Amount Year Ended December 31, 2017 Interest rate contracts $ (32 ) Interest Expense $ (3 ) Interest rate contracts Impairment Loss (173 ) Year Ended December 31, 2016 Interest rate contracts $ (34 ) Other income $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (69 ) Other income $ 5 Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. For more discussion of amounts reclassified to Impairment Loss, see Note 10. As of December 31, 2017, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from interest rate swaps not designated as cash flow hedges will include approximately $2.7 million as an increase to interest expense. Credit Risk Considerations Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral. Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 33.7 $ 50.3 $ 14.7 $ 30.3 Fair value of collateral already posted 28.9 29.2 10.1 9.2 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 4.8 21.1 4.6 21.1 in Net Asset Position Aggregate fair value of derivatives in net asset position $ 53.5 $ 62.9 $ 53.5 $ 62.0 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 62.9 53.5 62.0 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 $1.2 million related to $4.0 million in commodity derivatives that are in a net asset position at December 31, 2017, compared to letters of credit of $1.5 million related to derivatives of $9.0 million at December 31, 2016, if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting derivative assets follows: Derivative Assets The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 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 As of December 31, 2016 Gross Amounts of Recognized Assets $ 71 $ 9 $ 10 $ 90 $ 71 Gross Amounts Offset in Statement of Financial Position (4 ) (4 ) Net Amounts Presented in Statement of Financial Position 71 9 6 86 71 Gross Amounts Not Offset - Financial Instruments (9 ) (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Received Net Amount $ 62 $ 9 $ 6 $ 77 $ 62 Balance sheet location Prepayments $ 9 Other current assets 5 Other deferred debits and other assets 72 $ 71 Total $ 86 $ 71 Information related to the offsetting of derivative liabilities follows: Derivative Liabilities The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 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 As of December 31, 2016 Gross Amounts of Recognized Liabilities $ 58 $ 9 $ 67 $ 39 Gross Amounts Offset in Statement of Financial Position (3 ) (3 ) Net Amounts Presented in Statement of Financial Position 58 — 6 64 39 Gross Amounts Not Offset - Financial Instruments (9 ) (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Posted (29 ) (29 ) (9 ) Net Amount $ 20 — $ 6 $ 26 $ 21 Balance sheet location Derivative financial instruments $ 35 $ 28 Other deferred credits and other liabilities 29 11 Total $ 64 $ 39

FAIR VALUE MEASUREMENTS, INCLUD

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES	12 Months Ended
	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosures [Text Block]	7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES Available for sale securities are valued using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded or are open-ended mutual funds registered with the SEC which 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. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: As of December 31, 2017 As of December 31, 2016 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 1 Level 2 Level 1 Level 2 Level 2 Assets: Available for sale securities $ 119 — $ 100 — $ 14 — — Held to maturity securities — $ 6 — — — $ 7 — Interest rate contracts — 54 — $ 54 — 71 $ 71 Commodity contracts 1 — — — 8 1 — Energy management contracts — 4 — — 6 4 — Liabilities: Interest rate contracts — 32 — 15 — 58 39 Commodity contracts 2 1 — — — — — Energy management contracts 1 4 — — 2 10 — There were 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 the periods presented. Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2017 and December 31, 2016 were as follows: As of December 31, 2017 As of December 31, 2016 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,632.9 $ 7,399.7 $ 6,489.8 $ 7,183.3 Consolidated SCE&G 5,163.3 5,790.3 5,166.0 5,752.3 Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent. Carrying values of short-term borrowings approximate their fair values, which are based on quoted prices from dealers in the commercial paper market. These fair values are considered to be Level 2. In connection with the impairment loss described in Note 10, the Company and Consolidated SCE&G determined that the fair value of certain of their nuclear fuel was lower than its carrying amount. At December 31, 2017, this nuclear fuel had an estimated fair value of $43.8 million. This estimate is based on quoted prices received from vendors of nuclear fuel, which are considered to be Level 3 fair value measurements. The Company and Consolidated SCE&G assess the fair value of nuclear fuel in connection with the analysis of impairment described in Note 10 on a quarterly basis.
SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosures [Text Block]	7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES Available for sale securities are valued using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded or are open-ended mutual funds registered with the SEC which 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. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: As of December 31, 2017 As of December 31, 2016 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 1 Level 2 Level 1 Level 2 Level 2 Assets: Available for sale securities $ 119 — $ 100 — $ 14 — — Held to maturity securities — $ 6 — — — $ 7 — Interest rate contracts — 54 — $ 54 — 71 $ 71 Commodity contracts 1 — — — 8 1 — Energy management contracts — 4 — — 6 4 — Liabilities: Interest rate contracts — 32 — 15 — 58 39 Commodity contracts 2 1 — — — — — Energy management contracts 1 4 — — 2 10 — There were 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 the periods presented. Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2017 and December 31, 2016 were as follows: As of December 31, 2017 As of December 31, 2016 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,632.9 $ 7,399.7 $ 6,489.8 $ 7,183.3 Consolidated SCE&G 5,163.3 5,790.3 5,166.0 5,752.3 Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent. Carrying values of short-term borrowings approximate their fair values, which are based on quoted prices from dealers in the commercial paper market. These fair values are considered to be Level 2. In connection with the impairment loss described in Note 10, the Company and Consolidated SCE&G determined that the fair value of certain of their nuclear fuel was lower than its carrying amount. At December 31, 2017, this nuclear fuel had an estimated fair value of $43.8 million. This estimate is based on quoted prices received from vendors of nuclear fuel, which are considered to be Level 3 fair value measurements. The Company and Consolidated SCE&G assess the fair value of nuclear fuel in connection with the analysis of impairment described in Note 10 on a quarterly basis.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2017
Pension and Other Postretirement Benefit Plans
Pension and Other Postretirement Benefits Disclosure [Text Block]	EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN Pension and Other Postretirement Benefit Plans SCANA sponsors a noncontributory defined benefit pension plan covering regular, full-time employees hired before January 1, 2014. SCE&G participates in SCANA's pension plan. SCANA’s policy has been to fund the plan as permitted by applicable federal income tax regulations, as determined by an independent actuary. The pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and all eligible employees hired subsequently. Under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits. Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment. Benefits under the cash balance formula and the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued except that participants under the cash balance formula will continue to earn interest credits. In addition to pension benefits, SCANA provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. SCE&G participates in these programs. Retirees hired before January 1, 2011 share in a portion of their medical care cost, while employees hired subsequently are responsible for the full cost of retiree medical benefits elected by them. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits. The same benefit formula applies to all SCANA subsidiaries participating in the parent sponsored plans and, with regard to the pension plan, there are no legally separate asset pools. The postretirement benefit plans are accounted for as multiple employer plans. Changes in Benefit Obligations The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below. The Company Consolidated SCE&G Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2017 2016 2017 2016 2017 2016 Benefit obligation, January 1 $ 904.3 $ 855.4 $ 274.7 $ 253.6 $ 768.4 $ 724.0 $ 207.2 $ 191.7 Service cost 21.7 20.7 4.5 4.4 18.1 16.9 3.7 3.6 Interest cost 37.4 39.4 11.5 12.1 31.9 33.4 9.5 9.9 Plan participants’ contributions — — 1.3 1.7 — — 1.1 1.3 Actuarial (gain) loss 42.2 45.0 9.7 14.0 36.6 41.8 6.8 11.5 Benefits paid (72.4 ) (56.2 ) (12.5 ) (11.1 ) (62.0 ) (47.7 ) (10.3 ) (9.1 ) Amounts Funded to parent n/a n/a n/a n/a — — (1.4 ) (1.7 ) Benefit obligation, December 31 $ 933.2 $ 904.3 $ 289.2 $ 274.7 $ 793.0 $ 768.4 $ 216.6 $ 207.2 The accumulated benefit obligation for pension benefits for the Company was $ 905.8 million at the end of 2017 and $ 874.3 million at the end of 2016. The accumulated benefit obligation for pension benefits for Consolidated SCE&G was $769.7 million at the end of 2017 and $742.9 million at the end of 2016.The accumulated pension benefit obligation differs from the projected pension benefit obligation above in that it reflects no assumptions about future compensation levels. Significant assumptions used to determine the above benefit obligations are as follows: Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Annual discount rate used to determine benefit obligation 3.71 % 4.22 % 3.74 % 4.30 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 % A 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017. The rate was assumed to decrease gradually to 5.0% for 2023 and to remain at that level thereafter. A one percent increase in the assumed health care cost trend rate for the Company would increase the postretirement benefit obligation by $1.6 million at December 31, 2017 and by $0.8 million at December 31, 2016. A one percent decrease in the assumed health care cost trend rate for the Company would decrease the postretirement benefit obligation by $1.4 million at December 31, 2017 and by $0.7 million at December 31, 2016. A one percent increase in the assumed health care cost trend rate for Consolidated SCE&G would increase the postretirement benefit obligation by $1.3 million at December 31, 2017 and by $0.6 million at December 31, 2016. A one percent decrease in the assumed health care cost trend rate for Consolidated SCE&G would decrease the postretirement benefit obligation by $1.1 million at December 31, 2017 and by $0.6 million at December 31, 2016. Funded Status The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Fair value of plan assets $ 849.6 $ 793.6 — — $ 781.3 $ 732.9 — — Benefit obligation 933.2 904.3 $ 289.2 $ 274.7 793.0 768.4 $ 216.6 $ 207.2 Funded status $ (83.6 ) $ (110.7 ) $ (289.2 ) $ (274.7 ) $ (11.7 ) $ (35.5 ) $ (216.6 ) $ (207.2 ) Amounts recognized on the consolidated balance sheets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Current liability — — $ (13.5 ) $ (12.6 ) — — $ (10.8 ) $ (10.4 ) Noncurrent liability $ (83.6 ) $ (110.7 ) (275.7 ) (262.1 ) $ (11.7 ) $ (35.5 ) (205.8 ) (196.8 ) Amounts recognized in accumulated other comprehensive loss were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Net actuarial loss $ 8.8 $ 10.4 $ 3.5 $ 2.5 $ 2.1 $ 1.9 $ 1.5 $ 1.0 Prior service cost 0.1 0.1 — — — — — — Total $ 8.9 $ 10.5 $ 3.5 $ 2.5 $ 2.1 $ 1.9 $ 1.5 $ 1.0 Amounts recognized in regulatory assets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Net actuarial loss $ 194.8 $ 236.1 $ 43.3 $ 34.7 $ 171.4 $ 208.8 $ 35.9 $ 29.3 Prior service cost 1.2 2.5 — — 1.0 2.2 — — Total $ 196.0 $ 238.6 $ 43.3 $ 34.7 $ 172.4 $ 211.0 $ 35.9 $ 29.3 In connection with the joint ownership of Summer Station, costs related to the pension benefit obligation attributable to Santee Cooper as of December 31, 2017 and 2016 totaled $21.4 million and $23.4 million, respectively, and was recorded within deferred debits. The unfunded postretirement benefit obligation attributable to Santee Cooper as of December 31, 2017 and 2016 totaled $14.7 million and $15.8 million, respectively, and also was recorded within deferred debits. Changes in Fair Value of Plan Assets Pension Benefits The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Fair value of plan assets, January 1 $ 793.6 $ 781.7 $ 732.9 $ 720.1 Actual return on plan assets 128.4 68.1 110.4 60.5 Benefits paid (72.4 ) (56.2 ) (62.0 ) (47.7 ) Fair value of plan assets, December 31 $ 849.6 $ 793.6 $ 781.3 $ 732.9 Investment Policies and Strategies The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the obligations of the pension plan, (2) overseeing the plan's investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and liabilities, and overall risk associated with assets as compared to liabilities, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. SCANA uses a dynamic investment strategy for the management of the pension plan assets. This strategy will lead to a reduction in equities and an increase in long duration fixed income allocations over time with the intention of reducing volatility of funded status and pension costs. The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, levels of diversification, investment managers and performance expectations. The total portfolio is constructed and maintained to provide prudent diversification with regard to the concentration of holdings in individual issues, corporations, or industries. Transactions involving certain types of investments are prohibited. These include, except where utilized by a hedge fund manager, any form of private equity; commodities or commodity contracts (except for unleveraged stock or bond index futures and currency futures and options); ownership of real estate in any form other than publicly traded securities; short sales, warrants or margin transactions, or any leveraged investments; and natural resource properties. Investments made for the purpose of engaging in speculative trading are also prohibited. The pension plan asset allocation at December 31, 2017 and 2016 and the target allocation for 2018 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2018 2017 2016 Equity Securities 58 % 58 % 57 % Fixed Income 33 % 31 % 32 % Hedge Funds 9 % 11 % 11 % For 2018, the expected long-term rate of return on assets will be 7% . In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, considers the expected active and passive returns across various asset classes and assumes the target allocation is achieved. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment strategy described previously. Fair Value Measurements Assets held by the pension plan are measured at fair value and are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2017 and 2016, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Investments with fair value measure at Level 2: Mutual funds $ 120 $ 125 $ 110 $ 115 Short-term investment vehicles 17 16 16 15 US Treasury securities 15 18 14 17 Corporate debt securities 91 82 84 76 Municipals 17 14 15 13 Total assets in the fair value hierarchy 260 255 239 236 Investments at net asset value: Common collective trust 498 453 458 418 Joint venture interests 92 86 84 79 Total investments at fair value $ 850 $ 794 $ 781 $ 733 For all periods presented, assets with fair value measurements classified as Level 1 were insignificant, and there were no assets with fair value measurements classified as Level 3. There were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during 2017 or 2016. Mutual funds held by the plan are open-ended mutual funds registered with the SEC. The price of the mutual funds' shares is based on its NAV, which is determined by dividing the total value of portfolio investments, less any liabilities, by the total number of shares outstanding. For purposes of calculating NAV, portfolio securities and other assets for which market quotes are readily available are valued at market value. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. US Treasury securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt securities and municipals are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Common collective trust assets and limited partnerships are valued at NAV, which has been determined based on the unit values of the trust funds. Unit values are determined by the organization sponsoring such trust funds by dividing the trust funds’ net assets at fair value by the units outstanding at each valuation date. Joint venture interests are invested in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and not traded on a daily basis. The valuation of such multi-strategy hedge fund of funds is estimated based on the NAV of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may influence their fair value. Expected Cash Flows Total benefits expected to be paid from the pension plan or company assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows: Expected Benefit Payments The Company Consolidated SCE&G Millions of dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits 2018 $ 66.9 $ 13.8 $ 66.9 $ 11.0 2019 64.6 14.6 64.6 11.7 2020 63.9 15.4 63.9 12.3 2021 66.5 16.0 66.5 12.8 2022 72.0 16.5 72.0 13.1 2023-2027 303.0 87.3 303.0 69.6 Pension Plan Contributions The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and as a result of closing the plan to new entrants and freezing benefit accruals at the end of 2023, no significant contributions to the pension plan are expected to be made for the foreseeable future based on current market conditions and assumptions. Net Periodic Benefit Cost Net periodic benefit cost is recorded utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables. Components of Net Periodic Benefit Cost The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Service cost $ 21.7 $ 20.7 $ 24.1 $ 4.5 $ 4.4 $ 5.3 Interest cost 37.4 39.4 38.2 11.5 12.1 11.4 Expected return on assets (54.7 ) (55.9 ) (62.0 ) n/a n/a n/a Prior service cost amortization 1.6 3.9 4.1 — 0.3 0.4 Amortization of actuarial losses 16.3 14.8 13.6 1.0 0.5 2.1 Net periodic benefit cost $ 22.3 $ 22.9 $ 18.0 $ 17.0 $ 17.3 $ 19.2 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Service cost $ 18.1 $ 16.9 $ 19.3 $ 3.7 $ 3.6 $ 4.4 Interest cost 31.9 33.4 32.2 9.5 9.9 9.4 Expected return on assets (46.7 ) (47.4 ) (52.2 ) n/a n/a n/a Prior service cost amortization 1.4 3.4 3.4 — 0.3 0.3 Amortization of actuarial losses 13.9 12.5 11.4 0.8 0.4 1.7 Net periodic benefit cost $ 18.6 $ 18.8 $ 14.1 $ 14.0 $ 14.2 $ 15.8 In connection with regulatory orders, SCE&G recovers current pension expense through a rate rider that may be adjusted annually (for retail electric operations) or through cost of service rates (for gas operations). For retail electric operations, current pension expense is recognized based on amounts collected through its rate rider, and differences between actual pension expense and amounts recognized pursuant to the rider are deferred as a regulatory asset (for under-collections) or regulatory liability (for over-collections) as applicable. In addition, SCE&G amortizes certain previously deferred pension costs. See Note 2. Other changes in plan assets and benefit obligations recognized in OCI (net of tax) were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Current year actuarial (gain) loss $ (1.0 ) $ 0.6 $ 2.7 $ 1.1 $ 0.8 $ (1.2 ) Amortization of actuarial losses (0.6 ) (0.6 ) (0.4 ) (0.1 ) — (0.1 ) Amortization of prior service cost — (0.1 ) (0.1 ) — — (0.1 ) Total recognized in OCI $ (1.6 ) $ (0.1 ) $ 2.2 $ 1.0 $ 0.8 $ (1.4 ) Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Current year actuarial (gain) loss $ 0.3 — $ 0.2 $ 0.5 $ 0.3 $ (0.3 ) Amortization of actuarial losses (0.1 ) $ (0.1 ) (0.1 ) — — — Amortization of prior service cost — — (0.1 ) — — — Total recognized in OCI $ 0.2 $ (0.1 ) — $ 0.5 $ 0.3 $ (0.3 ) Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Current year actuarial (gain) loss $ (27.1 ) $ 29.4 $ 9.2 $ 9.4 $ 11.1 $ (18.0 ) Amortization of actuarial losses (14.1 ) (12.7 ) (11.9 ) (0.8 ) (0.4 ) (1.8 ) Amortization of prior service cost (1.4 ) (3.4 ) (3.7 ) — (0.3 ) (0.3 ) Total recognized in regulatory assets $ (42.6 ) $ 13.3 $ (6.4 ) $ 8.6 $ 10.4 $ (20.1 ) Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Current year actuarial (gain) loss $ (24.8 ) $ 26.3 $ 12.2 $ 7.3 $ 9.2 $ (14.0 ) Amortization of actuarial losses (12.5 ) (11.2 ) (10.4 ) (0.7 ) (0.3 ) (1.5 ) Amortization of prior service cost (1.3 ) (3.0 ) (3.1 ) — (0.2 ) (0.3 ) Total recognized in regulatory assets $ (38.6 ) $ 12.1 $ (1.3 ) $ 6.6 $ 8.7 $ (15.8 ) Significant Assumptions Used in Determining Net Periodic Benefit Cost Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Discount rate 4.22 % 4.68 % 4.20 % 4.30 % 4.78 % 4.30 % Expected return on plan assets 7.25 % 7.50 % 7.50 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % Health care cost trend rate n/a n/a n/a 6.60 % 7.00 % 7.00 % Ultimate health care cost trend rate n/a n/a n/a 5.00 % 5.00 % 5.00 % Year achieved n/a n/a n/a 2021 2021 2020 The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2018 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant : Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 0.5 $ 0.1 The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2018 are as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Actuarial loss $ 10.2 $ 1.8 $ 9.0 $ 1.5 Prior service cost 0.4 — 0.4 — Total $ 10.6 $ 1.8 $ 9.4 $ 1.5 Other postretirement benefit costs are subject to annual per capita limits pursuant to the plan's design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is not significant. 401(k) Retirement Savings Plan SCANA sponsors a defined contribution plan in which eligible employees may defer up to 75% of eligible earnings subject to certain limits and may diversify their investments. SCE&G participates in this plan. Contributions are matched 100% up to 6% of an employee’s eligible earnings. Such matching contributions made by the Company totaled $27.9 million in 2017, $27.5 million in 2016 and $26.2 million in 2015. These matching contributions included those made by Consolidated SCE&G, which totaled $23.4 million in 2017, $22.9 million in 2016 and $21.8 million in 2015. Employee deferrals, matching contributions, and earnings on all contributions are fully vested and nonforfeitable at all times.
SCE&G
Pension and Other Postretirement Benefit Plans
Pension and Other Postretirement Benefits Disclosure [Text Block]	EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN Pension and Other Postretirement Benefit Plans SCANA sponsors a noncontributory defined benefit pension plan covering regular, full-time employees hired before January 1, 2014. SCE&G participates in SCANA's pension plan. SCANA’s policy has been to fund the plan as permitted by applicable federal income tax regulations, as determined by an independent actuary. The pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and all eligible employees hired subsequently. Under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits. Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment. Benefits under the cash balance formula and the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued except that participants under the cash balance formula will continue to earn interest credits. In addition to pension benefits, SCANA provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. SCE&G participates in these programs. Retirees hired before January 1, 2011 share in a portion of their medical care cost, while employees hired subsequently are responsible for the full cost of retiree medical benefits elected by them. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits. The same benefit formula applies to all SCANA subsidiaries participating in the parent sponsored plans and, with regard to the pension plan, there are no legally separate asset pools. The postretirement benefit plans are accounted for as multiple employer plans. Changes in Benefit Obligations The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below. The Company Consolidated SCE&G Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2017 2016 2017 2016 2017 2016 Benefit obligation, January 1 $ 904.3 $ 855.4 $ 274.7 $ 253.6 $ 768.4 $ 724.0 $ 207.2 $ 191.7 Service cost 21.7 20.7 4.5 4.4 18.1 16.9 3.7 3.6 Interest cost 37.4 39.4 11.5 12.1 31.9 33.4 9.5 9.9 Plan participants’ contributions — — 1.3 1.7 — — 1.1 1.3 Actuarial (gain) loss 42.2 45.0 9.7 14.0 36.6 41.8 6.8 11.5 Benefits paid (72.4 ) (56.2 ) (12.5 ) (11.1 ) (62.0 ) (47.7 ) (10.3 ) (9.1 ) Amounts Funded to parent n/a n/a n/a n/a — — (1.4 ) (1.7 ) Benefit obligation, December 31 $ 933.2 $ 904.3 $ 289.2 $ 274.7 $ 793.0 $ 768.4 $ 216.6 $ 207.2 The accumulated benefit obligation for pension benefits for the Company was $ 905.8 million at the end of 2017 and $ 874.3 million at the end of 2016. The accumulated benefit obligation for pension benefits for Consolidated SCE&G was $769.7 million at the end of 2017 and $742.9 million at the end of 2016.The accumulated pension benefit obligation differs from the projected pension benefit obligation above in that it reflects no assumptions about future compensation levels. Significant assumptions used to determine the above benefit obligations are as follows: Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Annual discount rate used to determine benefit obligation 3.71 % 4.22 % 3.74 % 4.30 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 % A 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017. The rate was assumed to decrease gradually to 5.0% for 2023 and to remain at that level thereafter. A one percent increase in the assumed health care cost trend rate for the Company would increase the postretirement benefit obligation by $1.6 million at December 31, 2017 and by $0.8 million at December 31, 2016. A one percent decrease in the assumed health care cost trend rate for the Company would decrease the postretirement benefit obligation by $1.4 million at December 31, 2017 and by $0.7 million at December 31, 2016. A one percent increase in the assumed health care cost trend rate for Consolidated SCE&G would increase the postretirement benefit obligation by $1.3 million at December 31, 2017 and by $0.6 million at December 31, 2016. A one percent decrease in the assumed health care cost trend rate for Consolidated SCE&G would decrease the postretirement benefit obligation by $1.1 million at December 31, 2017 and by $0.6 million at December 31, 2016. Funded Status The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Fair value of plan assets $ 849.6 $ 793.6 — — $ 781.3 $ 732.9 — — Benefit obligation 933.2 904.3 $ 289.2 $ 274.7 793.0 768.4 $ 216.6 $ 207.2 Funded status $ (83.6 ) $ (110.7 ) $ (289.2 ) $ (274.7 ) $ (11.7 ) $ (35.5 ) $ (216.6 ) $ (207.2 ) Amounts recognized on the consolidated balance sheets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Current liability — — $ (13.5 ) $ (12.6 ) — — $ (10.8 ) $ (10.4 ) Noncurrent liability $ (83.6 ) $ (110.7 ) (275.7 ) (262.1 ) $ (11.7 ) $ (35.5 ) (205.8 ) (196.8 ) Amounts recognized in accumulated other comprehensive loss were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Net actuarial loss $ 8.8 $ 10.4 $ 3.5 $ 2.5 $ 2.1 $ 1.9 $ 1.5 $ 1.0 Prior service cost 0.1 0.1 — — — — — — Total $ 8.9 $ 10.5 $ 3.5 $ 2.5 $ 2.1 $ 1.9 $ 1.5 $ 1.0 Amounts recognized in regulatory assets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Net actuarial loss $ 194.8 $ 236.1 $ 43.3 $ 34.7 $ 171.4 $ 208.8 $ 35.9 $ 29.3 Prior service cost 1.2 2.5 — — 1.0 2.2 — — Total $ 196.0 $ 238.6 $ 43.3 $ 34.7 $ 172.4 $ 211.0 $ 35.9 $ 29.3 In connection with the joint ownership of Summer Station, costs related to the pension benefit obligation attributable to Santee Cooper as of December 31, 2017 and 2016 totaled $21.4 million and $23.4 million, respectively, and was recorded within deferred debits. The unfunded postretirement benefit obligation attributable to Santee Cooper as of December 31, 2017 and 2016 totaled $14.7 million and $15.8 million, respectively, and also was recorded within deferred debits. Changes in Fair Value of Plan Assets Pension Benefits The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Fair value of plan assets, January 1 $ 793.6 $ 781.7 $ 732.9 $ 720.1 Actual return on plan assets 128.4 68.1 110.4 60.5 Benefits paid (72.4 ) (56.2 ) (62.0 ) (47.7 ) Fair value of plan assets, December 31 $ 849.6 $ 793.6 $ 781.3 $ 732.9 Investment Policies and Strategies The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the obligations of the pension plan, (2) overseeing the plan's investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and liabilities, and overall risk associated with assets as compared to liabilities, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. SCANA uses a dynamic investment strategy for the management of the pension plan assets. This strategy will lead to a reduction in equities and an increase in long duration fixed income allocations over time with the intention of reducing volatility of funded status and pension costs. The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, levels of diversification, investment managers and performance expectations. The total portfolio is constructed and maintained to provide prudent diversification with regard to the concentration of holdings in individual issues, corporations, or industries. Transactions involving certain types of investments are prohibited. These include, except where utilized by a hedge fund manager, any form of private equity; commodities or commodity contracts (except for unleveraged stock or bond index futures and currency futures and options); ownership of real estate in any form other than publicly traded securities; short sales, warrants or margin transactions, or any leveraged investments; and natural resource properties. Investments made for the purpose of engaging in speculative trading are also prohibited. The pension plan asset allocation at December 31, 2017 and 2016 and the target allocation for 2018 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2018 2017 2016 Equity Securities 58 % 58 % 57 % Fixed Income 33 % 31 % 32 % Hedge Funds 9 % 11 % 11 % For 2018, the expected long-term rate of return on assets will be 7% . In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, considers the expected active and passive returns across various asset classes and assumes the target allocation is achieved. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment strategy described previously. Fair Value Measurements Assets held by the pension plan are measured at fair value and are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2017 and 2016, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Investments with fair value measure at Level 2: Mutual funds $ 120 $ 125 $ 110 $ 115 Short-term investment vehicles 17 16 16 15 US Treasury securities 15 18 14 17 Corporate debt securities 91 82 84 76 Municipals 17 14 15 13 Total assets in the fair value hierarchy 260 255 239 236 Investments at net asset value: Common collective trust 498 453 458 418 Joint venture interests 92 86 84 79 Total investments at fair value $ 850 $ 794 $ 781 $ 733 For all periods presented, assets with fair value measurements classified as Level 1 were insignificant, and there were no assets with fair value measurements classified as Level 3. There were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during 2017 or 2016. Mutual funds held by the plan are open-ended mutual funds registered with the SEC. The price of the mutual funds' shares is based on its NAV, which is determined by dividing the total value of portfolio investments, less any liabilities, by the total number of shares outstanding. For purposes of calculating NAV, portfolio securities and other assets for which market quotes are readily available are valued at market value. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. US Treasury securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt securities and municipals are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Common collective trust assets and limited partnerships are valued at NAV, which has been determined based on the unit values of the trust funds. Unit values are determined by the organization sponsoring such trust funds by dividing the trust funds’ net assets at fair value by the units outstanding at each valuation date. Joint venture interests are invested in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and not traded on a daily basis. The valuation of such multi-strategy hedge fund of funds is estimated based on the NAV of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may influence their fair value. Expected Cash Flows Total benefits expected to be paid from the pension plan or company assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows: Expected Benefit Payments The Company Consolidated SCE&G Millions of dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits 2018 $ 66.9 $ 13.8 $ 66.9 $ 11.0 2019 64.6 14.6 64.6 11.7 2020 63.9 15.4 63.9 12.3 2021 66.5 16.0 66.5 12.8 2022 72.0 16.5 72.0 13.1 2023-2027 303.0 87.3 303.0 69.6 Pension Plan Contributions The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and as a result of closing the plan to new entrants and freezing benefit accruals at the end of 2023, no significant contributions to the pension plan are expected to be made for the foreseeable future based on current market conditions and assumptions. Net Periodic Benefit Cost Net periodic benefit cost is recorded utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables. Components of Net Periodic Benefit Cost The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Service cost $ 21.7 $ 20.7 $ 24.1 $ 4.5 $ 4.4 $ 5.3 Interest cost 37.4 39.4 38.2 11.5 12.1 11.4 Expected return on assets (54.7 ) (55.9 ) (62.0 ) n/a n/a n/a Prior service cost amortization 1.6 3.9 4.1 — 0.3 0.4 Amortization of actuarial losses 16.3 14.8 13.6 1.0 0.5 2.1 Net periodic benefit cost $ 22.3 $ 22.9 $ 18.0 $ 17.0 $ 17.3 $ 19.2 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Service cost $ 18.1 $ 16.9 $ 19.3 $ 3.7 $ 3.6 $ 4.4 Interest cost 31.9 33.4 32.2 9.5 9.9 9.4 Expected return on assets (46.7 ) (47.4 ) (52.2 ) n/a n/a n/a Prior service cost amortization 1.4 3.4 3.4 — 0.3 0.3 Amortization of actuarial losses 13.9 12.5 11.4 0.8 0.4 1.7 Net periodic benefit cost $ 18.6 $ 18.8 $ 14.1 $ 14.0 $ 14.2 $ 15.8 In connection with regulatory orders, SCE&G recovers current pension expense through a rate rider that may be adjusted annually (for retail electric operations) or through cost of service rates (for gas operations). For retail electric operations, current pension expense is recognized based on amounts collected through its rate rider, and differences between actual pension expense and amounts recognized pursuant to the rider are deferred as a regulatory asset (for under-collections) or regulatory liability (for over-collections) as applicable. In addition, SCE&G amortizes certain previously deferred pension costs. See Note 2. Other changes in plan assets and benefit obligations recognized in OCI (net of tax) were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Current year actuarial (gain) loss $ (1.0 ) $ 0.6 $ 2.7 $ 1.1 $ 0.8 $ (1.2 ) Amortization of actuarial losses (0.6 ) (0.6 ) (0.4 ) (0.1 ) — (0.1 ) Amortization of prior service cost — (0.1 ) (0.1 ) — — (0.1 ) Total recognized in OCI $ (1.6 ) $ (0.1 ) $ 2.2 $ 1.0 $ 0.8 $ (1.4 ) Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Current year actuarial (gain) loss $ 0.3 — $ 0.2 $ 0.5 $ 0.3 $ (0.3 ) Amortization of actuarial losses (0.1 ) $ (0.1 ) (0.1 ) — — — Amortization of prior service cost — — (0.1 ) — — — Total recognized in OCI $ 0.2 $ (0.1 ) — $ 0.5 $ 0.3 $ (0.3 ) Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Current year actuarial (gain) loss $ (27.1 ) $ 29.4 $ 9.2 $ 9.4 $ 11.1 $ (18.0 ) Amortization of actuarial losses (14.1 ) (12.7 ) (11.9 ) (0.8 ) (0.4 ) (1.8 ) Amortization of prior service cost (1.4 ) (3.4 ) (3.7 ) — (0.3 ) (0.3 ) Total recognized in regulatory assets $ (42.6 ) $ 13.3 $ (6.4 ) $ 8.6 $ 10.4 $ (20.1 ) Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Current year actuarial (gain) loss $ (24.8 ) $ 26.3 $ 12.2 $ 7.3 $ 9.2 $ (14.0 ) Amortization of actuarial losses (12.5 ) (11.2 ) (10.4 ) (0.7 ) (0.3 ) (1.5 ) Amortization of prior service cost (1.3 ) (3.0 ) (3.1 ) — (0.2 ) (0.3 ) Total recognized in regulatory assets $ (38.6 ) $ 12.1 $ (1.3 ) $ 6.6 $ 8.7 $ (15.8 ) Significant Assumptions Used in Determining Net Periodic Benefit Cost Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Discount rate 4.22 % 4.68 % 4.20 % 4.30 % 4.78 % 4.30 % Expected return on plan assets 7.25 % 7.50 % 7.50 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % Health care cost trend rate n/a n/a n/a 6.60 % 7.00 % 7.00 % Ultimate health care cost trend rate n/a n/a n/a 5.00 % 5.00 % 5.00 % Year achieved n/a n/a n/a 2021 2021 2020 The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2018 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant : Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 0.5 $ 0.1 The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2018 are as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Actuarial loss $ 10.2 $ 1.8 $ 9.0 $ 1.5 Prior service cost 0.4 — 0.4 — Total $ 10.6 $ 1.8 $ 9.4 $ 1.5 Other postretirement benefit costs are subject to annual per capita limits pursuant to the plan's design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is not significant. 401(k) Retirement Savings Plan SCANA sponsors a defined contribution plan in which eligible employees may defer up to 75% of eligible earnings subject to certain limits and may diversify their investments. SCE&G participates in this plan. Contributions are matched 100% up to 6% of an employee’s eligible earnings. Such matching contributions made by the Company totaled $27.9 million in 2017, $27.5 million in 2016 and $26.2 million in 2015. These matching contributions included those made by Consolidated SCE&G, which totaled $23.4 million in 2017, $22.9 million in 2016 and $21.8 million in 2015. Employee deferrals, matching contributions, and earnings on all contributions are fully vested and nonforfeitable at all times.

SHARE-BASED COMPENSATION

SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2017
Share-Based Compensation
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	SHARE-BASED COMPENSATION The LTECP provides for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The LTECP currently authorizes the issuance of up to five million shares of SCANA’s common stock, no more than one million of which may be granted in the form of restricted stock. Compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. Share-based payment awards do not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves do not vest, dividends or dividend equivalents which would have been paid on those awards do not vest. The 2015-2017, 2016-2018 and 2017-2019 performance cycles provide for performance measurement and award determination based on performance over a single three -year cycle, with payment of awards being deferred until after the end of the three -year performance cycle. In each of these performance cycles, 30% of the performance awards were granted in the form of restricted share units, which are liability awards payable in cash, and 70% of the awards were granted in performance shares, each of which has a value that is equal to, and changes with, the value of a share of SCANA common stock. Dividend equivalents are accrued on the performance shares and the restricted share units. Performance awards and related dividend equivalents are subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to certain exceptions. Payouts of performance share awards are determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50% ) and growth in GAAP-adjusted net earnings per share (weighted 50% ). Compensation cost of liability awards is recognized over their respective three -year performance periods based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities related to performance cycles totaled approximately $ 28.0 million in 2017, $ 18.4 million in 2016 and $ 20.8 million in 2015 for the Company and approximately $ 20.2 million in 2017, $ 13.2 million in 2016 and $ 6.3 million in 2015 for Consolidated SCE&G. Fair value adjustments for all performance cycles resulted in compensation expense (benefit) recognized in the statements of operations totaling approximately $ (9.0) million in 2017, $ 25.6 million in 2016 and $ 18.0 million in 2015 for the Company, of which approximately $ (6.3) million in 2017, $ 17.3 million in 2016 and $ 12.2 million in 2015 for Consolidated SCE&G (including amounts allocated from SCANA Services). Such fair value adjustments also resulted in capitalized compensation costs of $ (1.3) million in 2017, $ 3.3 million in 2016 and $ 2.3 million in 2015 for the Company and $ (0.9) million in 2017, $ 3.1 million in 2016 and $ 0.6 million in 2015 for Consolidated SCE&G. At December 31, 2017, unrecognized compensation cost, which is expected to be recognized over a weighted-average period of 18 months , was $ 5.4 million for the Company and $ 4.1 million for Consolidated SCE&G. Large declines in stock price and relative performance in 2017 resulted in reductions of liabilities previously accrued with respect to open performance cycles. In the event of consummation of the merger, additional compensation cost arising from these liability awards may also be recognized.
SCE&G
Share-Based Compensation
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	9. SHARE-BASED COMPENSATION The LTECP provides for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The LTECP currently authorizes the issuance of up to five million shares of SCANA’s common stock, no more than one million of which may be granted in the form of restricted stock. Compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. Share-based payment awards do not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves do not vest, dividends or dividend equivalents which would have been paid on those awards do not vest. The 2015-2017, 2016-2018 and 2017-2019 performance cycles provide for performance measurement and award determination based on performance over a single three -year cycle, with payment of awards being deferred until after the end of the three -year performance cycle. In each of these performance cycles, 30% of the performance awards were granted in the form of restricted share units, which are liability awards payable in cash, and 70% of the awards were granted in performance shares, each of which has a value that is equal to, and changes with, the value of a share of SCANA common stock. Dividend equivalents are accrued on the performance shares and the restricted share units. Performance awards and related dividend equivalents are subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to certain exceptions. Payouts of performance share awards are determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50% ) and growth in GAAP-adjusted net earnings per share (weighted 50% ). Compensation cost of liability awards is recognized over their respective three -year performance periods based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities related to performance cycles totaled approximately $ 28.0 million in 2017, $ 18.4 million in 2016 and $ 20.8 million in 2015 for the Company and approximately $ 20.2 million in 2017, $ 13.2 million in 2016 and $ 6.3 million in 2015 for Consolidated SCE&G. Fair value adjustments for all performance cycles resulted in compensation expense (benefit) recognized in the statements of operations totaling approximately $ (9.0) million in 2017, $ 25.6 million in 2016 and $ 18.0 million in 2015 for the Company, of which approximately $ (6.3) million in 2017, $ 17.3 million in 2016 and $ 12.2 million in 2015 for Consolidated SCE&G (including amounts allocated from SCANA Services). Such fair value adjustments also resulted in capitalized compensation costs of $ (1.3) million in 2017, $ 3.3 million in 2016 and $ 2.3 million in 2015 for the Company and $ (0.9) million in 2017, $ 3.1 million in 2016 and $ 0.6 million in 2015 for Consolidated SCE&G. At December 31, 2017, unrecognized compensation cost, which is expected to be recognized over a weighted-average period of 18 months , was $ 5.4 million for the Company and $ 4.1 million for Consolidated SCE&G. Large declines in stock price and relative performance in 2017 resulted in reductions of liabilities previously accrued with respect to open performance cycles. In the event of consummation of the merger, additional compensation cost arising from these liability awards may also be recognized.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Commitment [Line Items]
Commitments and Contingencies Disclosure [Text Block]	Nuclear Project SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. SCE&G's ownership share in these units is 55% . As discussed below, various difficulties were encountered in connection with the project. The ability of the Consortium to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters, and others more fully discussed below, were the subject of comprehensive analyses performed by the Company and Santee Cooper (see Contractor Bankruptcy Proceedings and Related Uncertainties below). Based on the results of the Company's analysis, and in light of Santee Cooper's decision to suspend construction on Unit 2 and Unit 3, on July 31, 2017, the Company determined to stop the construction of the units and to pursue recovery of costs incurred in connection with such construction under the abandonment provisions of the BLRA or through other means. EPC Contract and BLRA Matters The Nuclear Project and SCE&G’s related recovery of financing costs through rates has been subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC approved, among other things, a milestone schedule and a capital costs estimates schedule for Unit 2 and Unit 3. Pursuant to the BLRA, this approval constituted a final and binding determination that the units were used and useful for utility purposes, and that the capital costs associated with them were prudent utility costs and expenses and were properly included in rates, so long as Unit 2 and Unit 3 were constructed or were being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the Nuclear Project. As of December 31, 2017, financing costs on $3.5 billion of SCE&G's construction costs for the Nuclear Project, excluding related transmission assets, have been reflected in revised rates under the BLRA, with the last revised rates increase having gone into effect in November 2016. SCE&G estimates that revised rates collections that have accumulated as of December 31, 2017, including collections related to transmission assets expected to be placed into service, total approximately $1.9 billion . As a result of the decision to abandon the Nuclear Project, amounts reclassified from construction work in progress into regulatory assets, net of impairments described below, are summarized as follows: Unrecovered Nuclear Project Costs Millions of dollars Nuclear Project costs as of September 30, 2017, prior to impairment loss and excluding transmission assets $ 4,730 Less Impairment loss recorded in the third quarter of 2017 (See below) 210 Balance of unrecovered Nuclear Project costs as of September 30, 2017 4,520 Less Impairment loss recorded in the fourth quarter of 2017 (See below) 460 Less Nuclear Project and switchyard assets transferred for use by Unit 1 84 Balance of unrecovered Nuclear Project costs as of December 31, 2017 (See Note 2) $ 3,976 The SCPSC granted initial approval of the construction schedule and related forecasted capital costs in 2009. The NRC issued combined Construction and Operating Licenses in March 2012. In November 2012, and again in September 2015 and November 2016 (see discussion below), the SCPSC approved SCE&G's requested updates to the milestone schedule, revised contractual substantial completion dates, and increases in capital and other costs. As further discussed below, under the current regulatory construct in South Carolina, approval by the SCPSC of cost recovery under the abandonment provisions of the BLRA or through other means will be required as a consequence of the Company’s determination on July 31, 2017 to cease construction of the Nuclear Project. October 2015 Amendment and WEC's Engagement of Fluor On October 27, 2015, SCE&G, Santee Cooper and the Consortium amended the EPC Contract. The amendment became effective in December 2015, at which time Fluor began serving as a subcontracted construction manager for the Consortium. The October 2015 Amendment provided SCE&G and Santee Cooper an option to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be reduced by amounts paid since June 30, 2015. SCE&G, on behalf of itself and as agent for Santee Cooper, elected the fixed price option, subject to SCPSC approval, on July 1, 2016. Among other things, the October 2015 Amendment revised the contractual guaranteed substantial completion dates of Unit 2 and Unit 3 to August 31, 2019 and August 31, 2020, respectively, and provided for development of a revised construction milestone payment schedule. In February 2017, WEC notified the Company and Consolidated SCE&G that the contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Unit 2 and Unit 3, respectively, which were reflected in the October 2015 Amendment, would not be met. Instead, WEC provided further revised estimated substantial completion dates of April 2020 and December 2020. November 2016 SCPSC Order In May 2016, SCE&G petitioned the SCPSC for approval of the updated construction and capital cost schedules for Unit 2 and Unit 3 which had been developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, the ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option. By order dated February 28, 2017, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement, and that order was not appealed. The construction schedule approved by the SCPSC in November 2016 provided for contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Unit 2 and Unit 3, respectively. The approved capital cost schedule included incremental capital costs that totaled $831 million , raising SCE&G's total project capital cost as then approved to an estimated amount of approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for the Nuclear Project from 10.5% to 10.25% . This revised ROE was to be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. No such revised rates have been sought since that time. 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. In connection with the bankruptcy filing, SCE&G, Santee Cooper, WEC and WECTEC entered into an Interim Assessment Agreement under which engineering and construction continued on the project and under which SCE&G and Santee Cooper were provided the right to discuss project status with Fluor and other subcontractors and vendors and to obtain from them relevant project information and documents that had been previously contractually unavailable in order for SCE&G and Santee Cooper to perform comprehensive analyses regarding whether or how to proceed with the Nuclear Project. As part of the Interim Assessment Agreement, and to avoid an immediate rejection of the EPC Contract upon the filing of the bankruptcy case, WEC and WECTEC required SCE&G and Santee Cooper to make estimated weekly payments to WEC, WECTEC, subcontractors and vendors, irrespective of the fixed price provisions of the EPC Contract, to permit the time to conduct analyses. SCE&G and Santee Cooper agreed to pay specified costs incurred by the Consortium, Fluor, other subcontractors and vendors for work performed or services rendered while the Interim Assessment Agreement remained in effect. During the period of the Interim Assessment Agreement, as amended and extended, SCE&G and Santee Cooper evaluated the various elements of the Nuclear Project, including forecasted costs and completion dates, while construction continued and SCE&G and Santee Cooper continued to make payments for such work. As part of its evaluation, SCE&G considered that, as a result of the bankruptcy process (including WEC and WECTEC's public announcements that they could not perform under the terms of the EPC Contract), the EPC Contract would likely be rejected and that the benefit of the fixed-price terms provided by the EPC Contract would be lost. As such, any cost overruns that would have been absorbed by the Consortium would become the responsibility of SCE&G and Santee Cooper. Additionally, these cost increases and other costs identified by SCE&G would not be fully recoverable from the Consortium or from Toshiba under its payment guaranty or the related Toshiba Settlement, discussed below, and such costs would likely substantially exceed the amount of the Consortium's payment obligations guaranteed by Toshiba. SCE&G also considered that even the newly revised substantial completion dates identified by WEC of April and December 2020 for Unit 2 and Unit 3, respectively, likely would not be met. As such, the electricity to be produced by each of the units would not qualify for nuclear production tax credits under Section 45J of the IRC. SCE&G's 55% share of these nuclear production tax credits for both Unit 2 and Unit 3 could have totaled as much as approximately $1.4 billion. Failure to meet the newly revised substantial completion dates identified by WEC would result in the nuclear production tax credits not being earned. 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. The Proofs of Claim are 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 the 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. Toshiba Settlement and Subsequent Monetization Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC, and in connection with the October 2015 Amendment, 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 from October 2017 through September 2022 in the total amount of approximately $2.2 billion ( $1.2 billion for SCE&G’s 55% share). The $2.2 billion is subject to offset for payments by WEC that have the effect of satisfying the liens on the project discussed below. On September 27, 2017, the scheduled payments under the Toshiba Settlement, exclusive of the payment due in October 2017, were purchased by Citibank for a one-time upfront payment of $1.847 billion (approximately $1.016 billion for SCE&G's 55% share), including amounts related to the contractor liens discussed below. The initial payment was then received from Toshiba on October 2, 2017, as scheduled, in the amount of $150 million ( $82.5 million for SCE&G's 55% share). SCE&G's share of amounts received, net of certain expenses, total $1.095 billion . The purchase agreement 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 were recorded as cash and as a regulatory liability on the accompanying 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. While this determination is pending, SCE&G has utilized portions of the proceeds 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 further discussion in Note 4. A number of subcontractors and vendors to the Consortium 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. SCE&G is contesting the filed liens. Payments under the Toshiba Settlement are subject to reduction if WEC pays creditors holding these 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 among SCE&G, Santee Cooper and Citibank was amended to limit the amount that SCE&G and Santee Cooper could be required to reimburse Citibank for valid subcontractor and vendor liens to $60 million ($ 33 million for SCE&G's 55% share). Determination to Stop Construction and Related Regulatory, Political and Legal Developments The BLRA provides that, in the event of abandonment prior to plant completion, costs incurred, including AFC, and a return on those costs, may be recoverable through rates, if the SCPSC determines that the decision to abandon the Nuclear Project was prudent. Based on the evaluation previously discussed, and in light of Santee Cooper's decision to suspend construction, on July 31, 2017, the Company determined to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs incurred in connection with such construction under the abandonment provisions of the BLRA or through other means. On July 31, 2017, SCE&G gave WEC a five-day notice of termination of the Interim Assessment Agreement and notified WEC of its determination to stop construction of Unit 2 and Unit 3. On August 1, 2017, SCE&G senior management provided an allowable ex parte briefing to the SCPSC regarding the Nuclear Project and this decision, and SCE&G also filed a petition with the SCPSC which included its plan of abandonment and certain proposed actions which would mitigate related customer rate increases, including a proposal to return to customers the net value of proceeds received by SCE&G under or arising from the monetization of the Toshiba Settlement. Through this petition, SCE&G had sought recovery of such costs expended on the construction of the Nuclear Project, including certain costs incurred subsequent to SCE&G's last revised rates update, and certain other costs under the abandonment provisions of the BLRA. Subsequently, SCE&G’s management met with various stakeholders and members of the South Carolina General Assembly, including legislative leaders, to discuss the abandonment of the Nuclear Project and to hear their concerns. In response to those concerns, and to allow for adequate time for governmental officials to conduct their reviews, SCE&G voluntarily withdrew its petition to abandon the project from the SCPSC on August 15, 2017. In August 2017, special committees of the South Carolina General Assembly, both in the House of Representatives and in the Senate, began conducting public hearings regarding the decision to abandon the Nuclear Project. Members of SCE&G's senior management, along with representatives from Santee Cooper, the ORS and other interested parties, testified before these committees. Several legislative proposals adverse to the Company and Consolidated SCE&G resulted from the work of these committees and certain adverse proposals have been or are being considered by the General Assembly in 2018. In January 2018, these committees reconvened for the purpose of considering the effects of the proposed merger discussed below on Nuclear Project stakeholders. On January 31, 2018, the South Carolina House of Representatives passed a bill (H. 4375) that would create an experimental rate which would effectively suspend collections from rates previously approved by the SCPSC under the BLRA. This experimental rate would remain in effect during the pendency of administrative proceedings currently before the SCPSC or any appeal therefrom. In addition, the South Carolina Senate passed a joint resolution (S. 954) which, if enacted, would prohibit the SCPSC from holding a hearing on the merits for a docket in which requests were made pursuant to the BLRA (other than an administrative or procedural hearing prior to such hearing on the merits), and would prohibit any final determination on any such requests, before November 1, 2018, and would require the SCPSC to issue a final order for such docket no later than December 21, 2018. Any bill must be approved by both legislative chambers and be signed by, or allowed to become law without the signature of, the Governor before it would be enacted. Neither the Company nor Consolidated SCE&G can predict if or when either of these bills could become law or what additional actions, if any, may be proposed or taken, including other legislative actions related to the BLRA. 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 in September 2017, the state's Office of Attorney General, the Speaker of the House of Representatives, and the Chair and Vice-Chair of the South Carolina House Utility Ratepayer Protection Committee requested that SLED conduct 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. The Company and Consolidated SCE&G intend to fully cooperate with these investigations. Also in connection with the abandonment of the Nuclear Project, various state or local governmental authorities have attempted and may further attempt to challenge, reverse or revoke one or more previously-approved tax or economic development incentives, benefits or exemptions and may attempt to apply such action retroactively. No assurance can be given as to the timing or outcome of these matters. On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, the ORS filed the Request with the SCPSC asking for an order 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 relied upon the opinion from the Office of Attorney General to assert that it is not just and reasonable or in the public interest to allow SCE&G to continue collecting revised rates. Further, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS that should have been disclosed and that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections. SCE&G estimates that revised rates collections, including collections related to transmission assets expected to be placed into service, currently total approximately $445 million annually, and such amounts accumulated as of December 31, 2017 total approximately $1.9 billion . On September 28, 2017, SCE&G filed a Motion to Dismiss the Request and a Request for Briefing Schedule and Hearing on Motion to Dismiss. On September 28, 2017, the SCPSC deferred action on the Request and ordered a hearing officer to establish a briefing schedule and hearing date on SCE&G's motion. On October 17, 2017, the ORS filed a motion with the SCPSC to amend the Request, in which 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. Parties who filed to intervene in the matter or who filed a letter in support of the request by the ORS include the Governor, the state's Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, the SCEUC, certain large industrial customers, and several environmental groups. After conducting a hearing to consider SCE&G's motion, the SCPSC denied the motion on December 20, 2017 and requested that the ORS carry out an inspection, audit and examination of SCE&G's revenue requirements to assist the SCPSC in determining whether SCE&G's present schedule of rates is fair and reasonable and also ordered that a hearing be scheduled to consider the Request. The hearing has not yet been scheduled. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the timing or outcome of this matter. See also Note 2. 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 liquidation of project liens) over 50 years. While SCE&G’s proposal was not formally submitted for regulatory approval, 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 commit 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, 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 adding an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers. 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. Impairment Considerations 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 the reviews by legislative committees and others, the adverse impact that would result if proposed legislation is enacted, and the Request being considered by the SCPSC that could result in the suspension of 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 fully recover its costs of Unit 2 and Unit 3 and a return on them from its customers. 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 have determined that a disallowance of recovery of part of the cost of the abandoned plant is both probable and reasonably estimable under applicable accounting guidance. In addition, the Company and Consolidated SCE&G have determined that full recovery of certain other related costs deferred within regulatory assets is less than probable. As a result, as of December 31, 2017, the Company and Consolidated SCE&G have recognized a pre-tax impairment loss totaling $1.118 billion ( $690 million net of tax). With the exception of the $210 million loss recorded in the third quarter of 2017 as explained below, this impairment loss was recorded in the fourth quarter of 2017. A discussion of this impairment loss follows: • A pre-tax impairment loss was recorded with respect to disallowance of unrecovered nuclear project costs of approximately $670 million . This amount includes $210 million recorded in the third quarter of 2017, which represented costs of approximately $1.2 billion that had been expended on the project, exclusive of transmission costs, but which had not yet been determined to be prudent by the SCPSC in connection with revised rates proceedings under the BLRA, offset by the amount of approximately $1 billion , which amount represents the recovery of the Toshiba Settlement proceeds that are in excess of amounts from that settlement that the Company and Consolidated SCE&G estimated may be necessary to satisfy certain project liens. This impairment loss also includes $180 million , which amount arises from SCE&G’s entry into an agreement in the fourth quarter of 2017 to purchase in 2018 an existing 540-MW combined cycle gas generating station along with SCE&G's commitment to regulators and the public that the recovery of the initial capital investment in the facility would not be sought from customers. The remaining $280 million of this impairment loss was recorded after consideration of the regulatory and political developments described above. • A pre-tax impairment loss was recorded in the aggregate amount of $361 million to write off costs which had been previously deferred, primarily as regulatory assets, in connection with the Nuclear Project. Such regulatory assets included deferred losses on interest rate swaps for which debt will not be issued due to the abandonment of the Nuclear Project, carrying costs on deferred tax assets arising from the capitalization of interest costs for tax purposes, net deferred costs and tax benefits related to foregone domestic production activities deductions (net of uncertain tax positions and credits) taken with respect to the project, and taxes associated with equity AFC. • Finally, an $87 million pre-tax impairment loss was recorded in order to reduce to estimated fair value the carrying value of nuclear fuel acquired for use in Unit 2 and Unit 3. With the exception of the $87 million related to nuclear fuel, the above impairment loss reflects impacts similar to those that may have resulted had the proposed solution announced November 16, 2017 been implemented. That proposal is presented by SCE&G as a less-favored alternative to the merger benefits and cost recovery plan in the January 12, 2018 Joint Petition. It is reasonably possible that a change in the estimated impairment loss could occur in the near term. If the merger benefits and cost recovery plan outlined in the Joint Petition is implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss and other charges totaling as much as approximately $1.7 billion would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $856 million recorded within regulatory assets and the recording of additional liabilities for customer refunds totaling approximately $1.875 billion , net of approximately $1.062 billion , which amount represents the monetization of guaranty settlement of $1.095 billion recorded within regulatory liabilities less amounts that may be required to settle contractor liens. If instead the Joint Petition is not approved and the Request by the ORS is approved, and if the BLRA is found to be unconstitutional or the General Assembly amends or revokes the BLRA, the Company and Consolidated SCE&G may be required to record an additional impairment loss and other charges totaling as much as approximately $4.8 billion . This additional impairment loss would result from the write-off of the remaining unrecovered Nuclear Project costs of $3.976 billion recorded within regulatory assets and the refund of revised rates collections under the BLRA described above of approximately $1.9 billion , net of approximately $1.062 billion , which amount represents the monetization of guaranty settlement of $1.095 billion recorded within regulatory liabilities less amounts that may be required to settle contractor liens. The Company and Consolidated SCE&G do not currently anticipate that any of the $1.9 billion in revenue previously collected will be subject to refund; however, no assurance can be given as to the outcome of this matter. Liquidity Considerations As a result of the decision to stop construction of Unit 2 and Unit 3, downgrades by credit ratings agencies have recently occurred. The Company and Consolidated SCE&G have significant obligations that must be paid within the next 12 months, including long-term debt maturities and capital lease payments of $727 million for the Company (including $723 million for Consolidated SCE&G), short-term borrowings of $350 million for the Company (including $252 million for Consolidated SCE&G), interest payments of approximately $335 million for the Company (including $259 million for Consolidated SCE&G), and future minimum payments for operating leases of $34 million for the Company (including $26 million for Consolidated SCE&G). Working capital requirements, such as those for fuel supply and similar obligations, also arise due to the lag between when such amounts are paid and when related collection of su	10. COMMITMENTS AND CONTINGENCIES
SCE&G
Commitment [Line Items]
Commitments and Contingencies Disclosure [Text Block]	Nuclear Project SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. SCE&G's ownership share in these units is 55% . As discussed below, various difficulties were encountered in connection with the project. The ability of the Consortium to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters, and others more fully discussed below, were the subject of comprehensive analyses performed by the Company and Santee Cooper (see Contractor Bankruptcy Proceedings and Related Uncertainties below). Based on the results of the Company's analysis, and in light of Santee Cooper's decision to suspend construction on Unit 2 and Unit 3, on July 31, 2017, the Company determined to stop the construction of the units and to pursue recovery of costs incurred in connection with such construction under the abandonment provisions of the BLRA or through other means. EPC Contract and BLRA Matters The Nuclear Project and SCE&G’s related recovery of financing costs through rates has been subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC approved, among other things, a milestone schedule and a capital costs estimates schedule for Unit 2 and Unit 3. Pursuant to the BLRA, this approval constituted a final and binding determination that the units were used and useful for utility purposes, and that the capital costs associated with them were prudent utility costs and expenses and were properly included in rates, so long as Unit 2 and Unit 3 were constructed or were being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the Nuclear Project. As of December 31, 2017, financing costs on $3.5 billion of SCE&G's construction costs for the Nuclear Project, excluding related transmission assets, have been reflected in revised rates under the BLRA, with the last revised rates increase having gone into effect in November 2016. SCE&G estimates that revised rates collections that have accumulated as of December 31, 2017, including collections related to transmission assets expected to be placed into service, total approximately $1.9 billion . As a result of the decision to abandon the Nuclear Project, amounts reclassified from construction work in progress into regulatory assets, net of impairments described below, are summarized as follows: Unrecovered Nuclear Project Costs Millions of dollars Nuclear Project costs as of September 30, 2017, prior to impairment loss and excluding transmission assets $ 4,730 Less Impairment loss recorded in the third quarter of 2017 (See below) 210 Balance of unrecovered Nuclear Project costs as of September 30, 2017 4,520 Less Impairment loss recorded in the fourth quarter of 2017 (See below) 460 Less Nuclear Project and switchyard assets transferred for use by Unit 1 84 Balance of unrecovered Nuclear Project costs as of December 31, 2017 (See Note 2) $ 3,976 The SCPSC granted initial approval of the construction schedule and related forecasted capital costs in 2009. The NRC issued combined Construction and Operating Licenses in March 2012. In November 2012, and again in September 2015 and November 2016 (see discussion below), the SCPSC approved SCE&G's requested updates to the milestone schedule, revised contractual substantial completion dates, and increases in capital and other costs. As further discussed below, under the current regulatory construct in South Carolina, approval by the SCPSC of cost recovery under the abandonment provisions of the BLRA or through other means will be required as a consequence of the Company’s determination on July 31, 2017 to cease construction of the Nuclear Project. October 2015 Amendment and WEC's Engagement of Fluor On October 27, 2015, SCE&G, Santee Cooper and the Consortium amended the EPC Contract. The amendment became effective in December 2015, at which time Fluor began serving as a subcontracted construction manager for the Consortium. The October 2015 Amendment provided SCE&G and Santee Cooper an option to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be reduced by amounts paid since June 30, 2015. SCE&G, on behalf of itself and as agent for Santee Cooper, elected the fixed price option, subject to SCPSC approval, on July 1, 2016. Among other things, the October 2015 Amendment revised the contractual guaranteed substantial completion dates of Unit 2 and Unit 3 to August 31, 2019 and August 31, 2020, respectively, and provided for development of a revised construction milestone payment schedule. In February 2017, WEC notified the Company and Consolidated SCE&G that the contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Unit 2 and Unit 3, respectively, which were reflected in the October 2015 Amendment, would not be met. Instead, WEC provided further revised estimated substantial completion dates of April 2020 and December 2020. November 2016 SCPSC Order In May 2016, SCE&G petitioned the SCPSC for approval of the updated construction and capital cost schedules for Unit 2 and Unit 3 which had been developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, the ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option. By order dated February 28, 2017, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement, and that order was not appealed. The construction schedule approved by the SCPSC in November 2016 provided for contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Unit 2 and Unit 3, respectively. The approved capital cost schedule included incremental capital costs that totaled $831 million , raising SCE&G's total project capital cost as then approved to an estimated amount of approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for the Nuclear Project from 10.5% to 10.25% . This revised ROE was to be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. No such revised rates have been sought since that time. 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. In connection with the bankruptcy filing, SCE&G, Santee Cooper, WEC and WECTEC entered into an Interim Assessment Agreement under which engineering and construction continued on the project and under which SCE&G and Santee Cooper were provided the right to discuss project status with Fluor and other subcontractors and vendors and to obtain from them relevant project information and documents that had been previously contractually unavailable in order for SCE&G and Santee Cooper to perform comprehensive analyses regarding whether or how to proceed with the Nuclear Project. As part of the Interim Assessment Agreement, and to avoid an immediate rejection of the EPC Contract upon the filing of the bankruptcy case, WEC and WECTEC required SCE&G and Santee Cooper to make estimated weekly payments to WEC, WECTEC, subcontractors and vendors, irrespective of the fixed price provisions of the EPC Contract, to permit the time to conduct analyses. SCE&G and Santee Cooper agreed to pay specified costs incurred by the Consortium, Fluor, other subcontractors and vendors for work performed or services rendered while the Interim Assessment Agreement remained in effect. During the period of the Interim Assessment Agreement, as amended and extended, SCE&G and Santee Cooper evaluated the various elements of the Nuclear Project, including forecasted costs and completion dates, while construction continued and SCE&G and Santee Cooper continued to make payments for such work. As part of its evaluation, SCE&G considered that, as a result of the bankruptcy process (including WEC and WECTEC's public announcements that they could not perform under the terms of the EPC Contract), the EPC Contract would likely be rejected and that the benefit of the fixed-price terms provided by the EPC Contract would be lost. As such, any cost overruns that would have been absorbed by the Consortium would become the responsibility of SCE&G and Santee Cooper. Additionally, these cost increases and other costs identified by SCE&G would not be fully recoverable from the Consortium or from Toshiba under its payment guaranty or the related Toshiba Settlement, discussed below, and such costs would likely substantially exceed the amount of the Consortium's payment obligations guaranteed by Toshiba. SCE&G also considered that even the newly revised substantial completion dates identified by WEC of April and December 2020 for Unit 2 and Unit 3, respectively, likely would not be met. As such, the electricity to be produced by each of the units would not qualify for nuclear production tax credits under Section 45J of the IRC. SCE&G's 55% share of these nuclear production tax credits for both Unit 2 and Unit 3 could have totaled as much as approximately $1.4 billion. Failure to meet the newly revised substantial completion dates identified by WEC would result in the nuclear production tax credits not being earned. 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. The Proofs of Claim are 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 the 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. Toshiba Settlement and Subsequent Monetization Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC, and in connection with the October 2015 Amendment, 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 from October 2017 through September 2022 in the total amount of approximately $2.2 billion ( $1.2 billion for SCE&G’s 55% share). The $2.2 billion is subject to offset for payments by WEC that have the effect of satisfying the liens on the project discussed below. On September 27, 2017, the scheduled payments under the Toshiba Settlement, exclusive of the payment due in October 2017, were purchased by Citibank for a one-time upfront payment of $1.847 billion (approximately $1.016 billion for SCE&G's 55% share), including amounts related to the contractor liens discussed below. The initial payment was then received from Toshiba on October 2, 2017, as scheduled, in the amount of $150 million ( $82.5 million for SCE&G's 55% share). SCE&G's share of amounts received, net of certain expenses, total $1.095 billion . The purchase agreement 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 were recorded as cash and as a regulatory liability on the accompanying 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. While this determination is pending, SCE&G has utilized portions of the proceeds 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 further discussion in Note 4. A number of subcontractors and vendors to the Consortium 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. SCE&G is contesting the filed liens. Payments under the Toshiba Settlement are subject to reduction if WEC pays creditors holding these 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 among SCE&G, Santee Cooper and Citibank was amended to limit the amount that SCE&G and Santee Cooper could be required to reimburse Citibank for valid subcontractor and vendor liens to $60 million ($ 33 million for SCE&G's 55% share). Determination to Stop Construction and Related Regulatory, Political and Legal Developments The BLRA provides that, in the event of abandonment prior to plant completion, costs incurred, including AFC, and a return on those costs, may be recoverable through rates, if the SCPSC determines that the decision to abandon the Nuclear Project was prudent. Based on the evaluation previously discussed, and in light of Santee Cooper's decision to suspend construction, on July 31, 2017, the Company determined to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs incurred in connection with such construction under the abandonment provisions of the BLRA or through other means. On July 31, 2017, SCE&G gave WEC a five-day notice of termination of the Interim Assessment Agreement and notified WEC of its determination to stop construction of Unit 2 and Unit 3. On August 1, 2017, SCE&G senior management provided an allowable ex parte briefing to the SCPSC regarding the Nuclear Project and this decision, and SCE&G also filed a petition with the SCPSC which included its plan of abandonment and certain proposed actions which would mitigate related customer rate increases, including a proposal to return to customers the net value of proceeds received by SCE&G under or arising from the monetization of the Toshiba Settlement. Through this petition, SCE&G had sought recovery of such costs expended on the construction of the Nuclear Project, including certain costs incurred subsequent to SCE&G's last revised rates update, and certain other costs under the abandonment provisions of the BLRA. Subsequently, SCE&G’s management met with various stakeholders and members of the South Carolina General Assembly, including legislative leaders, to discuss the abandonment of the Nuclear Project and to hear their concerns. In response to those concerns, and to allow for adequate time for governmental officials to conduct their reviews, SCE&G voluntarily withdrew its petition to abandon the project from the SCPSC on August 15, 2017. In August 2017, special committees of the South Carolina General Assembly, both in the House of Representatives and in the Senate, began conducting public hearings regarding the decision to abandon the Nuclear Project. Members of SCE&G's senior management, along with representatives from Santee Cooper, the ORS and other interested parties, testified before these committees. Several legislative proposals adverse to the Company and Consolidated SCE&G resulted from the work of these committees and certain adverse proposals have been or are being considered by the General Assembly in 2018. In January 2018, these committees reconvened for the purpose of considering the effects of the proposed merger discussed below on Nuclear Project stakeholders. On January 31, 2018, the South Carolina House of Representatives passed a bill (H. 4375) that would create an experimental rate which would effectively suspend collections from rates previously approved by the SCPSC under the BLRA. This experimental rate would remain in effect during the pendency of administrative proceedings currently before the SCPSC or any appeal therefrom. In addition, the South Carolina Senate passed a joint resolution (S. 954) which, if enacted, would prohibit the SCPSC from holding a hearing on the merits for a docket in which requests were made pursuant to the BLRA (other than an administrative or procedural hearing prior to such hearing on the merits), and would prohibit any final determination on any such requests, before November 1, 2018, and would require the SCPSC to issue a final order for such docket no later than December 21, 2018. Any bill must be approved by both legislative chambers and be signed by, or allowed to become law without the signature of, the Governor before it would be enacted. Neither the Company nor Consolidated SCE&G can predict if or when either of these bills could become law or what additional actions, if any, may be proposed or taken, including other legislative actions related to the BLRA. 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 in September 2017, the state's Office of Attorney General, the Speaker of the House of Representatives, and the Chair and Vice-Chair of the South Carolina House Utility Ratepayer Protection Committee requested that SLED conduct 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. The Company and Consolidated SCE&G intend to fully cooperate with these investigations. Also in connection with the abandonment of the Nuclear Project, various state or local governmental authorities have attempted and may further attempt to challenge, reverse or revoke one or more previously-approved tax or economic development incentives, benefits or exemptions and may attempt to apply such action retroactively. No assurance can be given as to the timing or outcome of these matters. On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, the ORS filed the Request with the SCPSC asking for an order 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 relied upon the opinion from the Office of Attorney General to assert that it is not just and reasonable or in the public interest to allow SCE&G to continue collecting revised rates. Further, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS that should have been disclosed and that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections. SCE&G estimates that revised rates collections, including collections related to transmission assets expected to be placed into service, currently total approximately $445 million annually, and such amounts accumulated as of December 31, 2017 total approximately $1.9 billion . On September 28, 2017, SCE&G filed a Motion to Dismiss the Request and a Request for Briefing Schedule and Hearing on Motion to Dismiss. On September 28, 2017, the SCPSC deferred action on the Request and ordered a hearing officer to establish a briefing schedule and hearing date on SCE&G's motion. On October 17, 2017, the ORS filed a motion with the SCPSC to amend the Request, in which 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. Parties who filed to intervene in the matter or who filed a letter in support of the request by the ORS include the Governor, the state's Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, the SCEUC, certain large industrial customers, and several environmental groups. After conducting a hearing to consider SCE&G's motion, the SCPSC denied the motion on December 20, 2017 and requested that the ORS carry out an inspection, audit and examination of SCE&G's revenue requirements to assist the SCPSC in determining whether SCE&G's present schedule of rates is fair and reasonable and also ordered that a hearing be scheduled to consider the Request. The hearing has not yet been scheduled. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the timing or outcome of this matter. See also Note 2. 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 liquidation of project liens) over 50 years. While SCE&G’s proposal was not formally submitted for regulatory approval, 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 commit 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, 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 adding an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers. 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. Impairment Considerations 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 the reviews by legislative committees and others, the adverse impact that would result if proposed legislation is enacted, and the Request being considered by the SCPSC that could result in the suspension of 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 fully recover its costs of Unit 2 and Unit 3 and a return on them from its customers. 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 have determined that a disallowance of recovery of part of the cost of the abandoned plant is both probable and reasonably estimable under applicable accounting guidance. In addition, the Company and Consolidated SCE&G have determined that full recovery of certain other related costs deferred within regulatory assets is less than probable. As a result, as of December 31, 2017, the Company and Consolidated SCE&G have recognized a pre-tax impairment loss totaling $1.118 billion ( $690 million net of tax). With the exception of the $210 million loss recorded in the third quarter of 2017 as explained below, this impairment loss was recorded in the fourth quarter of 2017. A discussion of this impairment loss follows: • A pre-tax impairment loss was recorded with respect to disallowance of unrecovered nuclear project costs of approximately $670 million . This amount includes $210 million recorded in the third quarter of 2017, which represented costs of approximately $1.2 billion that had been expended on the project, exclusive of transmission costs, but which had not yet been determined to be prudent by the SCPSC in connection with revised rates proceedings under the BLRA, offset by the amount of approximately $1 billion , which amount represents the recovery of the Toshiba Settlement proceeds that are in excess of amounts from that settlement that the Company and Consolidated SCE&G estimated may be necessary to satisfy certain project liens. This impairment loss also includes $180 million , which amount arises from SCE&G’s entry into an agreement in the fourth quarter of 2017 to purchase in 2018 an existing 540-MW combined cycle gas generating station along with SCE&G's commitment to regulators and the public that the recovery of the initial capital investment in the facility would not be sought from customers. The remaining $280 million of this impairment loss was recorded after consideration of the regulatory and political developments described above. • A pre-tax impairment loss was recorded in the aggregate amount of $361 million to write off costs which had been previously deferred, primarily as regulatory assets, in connection with the Nuclear Project. Such regulatory assets included deferred losses on interest rate swaps for which debt will not be issued due to the abandonment of the Nuclear Project, carrying costs on deferred tax assets arising from the capitalization of interest costs for tax purposes, net deferred costs and tax benefits related to foregone domestic production activities deductions (net of uncertain tax positions and credits) taken with respect to the project, and taxes associated with equity AFC. • Finally, an $87 million pre-tax impairment loss was recorded in order to reduce to estimated fair value the carrying value of nuclear fuel acquired for use in Unit 2 and Unit 3. With the exception of the $87 million related to nuclear fuel, the above impairment loss reflects impacts similar to those that may have resulted had the proposed solution announced November 16, 2017 been implemented. That proposal is presented by SCE&G as a less-favored alternative to the merger benefits and cost recovery plan in the January 12, 2018 Joint Petition. It is reasonably possible that a change in the estimated impairment loss could occur in the near term. If the merger benefits and cost recovery plan outlined in the Joint Petition is implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss and other charges totaling as much as approximately $1.7 billion would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $856 million recorded within regulatory assets and the recording of additional liabilities for customer refunds totaling approximately $1.875 billion , net of approximately $1.062 billion , which amount represents the monetization of guaranty settlement of $1.095 billion recorded within regulatory liabilities less amounts that may be required to settle contractor liens. If instead the Joint Petition is not approved and the Request by the ORS is approved, and if the BLRA is found to be unconstitutional or the General Assembly amends or revokes the BLRA, the Company and Consolidated SCE&G may be required to record an additional impairment loss and other charges totaling as much as approximately $4.8 billion . This additional impairment loss would result from the write-off of the remaining unrecovered Nuclear Project costs of $3.976 billion recorded within regulatory assets and the refund of revised rates collections under the BLRA described above of approximately $1.9 billion , net of approximately $1.062 billion , which amount represents the monetization of guaranty settlement of $1.095 billion recorded within regulatory liabilities less amounts that may be required to settle contractor liens. The Company and Consolidated SCE&G do not currently anticipate that any of the $1.9 billion in revenue previously collected will be subject to refund; however, no assurance can be given as to the outcome of this matter. Liquidity Considerations As a result of the decision to stop construction of Unit 2 and Unit 3, downgrades by credit ratings agencies have recently occurred. The Company and Consolidated SCE&G have significant obligations that must be paid within the next 12 months, including long-term debt maturities and capital lease payments of $727 million for the Company (including $723 million for Consolidated SCE&G), short-term borrowings of $350 million for the Company (including $252 million for Consolidated SCE&G), interest payments of approximately $335 million for the Company (including $259 million for Consolidated SCE&G), and future minimum payments for operating leases of $34 million for the Company (including $26 million for Consolidated SCE&G). Working capital requirements, such as those for fuel supply and similar obligations, also arise due to the lag between when such amounts are paid and when related collection of su	10. COMMITMENTS AND CONTINGENCIES

AFFILIATED TRANSACTIONS

AFFILIATED TRANSACTIONS	12 Months Ended
	Dec. 31, 2017
Affiliated Transaction [Line Items]
Schedule of Related Party Transactions [Table Text Block]	Millions of Dollars 2017 2016 2015 Purchases from SCANA Energy $ 127.4 $ 111.5 $ 128.5 Direct and Allocated Costs from SCANA Services 302.8 337.7 300.0 Millions of Dollars 2017 2016 Payable to SCANA Energy $ 10.0 $ 8.8 Payable to SCANA Services 42.0 63.5
AFFILIATED TRANSACTIONS	AFFILIATED TRANSACTIONS The Company: The Company received cash distributions from equity-method investees of $2.8 million in 2017, $3.7 million in 2016 and $4.0 million in 2015. The Company made investments in equity-method investees of $4.6 million in 2017, $5.5 million in 2016 and $4.1 million in 2015. The Company and Consolidated SCE&G: SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of operations (for the Company) and of comprehensive income (for Consolidated SCE&G). Millions of Dollars 2017 2016 2015 Purchases from Canadys Refined Coal, LLC $ 162.1 $ 161.8 $ 233.2 Sales to Canadys Refined Coal, LLC 161.1 160.8 232.0 Millions of Dollars 2017 2016 Receivable from Canadys Refined Coal, LLC $ 4.9 $ 16.0 Payable to Canadys Refined Coal, LLC 4.9 16.1 Consolidated SCE&G: SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and for 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 recorded in Other operation and maintenance - nonconsolidated affiliate and Other expenses on the consolidated statements of comprehensive income (loss). Millions of Dollars 2017 2016 2015 Purchases from SCANA Energy $ 127.4 $ 111.5 $ 128.5 Direct and Allocated Costs from SCANA Services 302.8 337.7 300.0 Millions of Dollars 2017 2016 Payable to SCANA Energy $ 10.0 $ 8.8 Payable to SCANA Services 42.0 63.5 Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA and transported natural gas to SCE&G to serve retail gas customers and certain electric generation requirements. SCE&G's purchases from CGT totaled approximately $3.4 million in 2015. Borrowings from and investments in an affiliated money pool are described in Note 4. SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs is described in Note 8.
SCE&G
Affiliated Transaction [Line Items]
Schedule of Related Party Transactions [Table Text Block]	Millions of Dollars 2017 2016 2015 Purchases from SCANA Energy $ 127.4 $ 111.5 $ 128.5 Direct and Allocated Costs from SCANA Services 302.8 337.7 300.0 Millions of Dollars 2017 2016 Payable to SCANA Energy $ 10.0 $ 8.8 Payable to SCANA Services 42.0 63.5
AFFILIATED TRANSACTIONS	AFFILIATED TRANSACTIONS The Company: The Company received cash distributions from equity-method investees of $2.8 million in 2017, $3.7 million in 2016 and $4.0 million in 2015. The Company made investments in equity-method investees of $4.6 million in 2017, $5.5 million in 2016 and $4.1 million in 2015. The Company and Consolidated SCE&G: SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of operations (for the Company) and of comprehensive income (for Consolidated SCE&G). Millions of Dollars 2017 2016 2015 Purchases from Canadys Refined Coal, LLC $ 162.1 $ 161.8 $ 233.2 Sales to Canadys Refined Coal, LLC 161.1 160.8 232.0 Millions of Dollars 2017 2016 Receivable from Canadys Refined Coal, LLC $ 4.9 $ 16.0 Payable to Canadys Refined Coal, LLC 4.9 16.1 Consolidated SCE&G: SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and for 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 recorded in Other operation and maintenance - nonconsolidated affiliate and Other expenses on the consolidated statements of comprehensive income (loss). Millions of Dollars 2017 2016 2015 Purchases from SCANA Energy $ 127.4 $ 111.5 $ 128.5 Direct and Allocated Costs from SCANA Services 302.8 337.7 300.0 Millions of Dollars 2017 2016 Payable to SCANA Energy $ 10.0 $ 8.8 Payable to SCANA Services 42.0 63.5 Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA and transported natural gas to SCE&G to serve retail gas customers and certain electric generation requirements. SCE&G's purchases from CGT totaled approximately $3.4 million in 2015. Borrowings from and investments in an affiliated money pool are described in Note 4. SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs is described in Note 8.
Canadys Refined Coal [Member] | SCE&G
Affiliated Transaction [Line Items]
Schedule of Related Party Transactions [Table Text Block]	Millions of Dollars 2017 2016 2015 Purchases from Canadys Refined Coal, LLC $ 162.1 $ 161.8 $ 233.2 Sales to Canadys Refined Coal, LLC 161.1 160.8 232.0 Millions of Dollars 2017 2016 Receivable from Canadys Refined Coal, LLC $ 4.9 $ 16.0 Payable to Canadys Refined Coal, LLC 4.9 16.1

SEGMENT OF BUSINESS INFORMATION

SEGMENT OF BUSINESS INFORMATION	12 Months Ended
	Dec. 31, 2017
Segment Reporting Information [Line Items]
Segment Reporting Disclosure [Text Block]	SEGMENT OF BUSINESS INFORMATION Reportable segments, which are described below, follow the same accounting policies as those described in Note 1. Intersegment sales and transfers of electricity and gas are recorded based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices. Electric Operations primarily generates, transmits and distributes electricity, and is regulated by the SCPSC and FERC. Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, purchases and sells natural gas, primarily at retail. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively. Gas Marketing is comprised of the marketing operations of SCANA Energy, which markets natural gas to retail customers in Georgia and to industrial and large commercial customers and municipalities in the Southeast. All Other includes the parent company and a services company. In addition, All Other includes gains from the sales of CGT and SCI (see Note 1) and their operating results prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. External revenue and intersegment revenue for All Other related to CGT and SCI were not significant during any period presented. Regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations’ product differs from the other segments, as does its generation process and method of distribution. Gas Marketing operates in a deregulated environment. Management uses operating income (loss) to measure segment profitability for its regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, no allocation is made to segments for interest charges, income tax expense (benefit) or assets other than utility plant. For nonregulated operations, management uses net income (loss) as the measure of segment profitability and evaluates total assets for financial position. Intersegment revenue for SCE&G was not significant. Interest income is not reported by segment and is not material. Deferred tax assets are netted with deferred tax liabilities for consolidated reporting purposes. The consolidated financial statements report operating revenues which are comprised of the energy-related and regulated segments. Revenues from non-reportable and nonregulated segments are included in Other Income. Therefore the adjustments to total operating revenues remove revenues from non-reportable segments. Adjustments to net income (loss) consist of the unallocated net income (loss) of regulated reportable segments. Segment Assets include utility plant, net for SCE&G’s Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G. Adjustments to Interest Expense, Income Tax Expense (Benefit), Expenditures for Assets and Deferred Tax Assets include primarily the amounts that are not allocated to the segments. Interest Expense is also adjusted to eliminate charges between affiliates. Adjustments to Depreciation and Amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Expenditures for Assets are adjusted for AFC and revisions to estimated cash flows related to AROs, and totals not allocated to other segments. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis. Disclosure of Reportable Segments The Company: Millions of dollars Electric Operations Gas Distribution Gas Marketing All Other Adjustments/ Eliminations Consolidated Total 2017 External Revenue $ 2,659 $ 874 $ 874 — — $ 4,407 Intersegment Revenue 5 2 127 $ 389 $ (523 ) — Operating Income (Loss) (161 ) 186 n/a — 51 76 Interest Expense 19 28 1 — 315 363 Depreciation and Amortization 295 85 2 16 (16 ) 382 Income Tax Expense (Benefit) 8 41 25 (7 ) (179 ) (112 ) Net Income (Loss) n/a n/a 27 (46 ) (100 ) (119 ) Segment Assets 11,979 3,259 230 1,042 2,229 18,739 Expenditures for Assets 207 417 2 7 592 1,225 Deferred Tax Assets 6 25 9 — (40 ) — 2016 External Revenue $ 2,614 $ 788 $ 825 — — $ 4,227 Intersegment Revenue 5 2 111 $ 414 $ (532 ) — Operating Income 957 148 n/a — 48 1,153 Interest Expense 17 25 1 — 299 342 Depreciation and Amortization 287 82 2 16 (16 ) 371 Income Tax Expense 8 32 19 — 212 271 Net Income (Loss) n/a n/a 30 (18 ) 583 595 Segment Assets 11,929 2,892 230 1,124 2,532 18,707 Expenditures for Assets 1,275 276 2 11 15 1,579 Deferred Tax Assets 9 32 11 — (52 ) — 2015 External Revenue $ 2,551 $ 810 $ 1,018 $ 5 $ (4 ) $ 4,380 Intersegment Revenue 6 2 128 413 (549 ) — Operating Income 876 152 n/a 236 44 1,308 Interest Expense 17 23 1 1 276 318 Depreciation and Amortization 277 77 2 16 (14 ) 358 Income Tax Expense 9 32 18 1 333 393 Net Income (Loss) n/a n/a 28 185 533 746 Segment Assets 10,883 2,606 201 998 2,458 17,146 Expenditures for Assets 1,087 203 2 15 (154 ) 1,153 Deferred Tax Assets 5 29 15 — (49 ) — Consolidated SCE&G: Millions of dollars Electric Gas Adjustments/ Consolidated 2017 External Revenue $ 2,664 $ 406 — $ 3,070 Operating Income (Loss) (161 ) 71 — (90 ) Interest Expense 19 — $ 269 288 Depreciation and Amortization 295 30 (13 ) 312 Segment Assets 11,979 869 3,098 15,946 Expenditures for Assets 207 65 656 928 Deferred Tax Assets 6 n/a (6 ) — 2016 External Revenue $ 2,619 $ 367 — $ 2,986 Operating Income 957 56 — 1,013 Interest Expense 17 — $ 253 270 Depreciation and Amortization 287 28 (13 ) 302 Segment Assets 11,929 825 3,337 16,091 Expenditures for Assets 1,275 78 46 1,399 Deferred Tax Assets 9 n/a (9 ) — 2015 External Revenue $ 2,557 $ 373 — $ 2,930 Operating Income 876 58 — 934 Interest Expense 17 — $ 231 248 Depreciation and Amortization 277 28 (11 ) 294 Segment Assets 10,883 757 3,125 14,765 Expenditures for Assets 1,087 57 (136 ) 1,008 Deferred Tax Assets 5 n/a (5 ) —
SCE&G
Segment Reporting Information [Line Items]
Segment Reporting Disclosure [Text Block]	SEGMENT OF BUSINESS INFORMATION Reportable segments, which are described below, follow the same accounting policies as those described in Note 1. Intersegment sales and transfers of electricity and gas are recorded based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices. Electric Operations primarily generates, transmits and distributes electricity, and is regulated by the SCPSC and FERC. Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, purchases and sells natural gas, primarily at retail. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively. Gas Marketing is comprised of the marketing operations of SCANA Energy, which markets natural gas to retail customers in Georgia and to industrial and large commercial customers and municipalities in the Southeast. All Other includes the parent company and a services company. In addition, All Other includes gains from the sales of CGT and SCI (see Note 1) and their operating results prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. External revenue and intersegment revenue for All Other related to CGT and SCI were not significant during any period presented. Regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations’ product differs from the other segments, as does its generation process and method of distribution. Gas Marketing operates in a deregulated environment. Management uses operating income (loss) to measure segment profitability for its regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, no allocation is made to segments for interest charges, income tax expense (benefit) or assets other than utility plant. For nonregulated operations, management uses net income (loss) as the measure of segment profitability and evaluates total assets for financial position. Intersegment revenue for SCE&G was not significant. Interest income is not reported by segment and is not material. Deferred tax assets are netted with deferred tax liabilities for consolidated reporting purposes. The consolidated financial statements report operating revenues which are comprised of the energy-related and regulated segments. Revenues from non-reportable and nonregulated segments are included in Other Income. Therefore the adjustments to total operating revenues remove revenues from non-reportable segments. Adjustments to net income (loss) consist of the unallocated net income (loss) of regulated reportable segments. Segment Assets include utility plant, net for SCE&G’s Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G. Adjustments to Interest Expense, Income Tax Expense (Benefit), Expenditures for Assets and Deferred Tax Assets include primarily the amounts that are not allocated to the segments. Interest Expense is also adjusted to eliminate charges between affiliates. Adjustments to Depreciation and Amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Expenditures for Assets are adjusted for AFC and revisions to estimated cash flows related to AROs, and totals not allocated to other segments. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis. Disclosure of Reportable Segments The Company: Millions of dollars Electric Operations Gas Distribution Gas Marketing All Other Adjustments/ Eliminations Consolidated Total 2017 External Revenue $ 2,659 $ 874 $ 874 — — $ 4,407 Intersegment Revenue 5 2 127 $ 389 $ (523 ) — Operating Income (Loss) (161 ) 186 n/a — 51 76 Interest Expense 19 28 1 — 315 363 Depreciation and Amortization 295 85 2 16 (16 ) 382 Income Tax Expense (Benefit) 8 41 25 (7 ) (179 ) (112 ) Net Income (Loss) n/a n/a 27 (46 ) (100 ) (119 ) Segment Assets 11,979 3,259 230 1,042 2,229 18,739 Expenditures for Assets 207 417 2 7 592 1,225 Deferred Tax Assets 6 25 9 — (40 ) — 2016 External Revenue $ 2,614 $ 788 $ 825 — — $ 4,227 Intersegment Revenue 5 2 111 $ 414 $ (532 ) — Operating Income 957 148 n/a — 48 1,153 Interest Expense 17 25 1 — 299 342 Depreciation and Amortization 287 82 2 16 (16 ) 371 Income Tax Expense 8 32 19 — 212 271 Net Income (Loss) n/a n/a 30 (18 ) 583 595 Segment Assets 11,929 2,892 230 1,124 2,532 18,707 Expenditures for Assets 1,275 276 2 11 15 1,579 Deferred Tax Assets 9 32 11 — (52 ) — 2015 External Revenue $ 2,551 $ 810 $ 1,018 $ 5 $ (4 ) $ 4,380 Intersegment Revenue 6 2 128 413 (549 ) — Operating Income 876 152 n/a 236 44 1,308 Interest Expense 17 23 1 1 276 318 Depreciation and Amortization 277 77 2 16 (14 ) 358 Income Tax Expense 9 32 18 1 333 393 Net Income (Loss) n/a n/a 28 185 533 746 Segment Assets 10,883 2,606 201 998 2,458 17,146 Expenditures for Assets 1,087 203 2 15 (154 ) 1,153 Deferred Tax Assets 5 29 15 — (49 ) — Consolidated SCE&G: Millions of dollars Electric Gas Adjustments/ Consolidated 2017 External Revenue $ 2,664 $ 406 — $ 3,070 Operating Income (Loss) (161 ) 71 — (90 ) Interest Expense 19 — $ 269 288 Depreciation and Amortization 295 30 (13 ) 312 Segment Assets 11,979 869 3,098 15,946 Expenditures for Assets 207 65 656 928 Deferred Tax Assets 6 n/a (6 ) — 2016 External Revenue $ 2,619 $ 367 — $ 2,986 Operating Income 957 56 — 1,013 Interest Expense 17 — $ 253 270 Depreciation and Amortization 287 28 (13 ) 302 Segment Assets 11,929 825 3,337 16,091 Expenditures for Assets 1,275 78 46 1,399 Deferred Tax Assets 9 n/a (9 ) — 2015 External Revenue $ 2,557 $ 373 — $ 2,930 Operating Income 876 58 — 934 Interest Expense 17 — $ 231 248 Depreciation and Amortization 277 28 (11 ) 294 Segment Assets 10,883 757 3,125 14,765 Expenditures for Assets 1,087 57 (136 ) 1,008 Deferred Tax Assets 5 n/a (5 ) —

OTHER INCOME (EXPENSE), NET (No

OTHER INCOME (EXPENSE), NET (Notes)	12 Months Ended
	Dec. 31, 2017
Other Income and Other Expense Disclosure [Text Block]	13. OTHER INCOME (EXPENSE), NET Components of other income (expense), net are as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Other income $ 79 $ 64 $ 75 $ 45 $ 29 $ 31 Other expense (46 ) (38 ) (60 ) (25 ) (24 ) (31 ) Allowance for equity funds used during construction 23 29 27 15 26 25 Other income (expense), net $ 56 $ 55 $ 42 $ 35 $ 31 $ 25
SCE&G
Other Income and Other Expense Disclosure [Text Block]	13. OTHER INCOME (EXPENSE), NET Components of other income (expense), net are as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Other income $ 79 $ 64 $ 75 $ 45 $ 29 $ 31 Other expense (46 ) (38 ) (60 ) (25 ) (24 ) (31 ) Allowance for equity funds used during construction 23 29 27 15 26 25 Other income (expense), net $ 56 $ 55 $ 42 $ 35 $ 31 $ 25

QUARTERLY FINANCIAL INFORMATION

QUARTERLY FINANCIAL INFORMATION (Notes)	12 Months Ended
	Dec. 31, 2017
Entity Information [Line Items]
Quarterly Financial Information [Text Block]	QUARTERLY FINANCIAL DATA (UNAUDITED) The Company First Quarter Second Quarter Third Quarter Fourth Quarter Annual 2017 Total operating revenues $ 1,173 $ 1,001 $ 1,076 $ 1,157 $ 4,407 Operating income (loss) 316 249 120 (609 ) 76 Net Income (Loss) 171 121 34 (445 ) (119 ) Earnings (Loss) per share 1.19 0.85 0.24 (3.11 ) (0.83 ) 2016 Total operating revenues $ 1,172 $ 905 $ 1,093 $ 1,057 $ 4,227 Operating income 331 221 348 253 1,153 Net Income 176 105 189 125 595 Earnings per share 1.23 0.74 1.32 0.87 4.16 Consolidated SCE&G Millions of dollars First Quarter Second Quarter Third Quarter Fourth Quarter Annual 2017 Total operating revenues $ 719 $ 756 $ 856 $ 739 $ 3,070 Operating income (loss) 222 246 123 (681 ) (90 ) Net Income (Loss) 112 126 42 (452 ) (172 ) Earnings Available (Loss Attributable) to Common Shareholder 109 123 39 (456 ) (185 ) 2016 Total operating revenues $ 717 $ 692 $ 882 $ 695 $ 2,986 Operating income 236 222 359 196 1,013 Net Income 116 113 204 93 526 Earnings Available to Common Shareholder 113 110 201 89 513 See Note 10 for a discussion of the impairment loss that was booked in the third quarter and the fourth quarter of 2017.
SCE&G
Entity Information [Line Items]
Quarterly Financial Information [Text Block]	14. QUARTERLY FINANCIAL DATA (UNAUDITED) The Company First Quarter Second Quarter Third Quarter Fourth Quarter Annual 2017 Total operating revenues $ 1,173 $ 1,001 $ 1,076 $ 1,157 $ 4,407 Operating income (loss) 316 249 120 (609 ) 76 Net Income (Loss) 171 121 34 (445 ) (119 ) Earnings (Loss) per share 1.19 0.85 0.24 (3.11 ) (0.83 ) 2016 Total operating revenues $ 1,172 $ 905 $ 1,093 $ 1,057 $ 4,227 Operating income 331 221 348 253 1,153 Net Income 176 105 189 125 595 Earnings per share 1.23 0.74 1.32 0.87 4.16 Consolidated SCE&G Millions of dollars First Quarter Second Quarter Third Quarter Fourth Quarter Annual 2017 Total operating revenues $ 719 $ 756 $ 856 $ 739 $ 3,070 Operating income (loss) 222 246 123 (681 ) (90 ) Net Income (Loss) 112 126 42 (452 ) (172 ) Earnings Available (Loss Attributable) to Common Shareholder 109 123 39 (456 ) (185 ) 2016 Total operating revenues $ 717 $ 692 $ 882 $ 695 $ 2,986 Operating income 236 222 359 196 1,013 Net Income 116 113 204 93 526 Earnings Available to Common Shareholder 113 110 201 89 513 See Note 10 for a discussion of the impairment loss that was booked in the third quarter and the fourth quarter of 2017.

SUBSEQUENT EVENT (Notes)

SUBSEQUENT EVENT (Notes)	12 Months Ended
	Dec. 31, 2017
Entity Information [Line Items]
Subsequent Events [Text Block]	5. SUBSEQUENT EVENT On January 2, 2018, SCANA, Sedona Corp. and Dominion Energy entered into the Merger Agreement pursuant to which Sedona Corp. (a wholly-owned subsidiary of Dominion Energy) agreed to merge into SCANA in a stock-for-stock transaction in which SCANA shareholders would receive 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock. The completion of the merger is subject to a variety of closing conditions, including the receipt of approvals from SCANA's shareholders and is also subject to consents and approvals or findings from governmental entities, which may impose conditions that could have an adverse effect on the Company or Consolidated SCE&G or could cause either SCANA or Dominion Energy to abandon the merger. The completion of the merger is also subject to an absence of substantive changes in certain South Carolina laws, including the BLRA, that would reasonably be expected to have an adverse effect on SCANA or its subsidiaries, or if any governmental entity enacts any order or there is any change in law which imposes any material change to the terms, conditions or undertakings set forth in the Joint Petition or any significant changes to the economic value of the Joint Petition. See also Note 10.
SCE&G
Entity Information [Line Items]
Subsequent Events [Text Block]	5. SUBSEQUENT EVENT On January 2, 2018, SCANA, Sedona Corp. and Dominion Energy entered into the Merger Agreement pursuant to which Sedona Corp. (a wholly-owned subsidiary of Dominion Energy) agreed to merge into SCANA in a stock-for-stock transaction in which SCANA shareholders would receive 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock. The completion of the merger is subject to a variety of closing conditions, including the receipt of approvals from SCANA's shareholders and is also subject to consents and approvals or findings from governmental entities, which may impose conditions that could have an adverse effect on the Company or Consolidated SCE&G or could cause either SCANA or Dominion Energy to abandon the merger. The completion of the merger is also subject to an absence of substantive changes in certain South Carolina laws, including the BLRA, that would reasonably be expected to have an adverse effect on SCANA or its subsidiaries, or if any governmental entity enacts any order or there is any change in law which imposes any material change to the terms, conditions or undertakings set forth in the Joint Petition or any significant changes to the economic value of the Joint Petition. See also Note 10.

SUMMARY OF SIGNIFICANT ACCOUN26

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2017
Significant Accounting Policies
Consolidation, Policy [Policy Text Block]	Organization and Principles of Consolidation The Company SCANA, a South Carolina corporation, is a holding company. The Company engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina, the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia and conducts other energy-related business. The accompanying consolidated financial statements reflect the accounts of SCANA, the following wholly-owned subsidiaries, and subsidiaries that formerly were wholly-owned during the periods presented. Regulated businesses Nonregulated businesses South Carolina Electric & Gas Company SCANA Energy Marketing, Inc. South Carolina Fuel Company, Inc. SCANA Services, Inc. South Carolina Generating Company, Inc. SCANA Corporate Security Services, Inc. Public Service Company of North Carolina, Incorporated SCANA Communications Holdings, Inc. SCANA reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. Discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. Consolidated SCE&G SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA, a South Carolina corporation. Consolidated SCE&G engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina. SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $503 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 4.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Property, Plant and Equipment, Policy [Policy Text Block]	Utility Plant Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense. AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 5.6% for 2017, 5.3% for 2016, and 6.1% for 2015. Consolidated SCE&G calculated AFC using average composite rates of 3.9% for 2017, 4.7% for 2016, and 5.6% for 2015. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred. Provisions for depreciation and amortization are recorded using the straight-line method based on the estimated service lives of the various classes of property, and in most cases, include provisions for future cost of removal. In 2015, SCE&G adopted lower depreciation rates for electric and common plant, as approved by the SCPSC and further described in Note 2. In addition, CGT was sold in the first quarter of 2015 (see Dispositions herein) and excluded from the 2015 calculation of composite weighted average depreciation rates. The composite weighted average depreciation rates for utility plant assets were as follows: 2017 2016 2015 SCE&G 2.55 % 2.56 % 2.55 % GENCO 2.66 % 2.66 % 2.66 % PSNC Energy 3.03 % 2.90 % 2.94 % Weighted average of above 2.63 % 2.61 % 2.61 % Consolidated SCE&G 2.55 % 2.56 % 2.56 % SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in Fuel used in electric generation and recovered through the fuel cost component of retail electric rates.
Jointly Owned Plant Policy [Policy Text Block]	Jointly Owned Utility Plant SCE&G jointly owns and is the operator of Unit 1. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. Unit 2 and Unit 3 have been reclassified from construction work in progress to a regulatory asset as a result of the decision to stop their construction. See additional discussion at Note 2. As of December 31, 2017 2016 Unit 1 Unit 1 Unit 2 and Unit 3 Percent owned 66.7% 66.7% 55.0% Plant in service $ 1.5 billion $ 1.3 billion — Accumulated depreciation $ 637.6 million $ 634.4 million — Construction work in progress $ 110.1 million $ 167.7 million $ 4.2 billion Included within other receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for the units. These amounts totaled $53.8 million at December 31, 2017 and $76.2 million at December 31, 2016.
Property, Plant and Equipment, Planned Major Maintenance Activities, Policy [Policy Text Block]	Major Maintenance Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred. SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2017, and 2016, SCE&G incurred $26.1 million and $23.8 million , respectively, for turbine maintenance. Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 million annually for its portion of the nuclear refueling outages scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which SCE&G was responsible totaled $1.8 million
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]	Goodwill The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company tests goodwill for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed. Accounting guidance adopted by the Company gives it the option to perform a qualitative assessment of impairment ("step zero"). Based on this qualitative assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to proceed with a two-step quantitative assessment. If the quantitative assessment becomes necessary, step one requires estimation of the fair value of the reporting unit and the comparison of that amount to its carrying value. If this step indicates an impairment (a carrying value in excess of fair value), then step two, measurement of the amount of the goodwill impairment (if any), is required. Should a write-down be required, such a charge would be treated as an operating expense. For each period presented, assets with a carrying value of $210 million for PSNC Energy (Gas Distribution segment), net of a writedown of $230 million taken in 2002, were classified as goodwill. The Company utilized the step zero qualitative assessment in its evaluations as of January 1, 2018 and as of January 1, 2017 and was not required to use the two-step quantitative assessment.
Nuclear Decommissiong [Policy Text Block]	Nuclear Decommissioning Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $786.4 million , stated in 2016 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. Under SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ( $3.2 million pre-tax in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. The asset balance held in trust reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Unit 1 on an after-tax basis.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds.
Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block]	Receivables Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described below. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $220.9 million at December 31, 2017 and $178.9 million at December 31, 2016 for the Company. Unbilled revenues totaled $140.3 million at December 31, 2017 and $117.6 million at December 31, 2016 for Consolidated SCE&G. Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station.
Inventory, Policy [Policy Text Block]	Inventories Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable.
Asset Management and Supply Service Agreements [Policy Text Block]	39% and 40% of PSNC Energy’s natural gas inventory at December 31, 2017 and December 31, 2016, respectively, with a carrying value of $11.5 million and $9.8 million , respectively.
Income Tax, Policy [Policy Text Block]	Income Taxes SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 5 for a discussion of the impact of adjustments recorded upon enactment of the Tax Act. Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions.
regulatory assets and regulatory liabilities [Policy Text Block]	Regulatory Assets and Regulatory Liabilities The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods different from the periods in which the costs would be charged to expense, or record revenues in periods different from the periods in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified in the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively.
Debt Premium, Discount, and Expense [Policy Text Block]	Debt Issuance Premiums, Discounts and Other Costs Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges.
Environmental Costs, Policy [Policy Text Block]	Environmental An environmental assessment program is maintained to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred.
Income Statement policy [Policy Text Block]	Statement of Operations Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within Operating Income and the 2015 gain on the sale of SCI within Other Income (Expense).
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed. Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings. SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews. SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. PSNC Energy is authorized by the NCUC to utilize a CUT which allows it to adjust base rates semi-annually for residential and commercial customers based on average per customer consumption, whether impacted by weather or other factors. Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of income.
Earnings Per Share, Policy [Policy Text Block]	Earnings (Loss) Per Share The Company computes basic earnings (loss) per share by dividing net income (loss) by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings (loss) per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.
New Accounting Matters [Policy Text Block]	New Accounting Matters Recently Adopted In the first quarter of 2017, the Company and Consolidated SCE&G adopted the following accounting guidance issued by the FASB. The adoption of this guidance had no impact on their respective financial statements except as indicated. • Guidance issued in August 2014 requires an entity's management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern. See related disclosure at Note 10. • Guidance issued in July 2015 requires most inventory to be measured at the lower of cost and net realizable value. • Guidance issued in October 2016 requires entities to recognize the income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer occurs. 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, and its adoption had no impact on its financial statements. Pending Adoption In the first quarter of 2018, the Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB. • Guidance issued in May 2014 for revenue arising from contracts with customers supersedes most prior revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides for a five-step analysis in determining when and how revenue is recognized, and requires revenue recognition to depict the transfer of promised goods or services to customers, based on the transfer of control, in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In addition, this guidance requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The analysis of contracts with customers to which the guidance might be applicable has been completed and activities of the FASB's Transition Resource Group for Revenue Recognition, particularly as they relate to the treatment of CIAC, ARP and the collectability of revenue of utilities subject to rate regulation have been considered. Specifically, the Company and Consolidated SCE&G have concluded that their use of CIAC is outside the scope of the new revenue recognition guidance. The Company and Consolidated SCE&G have determined that aspects of SCE&G’s WNA and, for the Company, PSNC Energy's CUT allow for revenue adjustments to be recognized prior to amounts being reflected in customer bills. These revenue adjustments, which give rise to regulatory assets or liabilities, represent ARPs that are outside the scope of the new guidance and will be reported as Other operating revenue separately from revenue from contracts with customers on the statement of operations. An evaluation of the enhanced disclosure requirements is being completed, including determining the appropriate disaggregation of revenue. The Company and Consolidated SCE&G will adopt this guidance using the modified retrospective method, and comparative periods will not be restated. In connection with this adoption, the Company has determined that its gas marketing subsidiary serves as an agent for gas distribution services in its retail market. Accordingly, certain pass through charges that the Company currently records within Gas-nonregulated revenues, and which are entirely offset within Gas purchased for resale, in the future will be recorded net on the statements of operations. The Company and Consolidated SCE&G do not anticipate that the adoption of this guidance will have any material impacts on their respective financial statements, but its adoption will result in additional disclosures. The adoption of this guidance will not result in a cumulative effect adjustment to beginning retained earnings. • Guidance issued in January 2016 changes how entities measure certain equity investments and financial liabilities, among other things. Entities will be required to make a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective, with certain exceptions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will have a significant impact on their respective financial statements. • 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. The adoption of this guidance will have no impact on the financial statements of the Company and Consolidated SCE&G. • Guidance issued in November 2016 clarifies how restricted cash should be presented on the statement of cash flows, and entities must apply the guidance retrospectively to all periods presented. The adoption of this guidance will have no impact on the financial statements of the Company and Consolidated SCE&G. • Guidance issued in March 2017 changes the required presentation of net periodic pension and postretirement benefit costs. Under this guidance, such costs will be separated into service cost components and other components. The service cost components will be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components will be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component will be eligible for capitalization in assets. Entities must apply this guidance on a retrospective basis for the presentation of the service cost component and the other components, and on a prospective basis for the capitalization of only the service cost component. As permitted, service cost and other costs disclosed in related footnotes to previously issued financial statements will be used when estimating retrospective changes for such costs in the income statements for prior periods. Due to regulatory overlay, non-service cost components related to regulated operations that are capitalized in assets under current accounting guidance will be deferred within regulatory assets in the future. As a result, the adoption of this guidance will not have a material impact on the financial statements of the Company and Consolidated SCE&G. 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, and without consideration of any regulatory accounting requirements which may apply, 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 January 2018, FASB amended this accounting guidance to provide an optional transition practical expedient that would allow adopters to not evaluate under the new guidance existing or expired land easements that were not previously accounted for as leases under existing guidance. The new guidance is effective for years beginning in 2019, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements other than increasing amounts reported for assets and liabilities on the balance sheet and changing the place on their respective statements of operations on which certain expenses are recorded. No impact on net income (loss) is expected. The identification and analysis of leasing and related contracts to which the guidance might be applicable has begun. In addition, the Company and Consolidated SCE&G have begun implementation of a third party software tool that will assist with initial adoption and ongoing compliance. Specifically, preliminary system configuration has been completed and data from certain leases are being entered. 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 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, though early adoption is permitted, and have not determined what impact such adoption will have 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 must adopt this guidance beginning in 2019, 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. No impact is expected on statements of operations or cash flows.
SCE&G
Significant Accounting Policies
Consolidation, Policy [Policy Text Block]	Consolidated SCE&G SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA, a South Carolina corporation. Consolidated SCE&G engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina. SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $503 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 4.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Property, Plant and Equipment, Policy [Policy Text Block]	Utility Plant Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense. AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 5.6% for 2017, 5.3% for 2016, and 6.1% for 2015. Consolidated SCE&G calculated AFC using average composite rates of 3.9% for 2017, 4.7% for 2016, and 5.6% for 2015. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred. Provisions for depreciation and amortization are recorded using the straight-line method based on the estimated service lives of the various classes of property, and in most cases, include provisions for future cost of removal. In 2015, SCE&G adopted lower depreciation rates for electric and common plant, as approved by the SCPSC and further described in Note 2. In addition, CGT was sold in the first quarter of 2015 (see Dispositions herein) and excluded from the 2015 calculation of composite weighted average depreciation rates. The composite weighted average depreciation rates for utility plant assets were as follows: 2017 2016 2015 SCE&G 2.55 % 2.56 % 2.55 % GENCO 2.66 % 2.66 % 2.66 % PSNC Energy 3.03 % 2.90 % 2.94 % Weighted average of above 2.63 % 2.61 % 2.61 % Consolidated SCE&G 2.55 % 2.56 % 2.56 % SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in Fuel used in electric generation and recovered through the fuel cost component of retail electric rates.
Jointly Owned Plant Policy [Policy Text Block]	Jointly Owned Utility Plant SCE&G jointly owns and is the operator of Unit 1. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. Unit 2 and Unit 3 have been reclassified from construction work in progress to a regulatory asset as a result of the decision to stop their construction. See additional discussion at Note 2. As of December 31, 2017 2016 Unit 1 Unit 1 Unit 2 and Unit 3 Percent owned 66.7% 66.7% 55.0% Plant in service $ 1.5 billion $ 1.3 billion — Accumulated depreciation $ 637.6 million $ 634.4 million — Construction work in progress $ 110.1 million $ 167.7 million $ 4.2 billion Included within other receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for the units. These amounts totaled $53.8 million at December 31, 2017 and $76.2 million at December 31, 2016.
Property, Plant and Equipment, Planned Major Maintenance Activities, Policy [Policy Text Block]	Major Maintenance Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred. SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2017, and 2016, SCE&G incurred $26.1 million and $23.8 million , respectively, for turbine maintenance. Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 million annually for its portion of the nuclear refueling outages scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which SCE&G was responsible totaled $1.8 million
Nuclear Decommissiong [Policy Text Block]	Nuclear Decommissioning Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $786.4 million , stated in 2016 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. Under SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ( $3.2 million pre-tax in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. The asset balance held in trust reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Unit 1 on an after-tax basis.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds.
Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block]	Receivables Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described below. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $220.9 million at December 31, 2017 and $178.9 million at December 31, 2016 for the Company. Unbilled revenues totaled $140.3 million at December 31, 2017 and $117.6 million at December 31, 2016 for Consolidated SCE&G. Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station.
Inventory, Policy [Policy Text Block]	Inventories Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable.
Income Tax, Policy [Policy Text Block]	Income Taxes SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 5 for a discussion of the impact of adjustments recorded upon enactment of the Tax Act. Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions.
regulatory assets and regulatory liabilities [Policy Text Block]	Regulatory Assets and Regulatory Liabilities The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs that have been or are expected to be allowed in the ratemaking process in periods different from the periods in which the costs would be charged to expense, or record revenues in periods different from the periods in which the revenues would be recorded, by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified in the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively.
Debt Premium, Discount, and Expense [Policy Text Block]	Debt Issuance Premiums, Discounts and Other Costs Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges.
Environmental Costs, Policy [Policy Text Block]	Environmental An environmental assessment program is maintained to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred.
Income Statement policy [Policy Text Block]	Statement of Operations Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within Operating Income and the 2015 gain on the sale of SCI within Other Income (Expense).
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not billed. Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings. SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews. SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. PSNC Energy is authorized by the NCUC to utilize a CUT which allows it to adjust base rates semi-annually for residential and commercial customers based on average per customer consumption, whether impacted by weather or other factors. Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of income.
New Accounting Matters [Policy Text Block]	New Accounting Matters Recently Adopted In the first quarter of 2017, the Company and Consolidated SCE&G adopted the following accounting guidance issued by the FASB. The adoption of this guidance had no impact on their respective financial statements except as indicated. • Guidance issued in August 2014 requires an entity's management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern. See related disclosure at Note 10. • Guidance issued in July 2015 requires most inventory to be measured at the lower of cost and net realizable value. • Guidance issued in October 2016 requires entities to recognize the income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer occurs. 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, and its adoption had no impact on its financial statements. Pending Adoption In the first quarter of 2018, the Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB. • Guidance issued in May 2014 for revenue arising from contracts with customers supersedes most prior revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides for a five-step analysis in determining when and how revenue is recognized, and requires revenue recognition to depict the transfer of promised goods or services to customers, based on the transfer of control, in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In addition, this guidance requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The analysis of contracts with customers to which the guidance might be applicable has been completed and activities of the FASB's Transition Resource Group for Revenue Recognition, particularly as they relate to the treatment of CIAC, ARP and the collectability of revenue of utilities subject to rate regulation have been considered. Specifically, the Company and Consolidated SCE&G have concluded that their use of CIAC is outside the scope of the new revenue recognition guidance. The Company and Consolidated SCE&G have determined that aspects of SCE&G’s WNA and, for the Company, PSNC Energy's CUT allow for revenue adjustments to be recognized prior to amounts being reflected in customer bills. These revenue adjustments, which give rise to regulatory assets or liabilities, represent ARPs that are outside the scope of the new guidance and will be reported as Other operating revenue separately from revenue from contracts with customers on the statement of operations. An evaluation of the enhanced disclosure requirements is being completed, including determining the appropriate disaggregation of revenue. The Company and Consolidated SCE&G will adopt this guidance using the modified retrospective method, and comparative periods will not be restated. In connection with this adoption, the Company has determined that its gas marketing subsidiary serves as an agent for gas distribution services in its retail market. Accordingly, certain pass through charges that the Company currently records within Gas-nonregulated revenues, and which are entirely offset within Gas purchased for resale, in the future will be recorded net on the statements of operations. The Company and Consolidated SCE&G do not anticipate that the adoption of this guidance will have any material impacts on their respective financial statements, but its adoption will result in additional disclosures. The adoption of this guidance will not result in a cumulative effect adjustment to beginning retained earnings. • Guidance issued in January 2016 changes how entities measure certain equity investments and financial liabilities, among other things. Entities will be required to make a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective, with certain exceptions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will have a significant impact on their respective financial statements. • 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. The adoption of this guidance will have no impact on the financial statements of the Company and Consolidated SCE&G. • Guidance issued in November 2016 clarifies how restricted cash should be presented on the statement of cash flows, and entities must apply the guidance retrospectively to all periods presented. The adoption of this guidance will have no impact on the financial statements of the Company and Consolidated SCE&G. • Guidance issued in March 2017 changes the required presentation of net periodic pension and postretirement benefit costs. Under this guidance, such costs will be separated into service cost components and other components. The service cost components will be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components will be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component will be eligible for capitalization in assets. Entities must apply this guidance on a retrospective basis for the presentation of the service cost component and the other components, and on a prospective basis for the capitalization of only the service cost component. As permitted, service cost and other costs disclosed in related footnotes to previously issued financial statements will be used when estimating retrospective changes for such costs in the income statements for prior periods. Due to regulatory overlay, non-service cost components related to regulated operations that are capitalized in assets under current accounting guidance will be deferred within regulatory assets in the future. As a result, the adoption of this guidance will not have a material impact on the financial statements of the Company and Consolidated SCE&G. 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, and without consideration of any regulatory accounting requirements which may apply, 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 January 2018, FASB amended this accounting guidance to provide an optional transition practical expedient that would allow adopters to not evaluate under the new guidance existing or expired land easements that were not previously accounted for as leases under existing guidance. The new guidance is effective for years beginning in 2019, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements other than increasing amounts reported for assets and liabilities on the balance sheet and changing the place on their respective statements of operations on which certain expenses are recorded. No impact on net income (loss) is expected. The identification and analysis of leasing and related contracts to which the guidance might be applicable has begun. In addition, the Company and Consolidated SCE&G have begun implementation of a third party software tool that will assist with initial adoption and ongoing compliance. Specifically, preliminary system configuration has been completed and data from certain leases are being entered. 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 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, though early adoption is permitted, and have not determined what impact such adoption will have 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 must adopt this guidance beginning in 2019, 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. No impact is expected on statements of operations or cash flows.

SUMMARY OF SIGNIFICANT ACCOUN27

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2017
Significant Accounting Policies
Interest Capitalization, Policy [Policy Text Block]
Schedule of weighted avg depreciation rates [Table Text Block]	2017 2016 2015 SCE&G 2.55 % 2.56 % 2.55 % GENCO 2.66 % 2.66 % 2.66 % PSNC Energy 3.03 % 2.90 % 2.94 % Weighted average of above 2.63 % 2.61 % 2.61 % Consolidated SCE&G 2.55 % 2.56 % 2.56 %
Schedule of Jointly Owned Utility Plants [Table Text Block]	As of December 31, 2017 2016 Unit 1 Unit 1 Unit 2 and Unit 3 Percent owned 66.7% 66.7% 55.0% Plant in service $ 1.5 billion $ 1.3 billion — Accumulated depreciation $ 637.6 million $ 634.4 million — Construction work in progress $ 110.1 million $ 167.7 million $ 4.2 billion
SCE&G
Significant Accounting Policies
Schedule of weighted avg depreciation rates [Table Text Block]	2017 2016 2015 SCE&G 2.55 % 2.56 % 2.55 % GENCO 2.66 % 2.66 % 2.66 % PSNC Energy 3.03 % 2.90 % 2.94 % Weighted average of above 2.63 % 2.61 % 2.61 % Consolidated SCE&G 2.55 % 2.56 % 2.56 %
Schedule of Jointly Owned Utility Plants [Table Text Block]	As of December 31, 2017 2016 Unit 1 Unit 1 Unit 2 and Unit 3 Percent owned 66.7% 66.7% 55.0% Plant in service $ 1.5 billion $ 1.3 billion — Accumulated depreciation $ 637.6 million $ 634.4 million — Construction work in progress $ 110.1 million $ 167.7 million $ 4.2 billion

RATE AND OTHER REGULATORY MAT28

RATE AND OTHER REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2017
Public Utilities, General Disclosures
Pipeline integrity management revenue requirement [Table Text Block]	Rates Effective Incremental Increase March 1, 2017 $1.9 million September 1, 2017 $0.7 million
Demand reduction programs [Table Text Block]	Year Effective Amount 2017 First billing cycle of May $37.0 million 2016 First billing cycle of May $37.6 million 2015 First billing cycle of May $32.0 million
Schedule of Changes in Electric Rate BLRA [Table Text Block]	Increase Effective for bills rendered on and after Amount Allowed ROE 2.7% November 27, 2016 $64.4 million 10.50% * 2.6% October 30, 2015 $64.5 million 11.00%
Schedule of Changes in Gas Rate RSA [Table Text Block]	Year Action Amount 2017 2.2 % Increase $8.6 million 2016 1.2 % Increase $4.1 million 2015 No change —
Schedule of Regulatory Assets [Table Text Block]	The Company Consolidated SCE&G December 31, December 31, Millions of dollars 2017 2016 2017 2016 Regulatory Assets: Unrecovered Nuclear Project costs $ 3,976 — $ 3,976 — Accumulated deferred income taxes — $ 316 — $ 307 AROs and related funding 434 425 410 403 Deferred employee benefit plan costs 305 342 273 309 Deferred losses on interest rate derivatives 456 620 456 620 Other unrecovered plant 105 117 105 117 DSM Programs 59 59 59 59 Carrying costs on deferred tax assets related to the Nuclear Project — 32 — 32 Pipeline integrity management costs 51 33 8 6 Environmental remediation costs 30 32 25 26 Deferred storm damage costs 24 20 24 20 Deferred costs related to uncertain tax position — 15 — 15 Other 140 119 140 116 Total Regulatory Assets $ 5,580 $ 2,130 $ 5,476 $ 2,030
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities: Monetization of guaranty settlement $ 1,095 — $ 1,095 — Accumulated deferred income taxes 1,076 23 914 14 Asset removal costs 757 755 527 529 Deferred gains on interest rate derivatives 131 151 131 151 Other — 1 — 1 Total Regulatory Liabilities $ 3,059 $ 930 $ 2,667 $ 695
SCE&G
Public Utilities, General Disclosures
Demand reduction programs [Table Text Block]	Year Effective Amount 2017 First billing cycle of May $37.0 million 2016 First billing cycle of May $37.6 million 2015 First billing cycle of May $32.0 million
Schedule of Changes in Electric Rate BLRA [Table Text Block]	Increase Effective for bills rendered on and after Amount Allowed ROE 2.7% November 27, 2016 $64.4 million 10.50% * 2.6% October 30, 2015 $64.5 million 11.00%
Schedule of Changes in Gas Rate RSA [Table Text Block]	Year Action Amount 2017 2.2 % Increase $8.6 million 2016 1.2 % Increase $4.1 million 2015 No change —
Schedule of Regulatory Assets [Table Text Block]	The Company Consolidated SCE&G December 31, December 31, Millions of dollars 2017 2016 2017 2016 Regulatory Assets: Unrecovered Nuclear Project costs $ 3,976 — $ 3,976 — Accumulated deferred income taxes — $ 316 — $ 307 AROs and related funding 434 425 410 403 Deferred employee benefit plan costs 305 342 273 309 Deferred losses on interest rate derivatives 456 620 456 620 Other unrecovered plant 105 117 105 117 DSM Programs 59 59 59 59 Carrying costs on deferred tax assets related to the Nuclear Project — 32 — 32 Pipeline integrity management costs 51 33 8 6 Environmental remediation costs 30 32 25 26 Deferred storm damage costs 24 20 24 20 Deferred costs related to uncertain tax position — 15 — 15 Other 140 119 140 116 Total Regulatory Assets $ 5,580 $ 2,130 $ 5,476 $ 2,030
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities: Monetization of guaranty settlement $ 1,095 — $ 1,095 — Accumulated deferred income taxes 1,076 23 914 14 Asset removal costs 757 755 527 529 Deferred gains on interest rate derivatives 131 151 131 151 Other — 1 — 1 Total Regulatory Liabilities $ 3,059 $ 930 $ 2,667 $ 695

LONG-TERM AND SHORT-TERM DEBT (

LONG-TERM AND SHORT-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Instrument [Line Items]
Schedule of Debt [Table Text Block]	: The Company December 31, 2017 2016 Dollars in millions Maturity Balance Rate Balance Rate SCANA Medium Term Notes (unsecured) 2020 - 2022 $ 800 5.42 % $ 800 5.42 % SCANA Senior Notes (unsecured) (a) 2018 - 2034 75 2.18 % 79 1.63 % SCE&G First Mortgage Bonds (secured) 2018 - 2065 4,840 5.80 % 4,840 5.79 % GENCO Notes (secured) 2018 - 2024 207 5.94 % 213 5.93 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.52 % 122 3.51 % PSNC Energy Senior Debentures and Notes 2020 - 2046 600 5.19 % 450 5.53 % Other 2018 - 2027 28 2.83 % 27 2.76 % Total debt 6,672 6,531 Current maturities of long-term debt (727 ) (17 ) Unamortized discount, net (1 ) (1 ) Unamortized debt issuance costs (38 ) (40 ) Total long-term debt, net $ 5,906 $ 6,473
Schedule of Line of Credit Facilities [Text Block]	December 31, 2016 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) $ 940.5 $ 64.4 $ 804.3 $ 71.8 Weighted average interest rate 1.43 % 1.04 % 1.07 % Letters of credit supported by LOC $ 3.3 $ 3.0 $ 0.3 — Available $ 1,056.2 $ 332.6 $ 595.4 $ 128.2 : Millions of dollars Total SCANA SCE&G PSNC Energy December 31, 2017 Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 $ 500.0 — $ 500.0 — Three-year, expiring December 2018 $ 200.0 — $ 200.0 — Total committed long-term $ 2,000.0 $ 400.0 $ 1,400.0 $ 200.0 Outstanding commercial paper (270 or fewer days) $ 350.3 — $ 251.6 $ 98.7 Weighted average interest rate — 1.92 % 1.93 % Letters of credit supported by LOC $ 3.3 $ 3.0 $ 0.3 — Available $ 1,646.4 $ 397.0 $ 1,148.1 $ 101.3
SCE&G
Debt Instrument [Line Items]
Schedule of Debt [Table Text Block]	Consolidated SCE&G December 31, 2017 2016 Dollars in millions Maturity Balance Rate Balance Rate First Mortgage Bonds (secured) 2018 - 2065 $ 4,840 5.80 % $ 4,840 5.79 % GENCO Notes (secured) 2018 - 2024 207 5.94 % 213 5.93 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.52 % 122 3.51 % Other 2018 - 2027 28 2.83 % 26 2.76 % Total debt 5,197 5,201 Current maturities of long-term debt (723 ) (12 ) Unamortized premium, net 1 1 Unamortized debt issuance costs (34 ) (36 ) Total long-term debt, net $ 4,441 $ 5,154
Schedule of Line of Credit Facilities [Text Block]	December 31, 2016 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) $ 940.5 $ 64.4 $ 804.3 $ 71.8 Weighted average interest rate 1.43 % 1.04 % 1.07 % Letters of credit supported by LOC $ 3.3 $ 3.0 $ 0.3 — Available $ 1,056.2 $ 332.6 $ 595.4 $ 128.2 Millions of dollars Total SCANA SCE&G PSNC Energy December 31, 2017 Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 $ 500.0 — $ 500.0 — Three-year, expiring December 2018 $ 200.0 — $ 200.0 — Total committed long-term $ 2,000.0 $ 400.0 $ 1,400.0 $ 200.0 Outstanding commercial paper (270 or fewer days) $ 350.3 — $ 251.6 $ 98.7 Weighted average interest rate — 1.92 % 1.93 % Letters of credit supported by LOC $ 3.3 $ 3.0 $ 0.3 — Available $ 1,646.4 $ 397.0 $ 1,148.1 $ 101.3

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2017
Investments, Owned, Federal Income Tax Note [Line Items]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	: The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Current taxes (benefit): Federal $ (414 ) $ 36 $ 382 $ (410 ) $ 50 $ 208 State 18 13 57 (18 ) 13 32 Total current taxes (benefit) (396 ) 49 439 (428 ) 63 240 Deferred tax (benefit) expense, net: Federal 323 203 (36 ) 261 167 (3 ) State (37 ) 21 (7 ) (2 ) 20 (3 ) Total deferred taxes (benefit) 286 224 (43 ) 259 187 (6 ) Investment tax credits: Amortization of amounts deferred-state — — (1 ) — — (1 ) Amortization of amounts deferred-federal (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Total investment tax credits (2 ) (2 ) (3 ) (2 ) (2 ) (3 ) Total income tax expense (benefit) $ (112 ) $ 271 $ 393 $ (171 ) $ 248 $ 231
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	: The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Net income (loss) $ (119 ) $ 595 $ 746 $ (185 ) $ 513 $ 466 Income tax expense (benefit) (112 ) 271 393 (171 ) 248 231 Noncontrolling interest — — — 13 13 14 Total pre-tax income (loss) $ (231 ) $ 866 $ 1,139 $ (343 ) $ 774 $ 711 Income taxes (benefit) on above at statutory federal income tax rate $ (81 ) $ 303 $ 399 $ (120 ) $ 271 $ 249 Increases (decreases) attributed to: State income taxes (less federal income tax effect) (7 ) 27 38 (8 ) 26 24 State investment tax credits (less federal income tax effect) (5 ) (5 ) (6 ) (5 ) (5 ) (6 ) Allowance for equity funds used during construction (8 ) (10 ) (9 ) (5 ) (9 ) (9 ) Deductible dividends—401(k) Retirement Savings Plan (9 ) (10 ) (10 ) — — — Amortization of federal investment tax credits (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Section 45 tax credits (8 ) (8 ) (9 ) (8 ) (8 ) (9 ) Domestic production activities deduction (18 ) (23 ) (18 ) (18 ) (23 ) (18 ) Remeasurement of deferred taxes upon enactment of Tax Act 30 — — (1 ) — — Realization of basis differences upon sale of subsidiaries — — 7 — — — Other differences, net (4 ) (1 ) 3 (4 ) (2 ) 2 Total income tax expense (benefit) $ (112 ) $ 271 $ 393 $ (171 ) $ 248 $ 231
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	: The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Deferred tax assets: Net operating loss and tax credit carryforward $ 600 — $ 541 — Toshiba settlement 273 — 273 — Nondeductible accruals 88 $ 148 42 $ 53 Asset retirement obligation, including nuclear decommissioning 141 213 132 200 Regulatory liability, non-property accumulated deferred income tax 54 — 54 — Financial instruments 15 22 — — Unamortized investment tax credits 8 15 8 15 Deferred fuel costs — 17 — 17 Other 6 10 5 8 Total deferred tax assets 1,185 425 1,055 293 Deferred tax liabilities: Property, plant and equipment 1,220 2,159 1,035 1,856 Regulatory asset, unrecovered nuclear plant costs 962 — 962 — Deferred employee benefit plan costs 60 105 53 93 Regulatory asset, asset retirement obligation 91 143 85 135 Regulatory asset, other unrecovered plant 27 45 27 45 Demand side management costs 16 23 16 23 Prepayments 21 32 19 30 Other 49 77 31 50 Total deferred tax liabilities 2,446 2,584 2,228 2,232 Net deferred tax liabilities $ 1,261 $ 2,159 $ 1,173 $ 1,939
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Unrecognized tax benefits, January 1 $ 350 $ 49 $ 16 $ 350 $ 49 $ 16 Gross increases—uncertain tax positions in prior period — 94 33 — 94 33 Gross decreases—uncertain tax positions in prior period (273 ) — (2 ) (273 ) — (2 ) Gross increases—current period uncertain tax positions 21 207 2 21 207 2 Unrecognized tax benefits, December 31 $ 98 $ 350 $ 49 $ 98 $ 350 $ 49
Summary of Tax Credit Carryforwards [Table Text Block]	The federal and state tax credits and NOL carryforwards are presented below: December 31, 2017 Millions of dollars The Company Consolidated SCE&G Expiration Year Federal NOL Carryforwards $ 2,052 $ 1,905 2037 Federal Tax Credits 35 35 2035 - 2037 Federal Charitable Carryforwards 7 5 2021 - 2022 State NOL Carryforwards 2,382 2,301 2037 State Charitable Carryforwards 3 2 2022 Total Tax Credits and NOL Carryforwards $ 4,479 $ 4,248
SCE&G
Investments, Owned, Federal Income Tax Note [Line Items]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	: The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Current taxes (benefit): Federal $ (414 ) $ 36 $ 382 $ (410 ) $ 50 $ 208 State 18 13 57 (18 ) 13 32 Total current taxes (benefit) (396 ) 49 439 (428 ) 63 240 Deferred tax (benefit) expense, net: Federal 323 203 (36 ) 261 167 (3 ) State (37 ) 21 (7 ) (2 ) 20 (3 ) Total deferred taxes (benefit) 286 224 (43 ) 259 187 (6 ) Investment tax credits: Amortization of amounts deferred-state — — (1 ) — — (1 ) Amortization of amounts deferred-federal (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Total investment tax credits (2 ) (2 ) (3 ) (2 ) (2 ) (3 ) Total income tax expense (benefit) $ (112 ) $ 271 $ 393 $ (171 ) $ 248 $ 231
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Net income (loss) $ (119 ) $ 595 $ 746 $ (185 ) $ 513 $ 466 Income tax expense (benefit) (112 ) 271 393 (171 ) 248 231 Noncontrolling interest — — — 13 13 14 Total pre-tax income (loss) $ (231 ) $ 866 $ 1,139 $ (343 ) $ 774 $ 711 Income taxes (benefit) on above at statutory federal income tax rate $ (81 ) $ 303 $ 399 $ (120 ) $ 271 $ 249 Increases (decreases) attributed to: State income taxes (less federal income tax effect) (7 ) 27 38 (8 ) 26 24 State investment tax credits (less federal income tax effect) (5 ) (5 ) (6 ) (5 ) (5 ) (6 ) Allowance for equity funds used during construction (8 ) (10 ) (9 ) (5 ) (9 ) (9 ) Deductible dividends—401(k) Retirement Savings Plan (9 ) (10 ) (10 ) — — — Amortization of federal investment tax credits (2 ) (2 ) (2 ) (2 ) (2 ) (2 ) Section 45 tax credits (8 ) (8 ) (9 ) (8 ) (8 ) (9 ) Domestic production activities deduction (18 ) (23 ) (18 ) (18 ) (23 ) (18 ) Remeasurement of deferred taxes upon enactment of Tax Act 30 — — (1 ) — — Realization of basis differences upon sale of subsidiaries — — 7 — — — Other differences, net (4 ) (1 ) 3 (4 ) (2 ) 2 Total income tax expense (benefit) $ (112 ) $ 271 $ 393 $ (171 ) $ 248 $ 231
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Deferred tax assets: Net operating loss and tax credit carryforward $ 600 — $ 541 — Toshiba settlement 273 — 273 — Nondeductible accruals 88 $ 148 42 $ 53 Asset retirement obligation, including nuclear decommissioning 141 213 132 200 Regulatory liability, non-property accumulated deferred income tax 54 — 54 — Financial instruments 15 22 — — Unamortized investment tax credits 8 15 8 15 Deferred fuel costs — 17 — 17 Other 6 10 5 8 Total deferred tax assets 1,185 425 1,055 293 Deferred tax liabilities: Property, plant and equipment 1,220 2,159 1,035 1,856 Regulatory asset, unrecovered nuclear plant costs 962 — 962 — Deferred employee benefit plan costs 60 105 53 93 Regulatory asset, asset retirement obligation 91 143 85 135 Regulatory asset, other unrecovered plant 27 45 27 45 Demand side management costs 16 23 16 23 Prepayments 21 32 19 30 Other 49 77 31 50 Total deferred tax liabilities 2,446 2,584 2,228 2,232 Net deferred tax liabilities $ 1,261 $ 2,159 $ 1,173 $ 1,939
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Unrecognized tax benefits, January 1 $ 350 $ 49 $ 16 $ 350 $ 49 $ 16 Gross increases—uncertain tax positions in prior period — 94 33 — 94 33 Gross decreases—uncertain tax positions in prior period (273 ) — (2 ) (273 ) — (2 ) Gross increases—current period uncertain tax positions 21 207 2 21 207 2 Unrecognized tax benefits, December 31 $ 98 $ 350 $ 49 $ 98 $ 350 $ 49
Summary of Tax Credit Carryforwards [Table Text Block]	The federal and state tax credits and NOL carryforwards are presented below: December 31, 2017 Millions of dollars The Company Consolidated SCE&G Expiration Year Federal NOL Carryforwards $ 2,052 $ 1,905 2037 Federal Tax Credits 35 35 2035 - 2037 Federal Charitable Carryforwards 7 5 2021 - 2022 State NOL Carryforwards 2,382 2,301 2037 State Charitable Carryforwards 3 2 2022 Total Tax Credits and NOL Carryforwards $ 4,479 $ 4,248

DERIVATIVE FINANCIAL INSTRUME31

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2017
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 December 31, 2017 Commodity 6,430,000 13,433,000 19,863,000 Energy Management (a) — 41,856,890 41,856,890 Total (a) 6,430,000 55,289,890 61,719,890 As of December 31, 2016 Commodity 4,510,000 11,947,000 16,457,000 Energy Management (a) — 67,447,223 67,447,223 Total (a) 4,510,000 79,394,223 83,904,223 (a) Includes amounts related to basis swap contracts totaling 2,582,000 MMBTU in 2017 and 730,721 MMBTU in 2016.
Schedule of Derivative Instruments [Table Text Block]	The aggregate notional amounts of the interest rate swaps were as follows: The Company Consolidated SCE&G Millions of dollars December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Designated as hedging instruments $ 111.2 $ 115.6 $ 36.4 $ 36.4 Not designated as hedging instruments 735.0 1,285.0 735.0 1,285.0
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 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 liabilities 1 Total — $ 30 — $ 10 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets 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 As of December 31, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 24 8 Commodity contracts Prepayments $ 5 Other current assets 1 Total $ 6 $ 28 — $ 9 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 71 $ 71 Derivative financial instruments $ 27 $ 27 Other deferred credits and other liabilities 3 3 Commodity contracts Other current assets 3 Energy management contracts Prepayments 6 2 Other current assets 2 1 Other deferred debits and other assets 2 Derivative financial instruments 4 Other deferred credits and other liabilities 2 Total $ 84 $ 39 $ 71 $ 30
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	The effect of derivative instruments on the consolidated statements of income is as follows: The Company and Consolidated SCE&G: Loss Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2017 Interest rate contracts $ (2 ) Interest expense $ (2 ) Year Ended December 31, 2016 Interest rate contracts — Interest expense $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (3 ) Interest expense $ (3 ) The Company: Gain or (Loss) Recognized in OCI, net of tax Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2017 Interest rate contracts — Interest expense $ (7 ) Commodity contracts $ (7 ) Gas purchased for resale 1 Total $ (7 ) $ (6 ) Year Ended December 31, 2016 Interest rate contracts $ (1 ) Interest expense $ (7 ) Commodity contracts 5 Gas purchased for resale (6 ) Total $ 4 $ (13 ) Year Ended December 31, 2015 Interest rate contracts $ (2 ) Interest expense $ (7 ) Commodity contracts (10 ) Gas purchased for resale (15 ) Total $ (12 ) $ (22 )
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	Derivatives Not Designated as Hedging Instruments The Company and Consolidated SCE&G: Loss Deferred in Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars Regulatory Accounts Location Amount Year Ended December 31, 2017 Interest rate contracts $ (32 ) Interest Expense $ (3 ) Interest rate contracts Impairment Loss (173 ) Year Ended December 31, 2016 Interest rate contracts $ (34 ) Other income $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (69 ) Other income $ 5
Disclosure of Credit Derivatives [Table Text Block]	Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 33.7 $ 50.3 $ 14.7 $ 30.3 Fair value of collateral already posted 28.9 29.2 10.1 9.2 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 4.8 21.1 4.6 21.1 in Net Asset Position Aggregate fair value of derivatives in net asset position $ 53.5 $ 62.9 $ 53.5 $ 62.0 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 62.9 53.5 62.0
Offsetting Assets [Table Text Block]	Information related to the offsetting derivative assets follows: Derivative Assets The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 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 As of December 31, 2016 Gross Amounts of Recognized Assets $ 71 $ 9 $ 10 $ 90 $ 71 Gross Amounts Offset in Statement of Financial Position (4 ) (4 ) Net Amounts Presented in Statement of Financial Position 71 9 6 86 71 Gross Amounts Not Offset - Financial Instruments (9 ) (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Received Net Amount $ 62 $ 9 $ 6 $ 77 $ 62 Balance sheet location Prepayments $ 9 Other current assets 5 Other deferred debits and other assets 72 $ 71 Total $ 86 $ 71
Offsetting Liabilities [Table Text Block]	Information related to the offsetting of derivative liabilities follows: Derivative Liabilities The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 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 As of December 31, 2016 Gross Amounts of Recognized Liabilities $ 58 $ 9 $ 67 $ 39 Gross Amounts Offset in Statement of Financial Position (3 ) (3 ) Net Amounts Presented in Statement of Financial Position 58 — 6 64 39 Gross Amounts Not Offset - Financial Instruments (9 ) (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Posted (29 ) (29 ) (9 ) Net Amount $ 20 — $ 6 $ 26 $ 21 Balance sheet location Derivative financial instruments $ 35 $ 28 Other deferred credits and other liabilities 29 11 Total $ 64 $ 39
SCE&G
Derivative [Line Items]
Schedule of Derivative Instruments [Table Text Block]	The aggregate notional amounts of the interest rate swaps were as follows: The Company Consolidated SCE&G Millions of dollars December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Designated as hedging instruments $ 111.2 $ 115.6 $ 36.4 $ 36.4 Not designated as hedging instruments 735.0 1,285.0 735.0 1,285.0
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 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 liabilities 1 Total — $ 30 — $ 10 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets 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 As of December 31, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 24 8 Commodity contracts Prepayments $ 5 Other current assets 1 Total $ 6 $ 28 — $ 9 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 71 $ 71 Derivative financial instruments $ 27 $ 27 Other deferred credits and other liabilities 3 3 Commodity contracts Other current assets 3 Energy management contracts Prepayments 6 2 Other current assets 2 1 Other deferred debits and other assets 2 Derivative financial instruments 4 Other deferred credits and other liabilities 2 Total $ 84 $ 39 $ 71 $ 30
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	The effect of derivative instruments on the consolidated statements of income is as follows: The Company and Consolidated SCE&G: Loss Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income (Effective Portion) Millions of dollars (Effective Portion) Location Amount Year Ended December 31, 2017 Interest rate contracts $ (2 ) Interest expense $ (2 ) Year Ended December 31, 2016 Interest rate contracts — Interest expense $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (3 ) Interest expense $ (3 )
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	Derivatives Not Designated as Hedging Instruments The Company and Consolidated SCE&G: Loss Deferred in Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars Regulatory Accounts Location Amount Year Ended December 31, 2017 Interest rate contracts $ (32 ) Interest Expense $ (3 ) Interest rate contracts Impairment Loss (173 ) Year Ended December 31, 2016 Interest rate contracts $ (34 ) Other income $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (69 ) Other income $ 5
Disclosure of Credit Derivatives [Table Text Block]	Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 33.7 $ 50.3 $ 14.7 $ 30.3 Fair value of collateral already posted 28.9 29.2 10.1 9.2 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 4.8 21.1 4.6 21.1 in Net Asset Position Aggregate fair value of derivatives in net asset position $ 53.5 $ 62.9 $ 53.5 $ 62.0 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 62.9 53.5 62.0
Offsetting Assets [Table Text Block]	Information related to the offsetting derivative assets follows: Derivative Assets The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 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 As of December 31, 2016 Gross Amounts of Recognized Assets $ 71 $ 9 $ 10 $ 90 $ 71 Gross Amounts Offset in Statement of Financial Position (4 ) (4 ) Net Amounts Presented in Statement of Financial Position 71 9 6 86 71 Gross Amounts Not Offset - Financial Instruments (9 ) (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Received Net Amount $ 62 $ 9 $ 6 $ 77 $ 62 Balance sheet location Prepayments $ 9 Other current assets 5 Other deferred debits and other assets 72 $ 71 Total $ 86 $ 71
Offsetting Liabilities [Table Text Block]	Information related to the offsetting of derivative liabilities follows: Derivative Liabilities The Company Consolidated SCE&G Millions of dollars Interest Rate Contracts Commodity Contracts Energy Management Contracts Total Interest Rate Contracts As of December 31, 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 As of December 31, 2016 Gross Amounts of Recognized Liabilities $ 58 $ 9 $ 67 $ 39 Gross Amounts Offset in Statement of Financial Position (3 ) (3 ) Net Amounts Presented in Statement of Financial Position 58 — 6 64 39 Gross Amounts Not Offset - Financial Instruments (9 ) (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Posted (29 ) (29 ) (9 ) Net Amount $ 20 — $ 6 $ 26 $ 21 Balance sheet location Derivative financial instruments $ 35 $ 28 Other deferred credits and other liabilities 29 11 Total $ 64 $ 39

FAIR VALUE MEASUREMENTS, INCL32

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Measurement Inputs, Disclosure [Table Text Block]	As of December 31, 2017 As of December 31, 2016 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 1 Level 2 Level 1 Level 2 Level 2 Assets: Available for sale securities $ 119 — $ 100 — $ 14 — — Held to maturity securities — $ 6 — — — $ 7 — Interest rate contracts — 54 — $ 54 — 71 $ 71 Commodity contracts 1 — — — 8 1 — Energy management contracts — 4 — — 6 4 — Liabilities: Interest rate contracts — 32 — 15 — 58 39 Commodity contracts 2 1 — — — — — Energy management contracts 1 4 — — 2 10 —
Fair Value, by Balance Sheet Grouping [Table Text Block]	As of December 31, 2017 As of December 31, 2016 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,632.9 $ 7,399.7 $ 6,489.8 $ 7,183.3 Consolidated SCE&G 5,163.3 5,790.3 5,166.0 5,752.3
SCE&G
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Measurement Inputs, Disclosure [Table Text Block]	As of December 31, 2017 As of December 31, 2016 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 1 Level 2 Level 1 Level 2 Level 2 Assets: Available for sale securities $ 119 — $ 100 — $ 14 — — Held to maturity securities — $ 6 — — — $ 7 — Interest rate contracts — 54 — $ 54 — 71 $ 71 Commodity contracts 1 — — — 8 1 — Energy management contracts — 4 — — 6 4 — Liabilities: Interest rate contracts — 32 — 15 — 58 39 Commodity contracts 2 1 — — — — — Energy management contracts 1 4 — — 2 10 —
Fair Value, by Balance Sheet Grouping [Table Text Block]	As of December 31, 2017 As of December 31, 2016 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,632.9 $ 7,399.7 $ 6,489.8 $ 7,183.3 Consolidated SCE&G 5,163.3 5,790.3 5,166.0 5,752.3

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Schedule of Changes in Projected Benefit Obligations [Table Text Block]	The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below. The Company Consolidated SCE&G Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2017 2016 2017 2016 2017 2016 Benefit obligation, January 1 $ 904.3 $ 855.4 $ 274.7 $ 253.6 $ 768.4 $ 724.0 $ 207.2 $ 191.7 Service cost 21.7 20.7 4.5 4.4 18.1 16.9 3.7 3.6 Interest cost 37.4 39.4 11.5 12.1 31.9 33.4 9.5 9.9 Plan participants’ contributions — — 1.3 1.7 — — 1.1 1.3 Actuarial (gain) loss 42.2 45.0 9.7 14.0 36.6 41.8 6.8 11.5 Benefits paid (72.4 ) (56.2 ) (12.5 ) (11.1 ) (62.0 ) (47.7 ) (10.3 ) (9.1 ) Amounts Funded to parent n/a n/a n/a n/a — — (1.4 ) (1.7 ) Benefit obligation, December 31 $ 933.2 $ 904.3 $ 289.2 $ 274.7 $ 793.0 $ 768.4 $ 216.6 $ 207.2
Schedule of Assumptions Used to Determine Benefit Obligations [Table Text Block]	Significant assumptions used to determine the above benefit obligations are as follows: Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Annual discount rate used to determine benefit obligation 3.71 % 4.22 % 3.74 % 4.30 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 %
Schedule of Net Funded Status [Table Text Block]	The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Fair value of plan assets $ 849.6 $ 793.6 — — $ 781.3 $ 732.9 — — Benefit obligation 933.2 904.3 $ 289.2 $ 274.7 793.0 768.4 $ 216.6 $ 207.2 Funded status $ (83.6 ) $ (110.7 ) $ (289.2 ) $ (274.7 ) $ (11.7 ) $ (35.5 ) $ (216.6 ) $ (207.2 )
Schedule of Amounts Recognized in Balance Sheet [Table Text Block]	Amounts recognized on the consolidated balance sheets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Current liability — — $ (13.5 ) $ (12.6 ) — — $ (10.8 ) $ (10.4 ) Noncurrent liability $ (83.6 ) $ (110.7 ) (275.7 ) (262.1 ) $ (11.7 ) $ (35.5 ) (205.8 ) (196.8 )
Schedule of Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Other changes in plan assets and benefit obligations recognized in OCI (net of tax) were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Current year actuarial (gain) loss $ (1.0 ) $ 0.6 $ 2.7 $ 1.1 $ 0.8 $ (1.2 ) Amortization of actuarial losses (0.6 ) (0.6 ) (0.4 ) (0.1 ) — (0.1 ) Amortization of prior service cost — (0.1 ) (0.1 ) — — (0.1 ) Total recognized in OCI $ (1.6 ) $ (0.1 ) $ 2.2 $ 1.0 $ 0.8 $ (1.4 )
Schedule of defined benefit plan, amounts recognized in regulatory assets [Table Text Block]	Amounts recognized in regulatory assets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Net actuarial loss $ 194.8 $ 236.1 $ 43.3 $ 34.7 $ 171.4 $ 208.8 $ 35.9 $ 29.3 Prior service cost 1.2 2.5 — — 1.0 2.2 — — Total $ 196.0 $ 238.6 $ 43.3 $ 34.7 $ 172.4 $ 211.0 $ 35.9 $ 29.3
Schedule of Changes in Fair Value of Plan Assets [Table Text Block]	Pension Benefits The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Fair value of plan assets, January 1 $ 793.6 $ 781.7 $ 732.9 $ 720.1 Actual return on plan assets 128.4 68.1 110.4 60.5 Benefits paid (72.4 ) (56.2 ) (62.0 ) (47.7 ) Fair value of plan assets, December 31 $ 849.6 $ 793.6 $ 781.3 $ 732.9
Schedule of Allocation of Plan Assets [Table Text Block]	The pension plan asset allocation at December 31, 2017 and 2016 and the target allocation for 2018 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2018 2017 2016 Equity Securities 58 % 58 % 57 % Fixed Income 33 % 31 % 32 % Hedge Funds 9 % 11 % 11 %
Schedule of Fair Value of Plan, Assets by Measurement Levels [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Investments with fair value measure at Level 2: Mutual funds $ 120 $ 125 $ 110 $ 115 Short-term investment vehicles 17 16 16 15 US Treasury securities 15 18 14 17 Corporate debt securities 91 82 84 76 Municipals 17 14 15 13 Total assets in the fair value hierarchy 260 255 239 236 Investments at net asset value: Common collective trust 498 453 458 418 Joint venture interests 92 86 84 79 Total investments at fair value $ 850 $ 794 $ 781 $ 733
Schedule of Expected Benefit Payments [Table Text Block]	The Company Consolidated SCE&G Millions of dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits 2018 $ 66.9 $ 13.8 $ 66.9 $ 11.0 2019 64.6 14.6 64.6 11.7 2020 63.9 15.4 63.9 12.3 2021 66.5 16.0 66.5 12.8 2022 72.0 16.5 72.0 13.1 2023-2027 303.0 87.3 303.0 69.6
Schedule of Net Benefit Costs [Table Text Block]	The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Service cost $ 21.7 $ 20.7 $ 24.1 $ 4.5 $ 4.4 $ 5.3 Interest cost 37.4 39.4 38.2 11.5 12.1 11.4 Expected return on assets (54.7 ) (55.9 ) (62.0 ) n/a n/a n/a Prior service cost amortization 1.6 3.9 4.1 — 0.3 0.4 Amortization of actuarial losses 16.3 14.8 13.6 1.0 0.5 2.1 Net periodic benefit cost $ 22.3 $ 22.9 $ 18.0 $ 17.0 $ 17.3 $ 19.2
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]	Amounts recognized in accumulated other comprehensive loss were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Net actuarial loss $ 8.8 $ 10.4 $ 3.5 $ 2.5 $ 2.1 $ 1.9 $ 1.5 $ 1.0 Prior service cost 0.1 0.1 — — — — — — Total $ 8.9 $ 10.5 $ 3.5 $ 2.5 $ 2.1 $ 1.9 $ 1.5 $ 1.0
Schedule of defined benefit plan, Other changes in plan assets recognized in regulatory assets [Table Text Block]	Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Current year actuarial (gain) loss $ (27.1 ) $ 29.4 $ 9.2 $ 9.4 $ 11.1 $ (18.0 ) Amortization of actuarial losses (14.1 ) (12.7 ) (11.9 ) (0.8 ) (0.4 ) (1.8 ) Amortization of prior service cost (1.4 ) (3.4 ) (3.7 ) — (0.3 ) (0.3 ) Total recognized in regulatory assets $ (42.6 ) $ 13.3 $ (6.4 ) $ 8.6 $ 10.4 $ (20.1 )
Schedule of Assumptions Used in Determining Net Periodic Benefit Cost [Table Text Block]	Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Discount rate 4.22 % 4.68 % 4.20 % 4.30 % 4.78 % 4.30 % Expected return on plan assets 7.25 % 7.50 % 7.50 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % Health care cost trend rate n/a n/a n/a 6.60 % 7.00 % 7.00 % Ultimate health care cost trend rate n/a n/a n/a 5.00 % 5.00 % 5.00 % Year achieved n/a n/a n/a 2021 2021 2020
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]	The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2018 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant : Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 0.5 $ 0.1
Schedule of amounts in regulatory assets to be recognized over the next fiscal year [Table Text Block]	The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2018 are as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Actuarial loss $ 10.2 $ 1.8 $ 9.0 $ 1.5 Prior service cost 0.4 — 0.4 — Total $ 10.6 $ 1.8 $ 9.4 $ 1.5
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Schedule of Changes in Projected Benefit Obligations [Table Text Block]	The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below. The Company Consolidated SCE&G Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2017 2016 2017 2016 2017 2016 Benefit obligation, January 1 $ 904.3 $ 855.4 $ 274.7 $ 253.6 $ 768.4 $ 724.0 $ 207.2 $ 191.7 Service cost 21.7 20.7 4.5 4.4 18.1 16.9 3.7 3.6 Interest cost 37.4 39.4 11.5 12.1 31.9 33.4 9.5 9.9 Plan participants’ contributions — — 1.3 1.7 — — 1.1 1.3 Actuarial (gain) loss 42.2 45.0 9.7 14.0 36.6 41.8 6.8 11.5 Benefits paid (72.4 ) (56.2 ) (12.5 ) (11.1 ) (62.0 ) (47.7 ) (10.3 ) (9.1 ) Amounts Funded to parent n/a n/a n/a n/a — — (1.4 ) (1.7 ) Benefit obligation, December 31 $ 933.2 $ 904.3 $ 289.2 $ 274.7 $ 793.0 $ 768.4 $ 216.6 $ 207.2
Schedule of Assumptions Used to Determine Benefit Obligations [Table Text Block]	Significant assumptions used to determine the above benefit obligations are as follows: Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Annual discount rate used to determine benefit obligation 3.71 % 4.22 % 3.74 % 4.30 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 %
Schedule of Net Funded Status [Table Text Block]	The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Fair value of plan assets $ 849.6 $ 793.6 — — $ 781.3 $ 732.9 — — Benefit obligation 933.2 904.3 $ 289.2 $ 274.7 793.0 768.4 $ 216.6 $ 207.2 Funded status $ (83.6 ) $ (110.7 ) $ (289.2 ) $ (274.7 ) $ (11.7 ) $ (35.5 ) $ (216.6 ) $ (207.2 )
Schedule of Amounts Recognized in Balance Sheet [Table Text Block]	Amounts recognized in accumulated other comprehensive loss were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Net actuarial loss $ 8.8 $ 10.4 $ 3.5 $ 2.5 $ 2.1 $ 1.9 $ 1.5 $ 1.0 Prior service cost 0.1 0.1 — — — — — — Total $ 8.9 $ 10.5 $ 3.5 $ 2.5 $ 2.1 $ 1.9 $ 1.5 $ 1.0
Schedule of Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Current year actuarial (gain) loss $ 0.3 — $ 0.2 $ 0.5 $ 0.3 $ (0.3 ) Amortization of actuarial losses (0.1 ) $ (0.1 ) (0.1 ) — — — Amortization of prior service cost — — (0.1 ) — — — Total recognized in OCI $ 0.2 $ (0.1 ) — $ 0.5 $ 0.3 $ (0.3 )
Schedule of defined benefit plan, amounts recognized in regulatory assets [Table Text Block]	Amounts recognized in regulatory assets were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Net actuarial loss $ 194.8 $ 236.1 $ 43.3 $ 34.7 $ 171.4 $ 208.8 $ 35.9 $ 29.3 Prior service cost 1.2 2.5 — — 1.0 2.2 — — Total $ 196.0 $ 238.6 $ 43.3 $ 34.7 $ 172.4 $ 211.0 $ 35.9 $ 29.3
Schedule of Changes in Fair Value of Plan Assets [Table Text Block]	Pension Benefits The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Fair value of plan assets, January 1 $ 793.6 $ 781.7 $ 732.9 $ 720.1 Actual return on plan assets 128.4 68.1 110.4 60.5 Benefits paid (72.4 ) (56.2 ) (62.0 ) (47.7 ) Fair value of plan assets, December 31 $ 849.6 $ 793.6 $ 781.3 $ 732.9
Schedule of Allocation of Plan Assets [Table Text Block]	The pension plan asset allocation at December 31, 2017 and 2016 and the target allocation for 2018 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2018 2017 2016 Equity Securities 58 % 58 % 57 % Fixed Income 33 % 31 % 32 % Hedge Funds 9 % 11 % 11 %
Schedule of Fair Value of Plan, Assets by Measurement Levels [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Investments with fair value measure at Level 2: Mutual funds $ 120 $ 125 $ 110 $ 115 Short-term investment vehicles 17 16 16 15 US Treasury securities 15 18 14 17 Corporate debt securities 91 82 84 76 Municipals 17 14 15 13 Total assets in the fair value hierarchy 260 255 239 236 Investments at net asset value: Common collective trust 498 453 458 418 Joint venture interests 92 86 84 79 Total investments at fair value $ 850 $ 794 $ 781 $ 733
Schedule of Expected Benefit Payments [Table Text Block]	The Company Consolidated SCE&G Millions of dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits 2018 $ 66.9 $ 13.8 $ 66.9 $ 11.0 2019 64.6 14.6 64.6 11.7 2020 63.9 15.4 63.9 12.3 2021 66.5 16.0 66.5 12.8 2022 72.0 16.5 72.0 13.1 2023-2027 303.0 87.3 303.0 69.6
Schedule of Net Benefit Costs [Table Text Block]	Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Service cost $ 18.1 $ 16.9 $ 19.3 $ 3.7 $ 3.6 $ 4.4 Interest cost 31.9 33.4 32.2 9.5 9.9 9.4 Expected return on assets (46.7 ) (47.4 ) (52.2 ) n/a n/a n/a Prior service cost amortization 1.4 3.4 3.4 — 0.3 0.3 Amortization of actuarial losses 13.9 12.5 11.4 0.8 0.4 1.7 Net periodic benefit cost $ 18.6 $ 18.8 $ 14.1 $ 14.0 $ 14.2 $ 15.8
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]	Amounts recognized in accumulated other comprehensive loss were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Net actuarial loss $ 8.8 $ 10.4 $ 3.5 $ 2.5 $ 2.1 $ 1.9 $ 1.5 $ 1.0 Prior service cost 0.1 0.1 — — — — — — Total $ 8.9 $ 10.5 $ 3.5 $ 2.5 $ 2.1 $ 1.9 $ 1.5 $ 1.0
Schedule of defined benefit plan, Other changes in plan assets recognized in regulatory assets [Table Text Block]	Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2017 2016 2015 2017 2016 2015 Current year actuarial (gain) loss $ (24.8 ) $ 26.3 $ 12.2 $ 7.3 $ 9.2 $ (14.0 ) Amortization of actuarial losses (12.5 ) (11.2 ) (10.4 ) (0.7 ) (0.3 ) (1.5 ) Amortization of prior service cost (1.3 ) (3.0 ) (3.1 ) — (0.2 ) (0.3 ) Total recognized in regulatory assets $ (38.6 ) $ 12.1 $ (1.3 ) $ 6.6 $ 8.7 $ (15.8 )
Schedule of Assumptions Used in Determining Net Periodic Benefit Cost [Table Text Block]	Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Discount rate 4.22 % 4.68 % 4.20 % 4.30 % 4.78 % 4.30 % Expected return on plan assets 7.25 % 7.50 % 7.50 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % Health care cost trend rate n/a n/a n/a 6.60 % 7.00 % 7.00 % Ultimate health care cost trend rate n/a n/a n/a 5.00 % 5.00 % 5.00 % Year achieved n/a n/a n/a 2021 2021 2020
Schedule of amounts in regulatory assets to be recognized over the next fiscal year [Table Text Block]	The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2018 are as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Actuarial loss $ 10.2 $ 1.8 $ 9.0 $ 1.5 Prior service cost 0.4 — 0.4 — Total $ 10.6 $ 1.8 $ 9.4 $ 1.5

COMMITMENTS AND CONTINGENCIES A

COMMITMENTS AND CONTINGENCIES ARO (Tables)	12 Months Ended
	Dec. 31, 2017
Change in Asset Retirement Obligations [Line Items]
Change in Asset Retirement Obligations [Table Text Block]	A reconciliation of the beginning and ending aggregate carrying amount of AROs is as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Beginning balance $ 558 $ 520 $ 522 $ 488 Liabilities incurred — — — — Liabilities settled (10 ) (11 ) (9 ) (11 ) Accretion expense 25 23 23 22 Revisions in estimated cash flows (5 ) 26 (7 ) 23 Ending balance $ 568 $ 558 $ 529 $ 522
SCE&G
Change in Asset Retirement Obligations [Line Items]
Change in Asset Retirement Obligations [Table Text Block]	A reconciliation of the beginning and ending aggregate carrying amount of AROs is as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2017 2016 Beginning balance $ 558 $ 520 $ 522 $ 488 Liabilities incurred — — — — Liabilities settled (10 ) (11 ) (9 ) (11 ) Accretion expense 25 23 23 22 Revisions in estimated cash flows (5 ) 26 (7 ) 23 Ending balance $ 568 $ 558 $ 529 $ 522

COMMITMENTS AND CONTINGENCIES O

COMMITMENTS AND CONTINGENCIES Operating Leases Tables (Tables)	12 Months Ended
	Dec. 31, 2017
Operating Leased Assets [Line Items]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	Future Minimum Rental Payments Millions of dollars 2018 2019 2020 2021 2022 Thereafter The Company $ 34 $ 30 $ 6 $ 6 $ 5 $ 31 Consolidated SCE&G 26 23 1 1 — 17
Schedule of Rent Expense [Table Text Block]	Rent Expense Millions of dollars 2017 2016 2015 The Company $ 10.0 $ 10.2 $ 11.1 Consolidated SCE&G 11.4 12.2 12.3
SCE&G
Operating Leased Assets [Line Items]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	Future Minimum Rental Payments Millions of dollars 2018 2019 2020 2021 2022 Thereafter The Company $ 34 $ 30 $ 6 $ 6 $ 5 $ 31 Consolidated SCE&G 26 23 1 1 — 17
Schedule of Rent Expense [Table Text Block]	Rent Expense Millions of dollars 2017 2016 2015 The Company $ 10.0 $ 10.2 $ 11.1 Consolidated SCE&G 11.4 12.2 12.3

SEGMENT OF BUSINESS INFORMATI36

SEGMENT OF BUSINESS INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Disclosure of Reportable Segments The Company: Millions of dollars Electric Operations Gas Distribution Gas Marketing All Other Adjustments/ Eliminations Consolidated Total 2017 External Revenue $ 2,659 $ 874 $ 874 — — $ 4,407 Intersegment Revenue 5 2 127 $ 389 $ (523 ) — Operating Income (Loss) (161 ) 186 n/a — 51 76 Interest Expense 19 28 1 — 315 363 Depreciation and Amortization 295 85 2 16 (16 ) 382 Income Tax Expense (Benefit) 8 41 25 (7 ) (179 ) (112 ) Net Income (Loss) n/a n/a 27 (46 ) (100 ) (119 ) Segment Assets 11,979 3,259 230 1,042 2,229 18,739 Expenditures for Assets 207 417 2 7 592 1,225 Deferred Tax Assets 6 25 9 — (40 ) — 2016 External Revenue $ 2,614 $ 788 $ 825 — — $ 4,227 Intersegment Revenue 5 2 111 $ 414 $ (532 ) — Operating Income 957 148 n/a — 48 1,153 Interest Expense 17 25 1 — 299 342 Depreciation and Amortization 287 82 2 16 (16 ) 371 Income Tax Expense 8 32 19 — 212 271 Net Income (Loss) n/a n/a 30 (18 ) 583 595 Segment Assets 11,929 2,892 230 1,124 2,532 18,707 Expenditures for Assets 1,275 276 2 11 15 1,579 Deferred Tax Assets 9 32 11 — (52 ) — 2015 External Revenue $ 2,551 $ 810 $ 1,018 $ 5 $ (4 ) $ 4,380 Intersegment Revenue 6 2 128 413 (549 ) — Operating Income 876 152 n/a 236 44 1,308 Interest Expense 17 23 1 1 276 318 Depreciation and Amortization 277 77 2 16 (14 ) 358 Income Tax Expense 9 32 18 1 333 393 Net Income (Loss) n/a n/a 28 185 533 746 Segment Assets 10,883 2,606 201 998 2,458 17,146 Expenditures for Assets 1,087 203 2 15 (154 ) 1,153 Deferred Tax Assets 5 29 15 — (49 ) —
SCE&G
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Consolidated SCE&G: Millions of dollars Electric Gas Adjustments/ Consolidated 2017 External Revenue $ 2,664 $ 406 — $ 3,070 Operating Income (Loss) (161 ) 71 — (90 ) Interest Expense 19 — $ 269 288 Depreciation and Amortization 295 30 (13 ) 312 Segment Assets 11,979 869 3,098 15,946 Expenditures for Assets 207 65 656 928 Deferred Tax Assets 6 n/a (6 ) — 2016 External Revenue $ 2,619 $ 367 — $ 2,986 Operating Income 957 56 — 1,013 Interest Expense 17 — $ 253 270 Depreciation and Amortization 287 28 (13 ) 302 Segment Assets 11,929 825 3,337 16,091 Expenditures for Assets 1,275 78 46 1,399 Deferred Tax Assets 9 n/a (9 ) — 2015 External Revenue $ 2,557 $ 373 — $ 2,930 Operating Income 876 58 — 934 Interest Expense 17 — $ 231 248 Depreciation and Amortization 277 28 (11 ) 294 Segment Assets 10,883 757 3,125 14,765 Expenditures for Assets 1,087 57 (136 ) 1,008 Deferred Tax Assets 5 n/a (5 ) —

OTHER INCOME (EXPENSE), NET (Ta

OTHER INCOME (EXPENSE), NET (Tables)	12 Months Ended
	Dec. 31, 2017
Schedule of Other Operating Cost and Expense, by Component [Table Text Block]	Components of other income (expense), net are as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Other income $ 79 $ 64 $ 75 $ 45 $ 29 $ 31 Other expense (46 ) (38 ) (60 ) (25 ) (24 ) (31 ) Allowance for equity funds used during construction 23 29 27 15 26 25 Other income (expense), net $ 56 $ 55 $ 42 $ 35 $ 31 $ 25
SCE&G
Schedule of Other Operating Cost and Expense, by Component [Table Text Block]	Components of other income (expense), net are as follows: The Company Consolidated SCE&G Millions of dollars 2017 2016 2015 2017 2016 2015 Other income $ 79 $ 64 $ 75 $ 45 $ 29 $ 31 Other expense (46 ) (38 ) (60 ) (25 ) (24 ) (31 ) Allowance for equity funds used during construction 23 29 27 15 26 25 Other income (expense), net $ 56 $ 55 $ 42 $ 35 $ 31 $ 25

QUARTERLY FINANCIAL INFORMATI38

QUARTERLY FINANCIAL INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2017
Statement [Line Items]
Schedule of Quarterly Financial Information [Table Text Block]	The Company First Quarter Second Quarter Third Quarter Fourth Quarter Annual 2017 Total operating revenues $ 1,173 $ 1,001 $ 1,076 $ 1,157 $ 4,407 Operating income (loss) 316 249 120 (609 ) 76 Net Income (Loss) 171 121 34 (445 ) (119 ) Earnings (Loss) per share 1.19 0.85 0.24 (3.11 ) (0.83 ) 2016 Total operating revenues $ 1,172 $ 905 $ 1,093 $ 1,057 $ 4,227 Operating income 331 221 348 253 1,153 Net Income 176 105 189 125 595 Earnings per share 1.23 0.74 1.32 0.87 4.16
SCE&G
Statement [Line Items]
Schedule of Quarterly Financial Information [Table Text Block]	Consolidated SCE&G Millions of dollars First Quarter Second Quarter Third Quarter Fourth Quarter Annual 2017 Total operating revenues $ 719 $ 756 $ 856 $ 739 $ 3,070 Operating income (loss) 222 246 123 (681 ) (90 ) Net Income (Loss) 112 126 42 (452 ) (172 ) Earnings Available (Loss Attributable) to Common Shareholder 109 123 39 (456 ) (185 ) 2016 Total operating revenues $ 717 $ 692 $ 882 $ 695 $ 2,986 Operating income 236 222 359 196 1,013 Net Income 116 113 204 93 526 Earnings Available to Common Shareholder 113 110 201 89 513

SUMMARY OF SIGNIFICANT ACCOUN39

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MWshares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares
Significant Accounting Policies
Long-term Debt, Current Maturities	$ 727	$ 17
Short-term borrowings	350	941
Regulated Operating Revenue, Gas	874	788	$ 811
Pre-tax gain on sale of CGT and SCI			$ 342
Unbilled Receivables, Current	220.9	178.9
Goodwill	$ 210	$ 210
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.63%	2.61%	2.61%
Public Utilities, Allowance for Funds Used During Construction, Additions	5.60%	5.30%	6.10%
Property, Plant and Equipment, Net	$ 270	$ 276
Asset Management and Supply Service Agreements
Future Operating Impairment Loss	$ 4,800
Earnings Per Share
Weighted Average Shares Outstanding - Basic | shares	143	143	143
SCEG and GENCO [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.55%	2.56%	2.56%
SCE&G
Significant Accounting Policies
Long-term Debt, Current Maturities	$ 723	$ 12
Short-term borrowings	252	804
Maintenance Costs	18.4
Utilities Operating Expense, Maintenance	26.1	23.8
Environmental Remediation Costs Recognized in Regulatory Assets	24.6
Unbilled Receivables, Current	$ 140.3	$ 117.6
Accrual period of nuclear refueling charges (in months)	18
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.55%	2.56%	2.55%
Public Utilities, Allowance for Funds Used During Construction, Additions	3.90%	4.70%	5.60%
Property, Plant and Equipment, Net	$ 71	$ 69
Genco
Significant Accounting Policies
Power Generation Capacity Megawatts | MW	605
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.66%	2.66%	2.66%
Property, Plant and Equipment, Net	$ 503
PSNC Energy
Significant Accounting Policies
Goodwill	210
Accumulated Amortization and Write-down, Goodwill	$ 230
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	3.03%	2.90%	2.94%
Asset Management and Supply Service Agreements
Natural gas inventory, carrying amount	$ 11.5	$ 9.8
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	39.00%	40.00%
PercentOfStorageFeesCreditedToRatePayers	75.00%
Summer Station Unit 1 [Domain]
Significant Accounting Policies
Jointly Owned Utility Plant, Proportionate Ownership Share	66.70%	66.70%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 1,500	$ 1,300
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	637.6	634.4
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	110.1	167.7
Summer Station Unit 1 [Domain] | SCE&G
Significant Accounting Policies
Accounts Receivable, Net	$ 53.8	$ 76.2
Summer Station New Units [Domain]
Significant Accounting Policies
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%	55.00%
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress		$ 4,200
SCE&G
Significant Accounting Policies
Decommissioning Liability, Noncurrent	$ 786.4
Decommissioning safe storage	60
Payments to Acquire Investments to be Held in Decommissioning Trust Fund	$ 3.2
Amount accrued annually for nuclear fuel outages	17.2
Nuclear refueling outage cost	$ 23.2	$ 1.8

RATE AND OTHER REGULATORY MAT40

RATE AND OTHER REGULATORY MATTERS RATE AND OTHER REGULATORY MATTERS (Details)	3 Months Ended		12 Months Ended
	Sep. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2018	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances				$ 1,900,000,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery				$ 0.035
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent				35.00%
SCE&G
Demand Side Management Program Costs, Noncurrent				$ 37,000,000	$ 37,600,000	$ 32,000,000
Capacity of renewable energy facilities by 2020				84.5
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances					61,000,000
SCPSC Order, Recovery Of Projected DER Program Costs				$ 16,500,000	6,900,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery				61,000,000
Carrying costs on deferred income tax assets				18,800,000	$ 14,000,000
SCPSC Order, Approx Annual pension rider decrease amount				11,900,000
DSM Program SCPC January 2017 filing, cost and net lost revenue recovery [Line Items]				$ 37,000,000
PSNC Energy [Member]
Pipeline integrity mgmt annual revenue requirement approved by NCUC	$ 700,000	$ 1,900,000
Pipeline integrity management costs [Member] | PSNC Energy [Member]
Regulatory Asset, Amortization Period				2021 years
Deferred Income Tax Charge [Member]
Regulatory Asset, Amortization Period				85 years
Pension Costs [Member] | SCE&G
Regulatory Asset, Amortization Period				11 years
Pension costs, electric [Member] | SCE&G
Regulatory Asset, Amortization Period				2044 years
Pension costs, gas [Member] | SCE&G
Regulatory Asset, Amortization Period				2027 years
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period				107 years
Subsequent Event [Member]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent			21.00%

RATE AND OTHER REGULATORY MAT41

RATE AND OTHER REGULATORY MATTERS ELECTRIC-BLRA (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Entity Information [Line Items]
Utilities Operating Expense, Impairments	$ 210		$ 1,118
Accumulated Carrying Costs Written Off			51
Regulatory Request to Lower Revenues			445
SCE&G
Entity Information [Line Items]
Utilities Operating Expense, Impairments			$ 1,118
Public Utilties increase (decrease) in retail electric rates				$ 64.4	$ 64.5
Public Utilities, Authorized Allowable Return on Common Equity, Percentage			10.50%	10.50%	11.00%
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA				2.70%	2.60%
Scenario, Forecast [Member] | SCE&G
Entity Information [Line Items]
Public Utilities, Authorized Allowable Return on Common Equity, Percentage		10.25%
Pension costs, electric [Member] | SCE&G
Entity Information [Line Items]
Regulatory Asset, Amortization Period			2044 years

RATE AND OTHER REGULATORY MAT42

RATE AND OTHER REGULATORY MATTERS GAS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
SCE&G
Entity Information [Line Items]
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates	2.20%	1.20%
Public Utilities, Authorized Allowable Return on Common Equity, Percentage	10.50%	10.50%	11.00%
Public Utilities changes in Retail Natural Gas Rates Approved under RSA	$ 8.6	$ 4.1	$ 0
PSNC Energy [Member]
Entity Information [Line Items]
PSNC Energy Rate Case Application, Percentage Increase	4.39%
Public Utilities, Authorized Allowable Return on Common Equity, Percentage	9.70%
PSNC Energy Rate Case Application, Increase Amount	$ 19.1

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES(Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Regulatory Assets, Noncurrent	$ 5,580	$ 2,130
Regulatory Liability, Noncurrent	3,059	930
Asset Retirement Obligation Costs [Member]
Regulatory Liability, Noncurrent	757	755
Deferred Income Tax Charge [Member]
Regulatory Liability, Noncurrent	1,076	23
Deferred gains on interest rate derivatives [Member]
Regulatory Liability, Noncurrent	131	151
Other Regulatory Liability [Member]
Regulatory Liability, Noncurrent	0	1
Unrecovered nuclear project costs post impairment [Member]
Regulatory Assets, Noncurrent	3,976
Demand Side Management programs [Member]
Regulatory Assets, Noncurrent	59	59
Pipeline integrity management costs [Member]
Regulatory Assets, Noncurrent	51	33
carrying cost on nuclear [Member]
Regulatory Assets, Noncurrent	0	32
Storm Costs [Member]
Regulatory Assets, Noncurrent	24	20
Deferred costs uncertain tax position [Member]
Regulatory Assets, Noncurrent	$ 0	15
Deferred Income Tax Charge [Member]
Regulatory Asset, Amortization Period	85 years
Regulatory Assets, Noncurrent	$ 0	316
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period	107 years
Regulatory Assets, Noncurrent	$ 434	425
Pension Costs [Member]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	1
Regulatory Assets, Noncurrent	305	342
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets, Noncurrent	456	620
Canadys Refined Coal [Member]
Regulatory Assets, Noncurrent	105	117
Environmental Restoration Costs [Member]
Regulatory Assets, Noncurrent	$ 30	32
Other Regulatory Assets [Member]
Regulatory Asset Recovery Assessments	2,047
Regulatory Assets, Noncurrent	$ 140	119
Summer Station New Units [Domain] | Settlement Proceeds [Member]
Regulatory Liability, Noncurrent	1,095	0
SCE&G
Regulatory Assets, Noncurrent	5,476	2,030
Regulatory Liability, Noncurrent	2,667	695
SCE&G | Settlement Proceeds [Member]
Regulatory Liability, Noncurrent	1,095	0
SCE&G | Asset Retirement Obligation Costs [Member]
Regulatory Liability, Noncurrent	527	529
SCE&G | Deferred Income Tax Charge [Member]
Regulatory Liability, Noncurrent	914	14
SCE&G | Deferred gains on interest rate derivatives [Member]
Regulatory Liability, Noncurrent	131	151
SCE&G | Other Regulatory Liability [Member]
Regulatory Liability, Noncurrent	0	1
SCE&G | Unrecovered nuclear project costs post impairment [Member]
Regulatory Assets, Noncurrent	3,976	0
SCE&G | Demand Side Management programs [Member]
Regulatory Assets, Noncurrent	59	59
SCE&G | Pipeline integrity management costs [Member]
Regulatory Assets, Noncurrent	8	6
Pipeline integrity management costs, annual amortization amount	1.9
SCE&G | carrying cost on nuclear [Member]
Regulatory Assets, Noncurrent	0	32
SCE&G | Storm Costs [Member]
Regulatory Assets, Noncurrent	24	20
SCE&G | Deferred costs uncertain tax position [Member]
Regulatory Assets, Noncurrent	0	15
SCE&G | Deferred Income Tax Charge [Member]
Regulatory Assets, Noncurrent	0	307
SCE&G | Asset Retirement Obligation Costs [Member]
Regulatory Assets, Noncurrent	$ 410	403
SCE&G | Pension Costs [Member]
Regulatory Asset, Amortization Period	11 years
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	$ 2
Regulatory Assets, Noncurrent	273	309
SCE&G | Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets, Noncurrent	456	620
SCE&G | Canadys Refined Coal [Member]
Regulatory Assets, Noncurrent	$ 105	117
SCE&G | Environmental Restoration Costs [Member]
Regulatory Asset, Amortization Period	17 years
Regulatory Assets, Noncurrent	$ 25	26
SCE&G | Other Regulatory Assets [Member]
Regulatory Assets, Noncurrent	140	$ 116
PSNC Energy [Member]
Pipeline integrity management costs, amount recovering beginning November 2016	4.1
Pipeline integrity management costs, amount deferred pending future approval of rate recovery	$ 26.6
PSNC Energy [Member] | Pipeline integrity management costs [Member]
Regulatory Asset, Amortization Period	2021 years
PSNC Energy [Member] | Environmental Restoration Costs [Member]
Regulatory Asset, Amortization Period	2021 years

RATE AND OTHER REGULATORY MAT44

RATE AND OTHER REGULATORY MATTERS NARRATIVE (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Deferred Income Tax Charge [Member]
Regulatory Asset, Amortization Period	85 years
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period	107 years
SCE&G
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	$ 831
Total New Nuclear Project Cost Approved By SCPSC In September 2015	6,800
EPC Contract Amendment, Total New Nuclear Project Cost Including Amendment Increase	$ 7,700
SCE&G | Pension Costs [Member]
Regulatory Asset, Amortization Period	11 years
SCE&G | Pension costs, gas [Member]
Regulatory Asset, Amortization Period	2027 years
SCE&G | Pension costs, electric [Member]
Regulatory Asset, Amortization Period	2044 years
PSNC Energy [Member]
MPG environmental remediation	6.9
PSNC Energy [Member] | Pipeline integrity management costs [Member]
Regulatory Asset, Amortization Period	2021 years

COMMON EQUITY (Details)

COMMON EQUITY (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	200,000,000	200,000,000
Dividend Payment Restrictions Schedule, Description	0.6125
SCE&G
Schedule of Capitalization, Equity [Line Items]
Retained Earnings, Appropriated	$ 93.9	$ 79
Common Stock, Shares Authorized	50,000,000	50,000,000
Preferred Stock, Shares Authorized	20,000,000	20,000,000
Preferred Stock, Shares Outstanding	1,000	1,000
PSNC Energy [Member]
Schedule of Capitalization, Equity [Line Items]
Dividend Payment Restrictions Schedule, Description	$30 million plus 85%
Dividends, Common Stock, Cash	$ 100

LONG-TERM AND SHORT-TERM DEBT46

LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016
Debt Instrument [Line Items]
Medium-term Notes	$ 800		$ 800
Senior Notes	75		79
First Mortgage Bonds	4,840		4,840	$ 425
First Mortgage Bonds rate				4.10%
GENCO Notes	207		213
Industrial and Pollution Control Bonds	122		122
Senior Notes, Noncurrent	600		450
Other Long-term Debt	28		27
Long-term Debt, Gross	6,672		6,531
Long-term Debt, Current Maturities	(727)		(17)
Debt Instrument, Unamortized Discount	1		1
Unamortized Debt Issuance Expense	(38)		(40)
Long-term Debt	5,906		$ 6,473
Long-term Debt Current Maturities in Next Twelve Months	727
Long-term Debt, Maturities, Repayments of Principal in Year Two	16
Long-term Debt, Maturities, Repayments of Principal in Year Three	366
Long-term Debt, Maturities, Repayments of Principal in Year Four	494
Long-term Debt, Maturities, Repayments of Principal in Year Five	$ 264
Medium-term Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.42%		5.42%
Debt Instrument, Redemption Period, Start Date	Apr. 1, 2020
Debt Instrument, Redemption Period, End Date	Feb. 1, 2022
First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.80%		5.79%
Debt Instrument, Redemption Period, Start Date	Nov. 1, 2018
Debt Instrument, Redemption Period, End Date	Jun. 1, 2065
Genco Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.94%		5.93%
Debt Instrument, Redemption Period, Start Date	Feb. 1, 2018
Debt Instrument, Redemption Period, End Date	Feb. 1, 2024
Industrial and Pollution Control Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	3.52%		3.51%
Debt Instrument, Redemption Period, Start Date	Feb. 1, 2028
Debt Instrument, Redemption Period, End Date	Dec. 1, 2038
Long-term Debt, Percentage Bearing Variable Interest, Amount	$ 67.8
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	1.85%		0.76%
Senior Debentures [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.19%		5.53%
Debt Instrument, Redemption Period, Start Date	Mar. 30, 2020
Debt Instrument, Redemption Period, End Date	Dec. 15, 2046
Other Debt [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	2.83%		2.76%
Debt Instrument, Redemption Period, Start Date	Jan. 1, 2018
Debt Instrument, Redemption Period, End Date	Sep. 30, 2027
Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	2.18%		1.63%
Debt Instrument, Redemption Period, Start Date	Jun. 1, 2018
Debt Instrument, Redemption Period, End Date	Jun. 1, 2034
Long-term Debt, Percentage Bearing Fixed Interest, Percentage Rate			6.17%
SCE&G
Debt Instrument [Line Items]
First Mortgage Bonds due 2064				$ 75
First Mortgage Bonds	$ 4,840		$ 4,840
GENCO Notes	207		213
Industrial and Pollution Control Bonds	122		122
Debt Instrument, Interest Rate, Stated Percentage				4.50%
First Mortgage Bonds issued May 2014				$ 300
Other Long-term Debt	28		26
Long-term Debt, Gross	5,197		5,201
Long-term Debt, Current Maturities	(723)		(12)
Debt Instrument, Unamortized Discount (Premium), Net	1		1
Unamortized Debt Issuance Expense	(34)		(36)
Long-term Debt	4,441		$ 5,154
Long-term Debt, Maturities, Repayments of Principal in Year Two	12
Long-term Debt, Maturities, Repayments of Principal in Year Three	11
Long-term Debt, Maturities, Repayments of Principal in Year Four	40
Long-term Debt, Maturities, Repayments of Principal in Year Five	$ 9
SCE&G | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.80%		5.79%
Debt Instrument, Redemption Period, End Date	Jun. 1, 2065
SCE&G | Genco Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.94%		5.93%
Debt Instrument, Redemption Period, End Date	Feb. 1, 2024
SCE&G | Industrial and Pollution Control Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	3.52%		3.51%
Debt Instrument, Redemption Period, End Date	Dec. 1, 2038
Long-term Debt, Percentage Bearing Variable Interest, Amount			$ 67.8
SCE&G | Other Debt [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	2.83%		2.76%
Debt Instrument, Redemption Period, Start Date	Jan. 31, 2018
Debt Instrument, Redemption Period, End Date	Sep. 30, 2027
SCEG including Fuel Company [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	1.92%		1.04%
Long-term Debt Current Maturities in Next Twelve Months	$ 723
PSNC Energy [Member]
Debt Instrument [Line Items]
Senior Notes		$ 150		$ 100
Debt Instrument, Interest Rate, Stated Percentage		4.18%		4.13%
Debt, Weighted Average Interest Rate	1.93%		1.07%

LONG-TERM AND SHORT-TERM DEBT47

LONG-TERM AND SHORT-TERM DEBT (Details 2)	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Debt Instrument, Redemption [Line Items]
Bond Ratio		5.24
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,000,000,000	$ 2,000,000,000
Commercial Paper	350,300,000	940,500,000
commercial paper available to be borrowed	600,000,000
Letters of Credit Outstanding, Amount	3,300,000	3,300,000
Line of Credit Facility, Remaining Borrowing Capacity	1,646,400,000	1,056,200,000
Genco
Debt Instrument, Redemption [Line Items]
Commercial Paper	200,000,000
SCEG including Fuel Company [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,400,000,000	1,400,000,000
Commercial Paper	$ 251,600,000	$ 804,300,000
Debt, Weighted Average Interest Rate	1.92%	1.04%
Letters of Credit Outstanding, Amount	$ 300,000	$ 300,000
Line of Credit Facility, Remaining Borrowing Capacity	1,148,100,000	595,400,000
Commercial paper borrowing limit	1,600,000,000
SCANA [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	400,000,000	400,000,000
Commercial Paper	$ 0	$ 64,400,000
Debt, Weighted Average Interest Rate	0.00%	1.43%
Letters of Credit Outstanding, Amount	$ 3,000,000	$ 3,000,000
Line of Credit Facility, Remaining Borrowing Capacity	397,000,000	332,600,000
Fuel Company [Member]
Debt Instrument, Redemption [Line Items]
Long-Term Line of Credit - SC Fuel Co only	500,000,000	500,000,000
SCE&G
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	700,000,000	700,000,000
Long-term Line of Credit - SCE&G only	200,000,000	200,000,000
PSNC Energy [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200,000,000	200,000,000
Commercial Paper	$ 98,700,000	$ 71,800,000
Debt, Weighted Average Interest Rate	1.93%	1.07%
Line of Credit Facility, Remaining Borrowing Capacity	$ 101,300,000	$ 128,200,000
Industrial and Pollution Control Bonds [Member]
Debt Instrument, Redemption [Line Items]
Debt, Weighted Average Interest Rate	3.52%	3.51%
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	1.85%	0.76%
Industrial and Pollution Control Bonds [Member] | SCE&G
Debt Instrument, Redemption [Line Items]
Debt, Weighted Average Interest Rate	3.52%	3.51%
Wells Fargo, National Association, Bank of America & Morgan Stanley [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 0.095
JP Morgan Chase, Mizuho Corp, TD Bank, Credit Suisse AG ,Cayman Islands Branch and UBS Loan Finance [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	7.9
royal bank of canada [Domain]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	0.055
3 Year Credit [Domain]
Debt Instrument, Redemption [Line Items]
Long-term Line of Credit - SCE&G only	200,000,000	$ 200,000,000
five year credit [Domain]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,300,000,000	$ 1,300,000,000

LONG-TERM AND SHORT-TERM DEBT48

LONG-TERM AND SHORT-TERM DEBT (NARRATIVE) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
months preceding issuance of bonds	18
Unfunded property additions	70.00%
Consecutive months for bond ratio	12
Bond Ratio	5.24
SCE&G
Debt Instrument [Line Items]
Due to Related Parties	$ 29	$ 37
Due from Related Parties		$ 28

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($)	3 Months Ended		9 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Investments, Owned, Federal Income Tax Note [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards				$ 600,000,000
Deferred Tax Asset, Legal Settlement				273,000,000
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards		$ 49,000,000		98,000,000	$ 350,000,000	$ 49,000,000	$ 16,000,000
Decrease in Unrecognized Tax Benefits is Reasonably Possible				11,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate				$ 98,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent		5.00%	6.00%	3.00%	4.00%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent				35.00%
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)				$ (414,000,000)	$ 36,000,000	382,000,000
Current State and Local Tax Expense (Benefit)				18,000,000	13,000,000	57,000,000
Current Income Tax Expense (Benefit)				(396,000,000)	49,000,000	439,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)				323,000,000	203,000,000	(36,000,000)
Deferred State and Local Income Tax Expense (Benefit)				(37,000,000)	21,000,000	(7,000,000)
Deferred Income Tax Expense (Benefit)				286,000,000	224,000,000	(43,000,000)
Income Tax Reconciliation, Tax Credits, Investment [Abstract]
Amortization of Amounts Deferred Under State and Local Investment Tax Credits				0	0	(1,000,000)
Investment Tax Credit				(2,000,000)	(2,000,000)	(3,000,000)
Income Tax Expense (Benefit)				(112,000,000)	271,000,000	393,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic				(231,000,000)	866,000,000	1,139,000,000
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount				(81,000,000)	303,000,000	399,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount				(7,000,000)	27,000,000	38,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits				(5,000,000)	(5,000,000)	(6,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction				(8,000,000)	(10,000,000)	(9,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Dividends, Amount				(9,000,000)	(10,000,000)	(10,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits				(2,000,000)	(2,000,000)	(2,000,000)
Section 45 tax credit				(8,000,000)	(8,000,000)	(9,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent				(18,000,000)	(23,000,000)	(18,000,000)
Income Tax Reconcilation, Tax Reform Remeasurement				30,000,000
Income Tax Reconciliation, Sale of Subsidiaries				0	0	7,000,000
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount				(4,000,000)	(1,000,000)	3,000,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities				88,000,000	148,000,000
Deferred tax Nuclear Decommissioning				141,000,000	213,000,000
Deferred Tax Asset, Remeasurement				54,000,000
Deferred Tax Assets, Financial Instruments				15,000,000	22,000,000
Deferred Tax Asset, Unamortized Investment, Tax Credits				8,000,000	15,000,000
Deferred Tax Asset, Deferred Fuel Cost					17,000,000
Deferred Tax Assets, Other				6,000,000	10,000,000
Deferred Tax Assets, Net				1,185,000,000	425,000,000
Deferred Tax Liabilities, Property, Plant and Equipment				1,220,000,000	2,159,000,000
Deferred Tax Liability, Impairment				962,000,000
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits				60,000,000	105,000,000
Deferred Tax Liabilities, Asset Retirement Obligation				91,000,000	143,000,000
Deferred tax asset unrecovered plant				27,000,000	45,000,000
Deferred Tax Liability, Demand Side Management				16,000,000	23,000,000
deferred tax liability, prepayments				21,000,000	32,000,000
Deferred Tax Liabilities, Other				49,000,000	77,000,000
Deferred Tax Liabilities, Net				2,446,000,000	2,584,000,000
Deferred Tax Liabilities, Net, Noncurrent				1,261,000,000	2,159,000,000
Unrecognized tax benefits				19,000,000	219,000,000
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions				0	94,000,000	33,000,000
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions				(273,000,000)	0	(2,000,000)
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions				21,000,000	207,000,000	2,000,000
SCE&G
Investments, Owned, Federal Income Tax Note [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards				541,000,000
Deferred Tax Asset, Legal Settlement				273,000,000
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards		$ 49,000,000		98,000,000	350,000,000	49,000,000	$ 16,000,000
Decrease in Unrecognized Tax Benefits is Reasonably Possible				11,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate				98,000,000
Increase in Unrecognized Tax Benefits is Reasonably Possible				0
Unrecognized Tax Benefits, Interest Income on Taxes Accrued				0
Unrecognized Tax Benefits, Interest on Income Taxes Accrued				0
Unrecognized Tax Benefits, Income Tax Penalties Expense				0
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)				(410,000,000)	50,000,000	208,000,000
Current State and Local Tax Expense (Benefit)				(18,000,000)	13,000,000	32,000,000
Current Income Tax Expense (Benefit)				(428,000,000)	63,000,000	240,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)				261,000,000	167,000,000	(3,000,000)
Deferred State and Local Income Tax Expense (Benefit)				2,000,000	20,000,000	(3,000,000)
Deferred Income Tax Expense (Benefit)				(259,000,000)	187,000,000	(6,000,000)
Income Tax Reconciliation, Tax Credits, Investment [Abstract]
Amortization of Amounts Deferred Under State and Local Investment Tax Credits				0	0	(1,000,000)
Investment Tax Credit				(2,000,000)	(2,000,000)	(3,000,000)
Income Tax Expense (Benefit)				(171,000,000)	248,000,000	231,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic				(343,000,000)	774,000,000	711,000,000
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount				(120,000,000)	271,000,000	249,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount				(8,000,000)	26,000,000	24,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits				(5,000,000)	(5,000,000)	(6,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction				(5,000,000)	(9,000,000)	(9,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits				(2,000,000)	(2,000,000)	(2,000,000)
Section 45 tax credit				(8,000,000)	(8,000,000)	(9,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent				(18,000,000)	(23,000,000)	(18,000,000)
Income Tax Reconcilation, Tax Reform Remeasurement				(1,000,000)
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount				(4,000,000)	(2,000,000)	2,000,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities				42,000,000	53,000,000
Deferred tax Nuclear Decommissioning				132,000,000	200,000,000
Deferred Tax Asset, Remeasurement				54,000,000
Deferred Tax Asset, Unamortized Investment, Tax Credits				8,000,000	15,000,000
Deferred Tax Asset, Deferred Fuel Cost					17,000,000
Deferred Tax Assets, Other				5,000,000	8,000,000
Deferred Tax Assets, Net				1,055,000,000	293,000,000
Deferred Tax Liabilities, Property, Plant and Equipment				1,035,000,000	1,856,000,000
Deferred Tax Liability, Impairment				962,000,000
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits				53,000,000	93,000,000
Deferred Tax Liabilities, Asset Retirement Obligation				85,000,000	135,000,000
Deferred tax asset unrecovered plant				27,000,000	45,000,000
Deferred Tax Liability, Demand Side Management				16,000,000	23,000,000
deferred tax liability, prepayments				19,000,000	30,000,000
Deferred Tax Liabilities, Other				31,000,000	50,000,000
Deferred Tax Liabilities, Net				2,228,000,000	2,232,000,000
Deferred Tax Liabilities, Net, Noncurrent				1,173,000,000	1,939,000,000
Unrecognized tax benefits				19,000,000	236,000,000
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions				0	94,000,000	33,000,000
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions				(273,000,000)	0	(2,000,000)
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions				$ 21,000,000	$ 207,000,000	$ 2,000,000
Income Tax Authority [Domain]
Investments, Owned, Federal Income Tax Note [Line Items]
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	2.50%

INCOME TAXES INCOME TAXES (Deta

INCOME TAXES INCOME TAXES (Details 2) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
income tax [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent									35.00%
Income Available to Common Shareholders	$ (445,000,000)	$ 34,000,000	$ 121,000,000	$ 171,000,000	$ 125,000,000	$ 189,000,000	$ 105,000,000	$ 176,000,000	$ (119,000,000)	$ 595,000,000	$ 746,000,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate									(81,000,000)	303,000,000	399,000,000
Income Tax Expense (Benefit) Continuing Operations, Income Tax Reconciliation, Changes [Abstract]
Income Tax Reconciliation, State and Local Income Taxes									(7,000,000)	27,000,000	38,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits									(5,000,000)	(5,000,000)	(6,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction									(8,000,000)	(10,000,000)	(9,000,000)
Income Tax Reconciliation, Deductions, Dividends									9,000,000	10,000,000	10,000,000
Amortization of Amounts Deferred under Federal Investment Tax Credits									2,000,000	2,000,000	2,000,000
Section 45 tax credit									8,000,000	8,000,000	9,000,000
Income Tax Reconciliation, Other Adjustments									(4,000,000)	(1,000,000)	3,000,000
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent									(18,000,000)	(23,000,000)	(18,000,000)
Income Tax Expense (Benefit)									(112,000,000)	271,000,000	393,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic									(231,000,000)	866,000,000	1,139,000,000
Income Tax Reconciliation, Sale of Subsidiaries									0	0	7,000,000
SCE&G
income tax [Line Items]
Net Income (Loss) Attributable to Parent	$ (456,000,000)	$ 39,000,000	$ 123,000,000	$ 109,000,000	$ 89,000,000	$ 201,000,000	$ 110,000,000	$ 113,000,000	(185,000,000)	513,000,000	466,000,000
Net Income (Loss) Attributable to Noncontrolling Interest									13,000,000	13,000,000	14,000,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate									(120,000,000)	271,000,000	249,000,000
Income Tax Expense (Benefit) Continuing Operations, Income Tax Reconciliation, Changes [Abstract]
Income Tax Reconciliation, State and Local Income Taxes									(8,000,000)	26,000,000	24,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits									(5,000,000)	(5,000,000)	(6,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction									(5,000,000)	(9,000,000)	(9,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits									2,000,000	2,000,000	2,000,000
Section 45 tax credit									8,000,000	8,000,000	9,000,000
Income Tax Reconciliation, Other Adjustments									(4,000,000)	(2,000,000)	2,000,000
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent									(18,000,000)	(23,000,000)	(18,000,000)
Income Tax Expense (Benefit)									(171,000,000)	248,000,000	231,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic									$ (343,000,000)	$ 774,000,000	$ 711,000,000

INCOME TAXES INCOME TAXES (De51

INCOME TAXES INCOME TAXES (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	$ 88	$ 148
Deferred tax Nuclear Decommissioning	141	213
Deferred Tax Assets, Financial Instruments	15	22
Deferred Tax Asset, Unamortized Investment, Tax Credits	8	15
Deferred Tax Asset, Deferred Fuel Cost		17
Deferred Tax Assets, Other	6	10
Deferred Tax Assets, Net	1,185	425
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	1,220	2,159
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	60	105
Deferred Tax Liabilities, Asset Retirement Obligation	91	143
Deferred tax asset unrecovered plant	27	45
Deferred Tax Liability, Demand Side Management	16	23
deferred tax liability, prepayments	21	32
Deferred Tax Liabilities, Other	49	77
Deferred Tax Liabilities, Gross	2,446	2,584
Deferred Tax Liabilities, Net, Noncurrent	1,261	2,159
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	0	94	$ 33
Gross decreases tax positions in prior period	(273)	0	(2)
Gross increases current period tax positions	21	207	2
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards	98	350	49	$ 16
SCE&G
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	42	53
Deferred tax Nuclear Decommissioning	132	200
Deferred Tax Asset, Unamortized Investment, Tax Credits	8	15
Deferred Tax Asset, Deferred Fuel Cost		17
Deferred Tax Assets, Other	5	8
Deferred Tax Assets, Net	1,055	293
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	1,035	1,856
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	53	93
Deferred Tax Liabilities, Asset Retirement Obligation	85	135
Deferred tax asset unrecovered plant	27	45
Deferred Tax Liability, Demand Side Management	16	23
deferred tax liability, prepayments	19	30
Deferred Tax Liabilities, Other	31	50
Deferred Tax Liabilities, Gross	2,228	2,232
Deferred Tax Liabilities, Net, Noncurrent	1,173	1,939
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	0	94	33
Gross decreases tax positions in prior period	(273)	0	(2)
Gross increases current period tax positions	21	207	2
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards	$ 98	$ 350	$ 49	$ 16

INCOME TAXES INCOME TAXES CARRY

INCOME TAXES INCOME TAXES CARRYFORWARD (Details) - USD ($) $ in Millions	12 Months Ended						24 Months Ended
	Dec. 31, 2037	Dec. 31, 2035	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2037
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent						35.00%
Operating Loss Carryforwards						$ 2,052
Renewable Energy Tax Credit						35
Charitable carryforwards						7
State Operating Loss Carryforward						2,382
State Charitable Carryforwards						3
Tax Credit Carryforward, Amount						4,479
Tax Carryforward [Member]
Tax Credit Carryforward, Ending Expiration Date	Dec. 31, 2037
Renewable Energy Tax Credit [Member]
Tax Credit Carryforward Expiration Date, Beginning		2,035
Tax Credit Carryforward, Ending Expiration Date							Dec. 31, 2037
Federal Charitable Carryforwards [Member]
Tax Credit Carryforward Expiration Date, Beginning				2,021
Tax Credit Carryforward, Ending Expiration Date			Dec. 31, 2022
State NOL Carryforwards [Member]
Tax Credit Carryforward, Ending Expiration Date	Dec. 31, 2037
State Charitable Carryforwards [Member]
Tax Credit Carryforward, Ending Expiration Date			Dec. 31, 2022
SCE&G
Operating Loss Carryforwards						1,905
Renewable Energy Tax Credit						35
Charitable carryforwards						5
State Operating Loss Carryforward						2,301
State Charitable Carryforwards						2
Tax Credit Carryforward, Amount						$ 4,248
Subsequent Event [Member]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent					21.00%

DERIVATIVE FINANCIAL INSTRUME53

DERIVATIVE FINANCIAL INSTRUMENTS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MMBTU		Dec. 31, 2016USD ($)MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	61,719,890	[1]	83,904,223
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6,430,000		4,510,000
Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	55,289,890	[1]	79,394,223
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	41,856,890	[1]	67,447,223
Energy Related Derivative [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	41,856,890		67,447,223
Commodity Contract [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	19,863,000		16,457,000
Commodity Contract [Member] | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6,430,000		4,510,000
Commodity Contract [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	13,433,000		11,947,000
Basis Swap [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	2,582,000		730,721
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 111.2		$ 115.6
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	735		1,285
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	36.4		36.4
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 735		$ 1,285
[1]	(a) Includes amounts related to basis swap contracts totaling 2,582,000 MMBTU in 2017 and 730,721 MMBTU in 2016.

DERIVATIVE FINANCIAL INSTRUME54

DERIVATIVE FINANCIAL INSTRUMENTS FAIR VALUE ON BALANCE SHEET (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 38	$ 67
Derivative Liability	37	64
Derivative Asset	59	86
Derivative Asset, Fair Value, Gross Asset	59	90
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	1	72
Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	28	29
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability	2
Derivative Asset	58	5
Prepayments [Member]
Derivative [Line Items]
Derivative Asset		9
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	32	58
Derivative Liability	32	58
Derivative Asset	54	71
Derivative Asset, Fair Value, Gross Asset	54	71
Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	3
Derivative Liability	3	0
Derivative Asset	1	9
Derivative Asset, Fair Value, Gross Asset	1	9
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	3	9
Derivative Liability	2	6
Derivative Asset	4	6
Derivative Asset, Fair Value, Gross Asset	4	10
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	30	28
Derivative Asset, Fair Value, Gross Asset	0	6
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	3	4
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	24	24
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1
Derivative Asset, Fair Value, Gross Asset		1
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	2
Derivative Asset, Fair Value, Gross Asset		5
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	8	39
Derivative Asset, Fair Value, Gross Asset	59	84
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	54
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1	27
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		71
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	4	3
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1	3
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	4
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	2
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		2
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		1
Derivative Asset, Fair Value, Gross Asset	3	2
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1	2
Derivative Asset, Fair Value, Gross Asset		6
SCE&G
Derivative [Line Items]
Derivative Liability	15	39
Derivative Asset	54	71
SCE&G | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset		71
SCE&G | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	13	11
SCE&G | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	15	39
Derivative Liability	15	39
Derivative Asset	54	71
Derivative Asset, Fair Value, Gross Asset	54	71
SCE&G | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	10	9
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1	1
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	9	8
SCE&G | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	5	30
Derivative Asset, Fair Value, Gross Asset	54	71
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	54
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1	27
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		71
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 4	$ 3

DERIVATIVE FINANCIAL INSTRUME55

DERIVATIVE FINANCIAL INSTRUMENTS ON INCOME STATEMENT (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax		$ (7)	$ 4	$ (12)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		(6)	$ (13)	(22)
Utilities Operating Expense, Impairments	$ 210	$ 1,118
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial		insignificant	insignificant
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		$ 7	$ 7	7
Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred		(7.2)
Commodity Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		(1)	6	15
Commodity Contract [Member] | Gas Purchased for Resale [Member] [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred		(3.3)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net		(32)	(34)	(69)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Nonoperating Income (Expense) [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income			$ (2)	$ 5
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income		(3)
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred		2.7
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Operating Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income		(173)
SCE&G
Derivative [Line Items]
Utilities Operating Expense, Impairments		$ 1,118
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial		insignificant	insignificant	insignificant
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net		$ (32)	$ (34)	$ (69)
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Nonoperating Income (Expense) [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income				5
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income		(3)	(2)
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Operating Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income		(173)
Cash Flow Hedging [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net			(1)	(2)
Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net		(2)		(3)
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net		(2)	(2)	(3)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		(7)	(7)	(7)
Cash Flow Hedging [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net		(7)	5	(10)
Cash Flow Hedging [Member] | Commodity Contract [Member] | Gas Purchased for Resale [Member] [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		1	(6)	(15)
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred		1.5
Cash Flow Hedging [Member] | SCE&G | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net		(2)		(3)
Cash Flow Hedging [Member] | SCE&G | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net		(2)	$ (2)	$ (3)
Cash Flow Hedging [Member] | SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred		1.5
Cash Flow Hedging [Member] | SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred		$ 2.7

DERIVATIVE FINANCIAL INSTRUME56

DERIVATIVE FINANCIAL INSTRUMENTS (CREDIT RISK) (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	$ 28.9	$ 29.2
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	4.8	21.1
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	33.7	50.3
Cash collateral requested from counterparty	53.5	62.9
Derivative, net asset position	53.5	62.9
Letter of Credit Available Commodity Derivatives,asset position	1.2	1.5
Commodity Derivative, net asset position	4	9
SCE&G
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	10.1	9.2
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	4.6	21.1
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	14.7	30.3
Cash collateral requested from counterparty	53.5	62
Derivative, net asset position	53.5	62
Interest Rate Contract [Member] | Interest Expense [Member] | Not Designated as Hedging Instrument [Member]
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(3)
Interest Rate Contract [Member] | Interest Expense [Member] | Not Designated as Hedging Instrument [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(3)	(2)
Interest Rate Contract [Member] | Operating Expense [Member] | Not Designated as Hedging Instrument [Member]
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(173)
Interest Rate Contract [Member] | Operating Expense [Member] | Not Designated as Hedging Instrument [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ (173)
Interest Rate Contract [Member] | Other Nonoperating Income (Expense) [Member] | Not Designated as Hedging Instrument [Member]
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income		$ (2)	$ 5
Interest Rate Contract [Member] | Other Nonoperating Income (Expense) [Member] | Not Designated as Hedging Instrument [Member] | SCE&G
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income			$ 5

DERIVATIVE FINANCIAL INSTRUME57

DERIVATIVE FINANCIAL INSTRUMENTS OFFSETTING ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Liability	$ 37	$ 64
Derivative Asset, Fair Value, Gross Liability	0	(4)
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	(9)
Derivative, Collateral, Obligation to Return Cash
Derivative Liability, Fair Value, Gross Asset	(1)	(3)
Derivative Liabilities, Net Amount	64	26
Derivative Liability, Fair Value, Gross Liability	38	67
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	(9)
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	(27)	(29)
Derivative Assets, Net Amount	59	77
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability	2
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	7	35
Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	28	29
SCE&G
Derivative [Line Items]
Derivative Liability	15	39
SCE&G | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	2	28
SCE&G | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	13	11
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability	32	58
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	(9)
Derivative Liabilities, Net Amount	60	20
Derivative Liability, Fair Value, Gross Liability	32	58
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments		(9)
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	(28)	(29)
Derivative Assets, Net Amount	54	62
Interest Rate Contract [Member] | SCE&G
Derivative [Line Items]
Derivative Liability	15	39
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	(9)
Derivative Liabilities, Net Amount	15	21
Derivative Liability, Fair Value, Gross Liability	15	39
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	(9)
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted		(9)
Derivative Assets, Net Amount	54	62
Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability	3	0
Derivative Liabilities, Net Amount	3	0
Derivative Liability, Fair Value, Gross Liability	3
Derivative Assets, Net Amount	1	9
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability	2	6
Derivative Asset, Fair Value, Gross Liability	0	(4)
Derivative Liability, Fair Value, Gross Asset	(1)	(3)
Derivative Liabilities, Net Amount	1	6
Derivative Liability, Fair Value, Gross Liability	3	9
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	(1)
Derivative Assets, Net Amount	$ 4	$ 6

FAIR VALUE MEASUREMENTS, INCL58

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Nuclear Fuel	$ 87
Derivative Asset	59	$ 86
Derivative Liability	$ 37	$ 64
Liabilities, Fair Value Disclosure [Abstract]
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Level 3 Fair Value Measurements	no	no
Available-for-sale Securities [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	$ 119	$ 14
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	7
Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	54	71
Derivative Liability	32	58
Interest Rate Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	54	71
Financial and Nonfinancial Liabilities, Fair Value Disclosure	32	58
Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	1	9
Derivative Liability	3	0
Commodity Contract [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	1	8
Financial and Nonfinancial Liabilities, Fair Value Disclosure	2	0
Commodity Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	1
Financial and Nonfinancial Liabilities, Fair Value Disclosure	1	0
Other Energy Management Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	4	6
Derivative Liability	2	6
Other Energy Management Contract [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	0	6
Financial and Nonfinancial Liabilities, Fair Value Disclosure	1	2
Other Energy Management Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	4	4
Financial and Nonfinancial Liabilities, Fair Value Disclosure	4	10
SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	54	71
Derivative Liability	$ 15	$ 39
Liabilities, Fair Value Disclosure [Abstract]
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Level 3 Fair Value Measurements	no	no
SCE&G | Available-for-sale Securities [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	$ 100
SCE&G | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	54	$ 71
Derivative Liability	15	39
SCE&G | Interest Rate Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	54	71
Financial and Nonfinancial Liabilities, Fair Value Disclosure	$ 15	$ 39
Nuclear Fuel [Member]
Liabilities, Fair Value Disclosure [Abstract]
Level 3 Fair Value Measurements	43.8

FAIR VALUE MEASUREMENTS, INCL59

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other Long-term Debt, Noncurrent	$ 6,632.9	$ 6,489.8
Long-term debt, Fair Value	7,399.7	7,183.3
SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other Long-term Debt, Noncurrent	5,163.3	5,166
Long-term debt, Fair Value	$ 5,790.3	$ 5,752.3

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year, Description		no
Defined Benefit Plan, Accumulated Benefit Obligation		$ 905.8	$ 874.3
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation		$ 1.6	0.8
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation		$ 1.4	$ 0.7
Defined Benefit Plan Health Care Cost Trend Rate, Assumed		7.00%
Defined Benefit Plan, Target Allocation, Equity Securities		58.00%	57.00%
Defined Benefit Plan, Target Plan Asset Allocations		31.00%	32.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid			$ 11.1
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		$ 1.3	1.7
Defined Benefit Plan, Benefit Obligation		289.2	274.7	$ 253.6
Defined Benefit Plan, Service Cost		4.5	4.4	5.3
Defined Benefit Plan, Interest Cost		11.5	12.1	$ 11.4
Defined Benefit Plan, Actuarial Net (Gains) Losses		$ (9.7)	$ (14)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		3.74%	4.30%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.00%	3.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(289.2)	(274.7)
Liability, Defined Benefit Plan, Current		(13.5)	(12.6)
Liability, Other Postretirement Defined Benefit Plan, Noncurrent		(275.7)	(262.1)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax		3.5	2.5
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax		0	0
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax		3.5	2.5
pension and other postretirement benefit plans, regulated assets, net gains, before tax		43.3	34.7
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		0	0
Pension and other postretirement benefit plans, regulatory assets, before tax		43.3	34.7
Defined Benefit Plan, Shared Costs Deferred		14.7	15.8
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		9.4	11.1	$ (18)
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(0.8)	(0.4)	(1.8)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		0	(0.3)	(0.3)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ 8.6	$ 10.4	$ (20.1)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.30%	4.78%	4.30%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year		6.60%	7.00%	7.00%
Defined Benefit Plan, Benefit Obligation, Benefits Paid		$ 12.5
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		72.4
Defined Benefit Plan, Benefit Obligation		933.2	$ 904.3	$ 855.4
Defined Benefit Plan, Service Cost		21.7	20.7	24.1
Defined Benefit Plan, Interest Cost		37.4	39.4	38.2
Defined Benefit Plan, Actuarial Net (Gains) Losses		$ (42.2)	$ (45)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		3.71%	4.22%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.00%	3.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 849.6	$ 793.6	781.7
Defined Benefit Plan, Plan Assets, Increase (Decrease) for Actual Return (Loss)		128.4	68.1
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(83.6)	(110.7)
Liability, Defined Benefit Pension Plan, Noncurrent		(83.6)	(110.7)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax		8.8	10.4
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax		0.1	0.1
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax		8.9	10.5
pension and other postretirement benefit plans, regulated assets, net gains, before tax		194.8	236.1
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		1.2	2.5
Pension and other postretirement benefit plans, regulatory assets, before tax		196	238.6
Defined Benefit Plan, Shared Costs Deferred		21.4	23.4
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		(27.1)	29.4	9.2
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(14.1)	(12.7)	(11.9)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		(1.4)	(3.4)	(3.7)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ (42.6)	$ 13.3	$ (6.4)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.25%	7.50%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.22%	4.68%	4.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Benefit Obligation, Benefits Paid		$ 72.4	$ 56.2
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year, Description		no
Defined Benefit Plan, Period for which Annual Base Earnings are Considered Under Average Pay Formula		3
Defined Benefit Plan, Accumulated Benefit Obligation		$ 769.7	742.9
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation		$ 1.3	0.6
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation		$ 1.1	$ 0.6
Defined Benefit Plan Health Care Cost Trend Rate, Assumed		7.00%
Defined Benefit Plan, Target Allocation, Equity Securities		58.00%	57.00%
Defined Benefit Plan, Target Plan Asset Allocations		31.00%	32.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
SCE&G | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		$ 10.3	$ 9.1
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		1.1	1.3
Defined Benefit Plan, Benefit Obligation		216.6	207.2	$ 191.7
Defined Benefit Plan, Service Cost		3.7	3.6	4.4
Defined Benefit Plan, Interest Cost		9.5	9.9	$ 9.4
Defined Benefit Plan, Actuarial Net (Gains) Losses		(6.8)	(11.5)
Defined Benefit Plan, Amounts Funded to Parent		$ (1.4)	$ (1.7)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		3.74%	4.30%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.00%	3.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(216.6)	(207.2)
Liability, Defined Benefit Plan, Current		(10.8)	(10.4)
Liability, Other Postretirement Defined Benefit Plan, Noncurrent		(205.8)	(196.8)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax		1.5	1
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax		0	0
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax		1.5	1
pension and other postretirement benefit plans, regulated assets, net gains, before tax		35.9	29.3
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		0	0
Pension and other postretirement benefit plans, regulatory assets, before tax		35.9	29.3
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		7.3	9.2	$ (14)
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(0.7)	(0.3)	1.5
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		0	(0.2)	(0.3)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ 6.6	$ 8.7	$ (15.8)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.30%	4.78%	4.30%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year		6.60%	7.00%	7.00%
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		$ 62	$ 47.7
Defined Benefit Plan, Benefit Obligation		793	768.4	$ 724
Defined Benefit Plan, Service Cost		18.1	16.9	19.3
Defined Benefit Plan, Interest Cost		31.9	33.4	32.2
Defined Benefit Plan, Actuarial Net (Gains) Losses		(36.6)	(41.8)
Defined Benefit Plan, Amounts Funded to Parent		$ 0	$ 0
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		3.71%	4.22%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.00%	3.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 781.3	$ 732.9	720.1
Defined Benefit Plan, Plan Assets, Increase (Decrease) for Actual Return (Loss)		110.4	60.5
Defined Benefit Plan, Funded (Unfunded) Status of Plan		(11.7)	(35.5)
Liability, Defined Benefit Pension Plan, Noncurrent		(11.7)	(35.5)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax		2.1	1.9
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax		0	0
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax		2.1	1.9
pension and other postretirement benefit plans, regulated assets, net gains, before tax		171.4	208.8
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		1	2.2
Pension and other postretirement benefit plans, regulatory assets, before tax		172.4	211
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		(24.8)	26.3	12.2
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(12.5)	(11.2)	(10.4)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		(1.3)	(3)	(3.1)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ (38.6)	$ 12.1	$ (1.3)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.25%	7.50%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.22%	4.68%	4.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Pension Costs [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority		$ 1
Pension Costs [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority		$ 2
Regulatory assets, expected recovery period (in years)		11 years
Scenario, Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	7.00%
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%
Scenario, Forecast [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	7.00%
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%

EMPLOYEE BENEFIT PLANS EMPLOYEE

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 2)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities		58.00%	57.00%
Defined Benefit Plan, Target Plan Asset Allocations		31.00%	32.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities		58.00%	57.00%
Defined Benefit Plan, Target Plan Asset Allocations		31.00%	32.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
Scenario, Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%
Scenario, Forecast [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%

EMPLOYEE BENEFIT PLANS EMPLOY62

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Common collective trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investment, Fair Value Disclosure	$ 498	$ 453
Joint venture interests [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investment, Fair Value Disclosure	92	86
Alternative investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investment, Fair Value Disclosure	850	794
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	260	255
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	120	125
Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	17	16
Fair Value, Inputs, Level 2 [Member] | Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	15	18
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	91	82
Fair Value, Inputs, Level 2 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 17	$ 14
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
SCE&G | Common collective trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investment, Fair Value Disclosure	$ 458	$ 418
SCE&G | Joint venture interests [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investment, Fair Value Disclosure	84	79
SCE&G | Alternative investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investment, Fair Value Disclosure	781	733
SCE&G | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	239	236
SCE&G | Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	110	115
SCE&G | Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	16	15
SCE&G | Fair Value, Inputs, Level 2 [Member] | Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	14	17
SCE&G | Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	84	76
SCE&G | Fair Value, Inputs, Level 2 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 15	$ 13

EMPLOYEE BENEFIT PLANS EMPLOY63

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 4) $ in Millions	Dec. 31, 2017USD ($)
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	$ 66.9
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	64.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	63.9
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	66.5
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	72
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	303
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	13.8
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	14.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	15.4
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	16
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	16.5
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	87.3
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	66.9
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	64.6
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	63.9
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	66.5
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	72
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	303
SCE&G | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	11
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	11.7
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	12.3
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	12.8
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	13.1
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	$ 69.6

EMPLOYEE BENEFIT PLANS EMPLOY64

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		$ 0	$ 0	$ 0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		$ 0	1	0
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%
Defined Contribution Plan, Maximum Percentage of Employer Contribution for up to Six Percent of Participant Contribution		100.00%
Defined Contribution Plan, Maximum Percentage of Participant Contribution Eligible for Employer Contribution Match		6.00%
Defined Contribution Plan, Cost		$ 27.9	27.5	26.2
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		(1)	0.6	2.7
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		(0.6)	(0.6)	(0.4)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax		0	(0.1)	(0.1)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		(1.6)	(0.1)	2.2
Defined Benefit Plan, Service Cost		21.7	20.7	24.1
Defined Benefit Plan, Interest Cost		37.4	39.4	38.2
Defined Benefit Plan, Expected Return (Loss) on Plan Assets		(54.7)	(55.9)	(62)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		1.6	3.9	4.1
Defined Benefit Plan, Amortization of Gain (Loss)		16.3	14.8	13.6
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 22.3	$ 22.9	$ 18
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.22%	4.68%	4.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.25%	7.50%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		$ 1.1	$ 0.8	$ (1.2)
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		(0.1)	0	(0.1)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax		0	0	(0.1)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		1	0.8	(1.4)
Defined Benefit Plan, Service Cost		4.5	4.4	5.3
Defined Benefit Plan, Interest Cost		11.5	12.1	11.4
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0	0.3	0.4
Defined Benefit Plan, Amortization of Gain (Loss)		1	0.5	2.1
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 17	$ 17.3	$ 19.2
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.30%	4.78%	4.30%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year		6.60%	7.00%	7.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		$ 0		$ 0	$ 0
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		$ 0		0	$ 0
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%
Defined Contribution Plan, Maximum Percentage of Employer Contribution for up to Six Percent of Participant Contribution		100.00%
Defined Contribution Plan, Maximum Percentage of Participant Contribution Eligible for Employer Contribution Match		6.00%
Defined Contribution Plan, Cost		$ 23.4	$ 22.9	21.8
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		0.3	0	0.2
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		(0.1)	(0.1)	(0.1)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax		0	0	(0.1)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		0.2	(0.1)	0
Defined Benefit Plan, Service Cost		18.1	16.9	19.3
Defined Benefit Plan, Interest Cost		31.9	33.4	32.2
Defined Benefit Plan, Expected Return (Loss) on Plan Assets		(46.7)	(47.4)	(52.2)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		1.4	3.4	3.4
Defined Benefit Plan, Amortization of Gain (Loss)		13.9	12.5	11.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 18.6	$ 18.8	$ 14.1
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.22%	4.68%	4.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		7.25%	7.50%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
SCE&G | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax		$ 0.5	$ 0.3	$ (0.3)
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		0	0	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax		0	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		0.5	0.3	(0.3)
Defined Benefit Plan, Service Cost		3.7	3.6	4.4
Defined Benefit Plan, Interest Cost		9.5	9.9	9.4
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0	0.3	0.3
Defined Benefit Plan, Amortization of Gain (Loss)		0.8	0.4	1.7
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 14	$ 14.2	$ 15.8
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.30%	4.78%	4.30%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year		6.60%	7.00%	7.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
Scenario, Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	7.00%
Scenario, Forecast [Member] | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Amortization of Net Gains (Losses)	$ 0.5
Defined benefit plan, future amortization of gain or loss from regulatory assets	10.2
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	0.4
Defined benefit plan, amount to be amortized from regulatory assets next year	10.6
Scenario, Forecast [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Amortization of Net Gains (Losses)	0.1
Defined benefit plan, future amortization of gain or loss from regulatory assets	1.8
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	0
Defined benefit plan, amount to be amortized from regulatory assets next year	$ 1.8
Scenario, Forecast [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	7.00%
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	insignificant
Scenario, Forecast [Member] | SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, future amortization of gain or loss from regulatory assets	$ 9
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	0.4
Defined benefit plan, amount to be amortized from regulatory assets next year	9.4
Scenario, Forecast [Member] | SCE&G | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, future amortization of gain or loss from regulatory assets	1.5
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	0
Defined benefit plan, amount to be amortized from regulatory assets next year	$ 1.5

SHARE-BASED COMPENSATION (Detai

SHARE-BASED COMPENSATION (Details)	Dec. 31, 2017shares
Share-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	5,000,000
Restricted Stock Units
Share-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	1,000,000

SHARE-BASED COMPENSATION Liabil

SHARE-BASED COMPENSATION Liability Awards (Details) - USD ($)	Feb. 28, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Liability Awards
Cash-Settled Liabilities		$ 28	$ 18.4	$ 20.8
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 5.4
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		18 months
Compensation Expenses Recognized Resulting From Fair Value Adjustments of Performance Awards		$ (9)	25.6	18
Capitalized Compensation Expense		$ (1.3)	3.3	2.3
Performance Shares [Member]
Liability Awards
Weight of Entity's Performance Against Pre-Determined Measures of Total Stockholder Return As Compared to Peer Groups of Utilities to Determine Payout of Performance Shares as a Percentage		50.00%
Weight of Growth in GAAP-adjusted net earnings per share from operations to determine payout of performance shares as a percent		50.00%
SCE&G
Liability Awards
Cash-Settled Liabilities		$ 20.2	13.2	6.3
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		4.1
Compensation Expenses Recognized Resulting From Fair Value Adjustments of Performance Awards		(6.3)	17.3	12.2
Capitalized Compensation Expense		$ (0.9)	$ 3.1	$ 0.6
SCE&G | Restricted Stock Units
Liability Awards
Performance Cycle (in years)		3 years
Percentage of Performance Award Granted in Form of Restricted Stock Units (as a percent)		30.00%
SCE&G | Performance Shares [Member]
Liability Awards
Percentage of Performance Award Granted in Form of Performance Shares (as a percent)		70.00%
Weight of Entity's Performance Against Pre-Determined Measures of Total Stockholder Return As Compared to Peer Groups of Utilities to Determine Payout of Performance Shares as a Percentage		50.00%
Weight of Growth in GAAP-adjusted net earnings per share from operations to determine payout of performance shares as a percent		50.00%
Subsequent Event [Member] | Restricted Stock Units
Liability Awards
Percentage of Performance Award Granted in Form of Restricted Stock Units (as a percent)	30.00%
Subsequent Event [Member] | Performance Shares [Member]
Liability Awards
Percentage of Performance Award Granted in Form of Performance Shares (as a percent)	70.00%
Subsequent Event [Member] | SCE&G | Restricted Stock Units
Liability Awards
Percentage of Performance Award Granted in Form of Restricted Stock Units (as a percent)	30.00%
Subsequent Event [Member] | SCE&G | Performance Shares [Member]
Liability Awards
Percentage of Performance Award Granted in Form of Performance Shares (as a percent)	70.00%

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Details)	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Commitments and contingencies
Operating Leases, Rent Expense	$ 10	$ 10.2	$ 11.1
Operating Leases, Future Minimum Payments Due, Next Twelve Months	34,000,000
Operating Leases, Future Minimum Payments, Due in Two Years	30,000,000
Operating Leases, Future Minimum Payments, Due in Three Years	6,000,000
Operating Leases, Future Minimum Payments, Due in Four Years	6,000,000
Operating Leases, Future Minimum Payments, Due in Five Years	5,000,000
Operating Leases, Future Minimum Payments, Due Thereafter	31,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	1,800,000,000
Asset Retirement Obligation Other Conditional Obligations	360,000,000
Asset Retirement Obligation	568,000,000	558,000,000	520,000,000
Asset Retirement Obligation, Liabilities Incurred	0	0
Asset Retirement Obligation, Liabilities Settled	(10,000,000)	(11,000,000)
Asset Retirement Obligation, Accretion Expense	25,000,000	23,000,000
Asset Retirement Obligation, Revision of Estimate	$ (5,000,000)	26,000,000
Environmental
Emission Rate Standard For Coal Fired Power Plants Under Clean Air Act	1,400
Emission Rate Standard for Natural Gas	1,000
Goal For Reduced Carbon Dioxide Emissions From 2005 Levels By 2030 Under Clean Air Act	32.00%
Number of States affected by CSAPR	28
SCE&G
Commitments and contingencies
Operating Leases, Rent Expense	$ 11.4	12.2	12.3
Operating Leases, Future Minimum Payments Due, Next Twelve Months	26,000,000
Operating Leases, Future Minimum Payments, Due in Two Years	23,000,000
Operating Leases, Future Minimum Payments, Due in Three Years	1,000,000
Operating Leases, Future Minimum Payments, Due in Four Years	1,000,000
Operating Leases, Future Minimum Payments, Due in Five Years	0
Operating Leases, Future Minimum Payments, Due Thereafter	17,000,000
Asset Retirement Obligation Other Conditional Obligations	321,000,000
Asset Retirement Obligation	529,000,000	522,000,000	$ 488,000,000
Asset Retirement Obligation, Liabilities Incurred	0	0
Asset Retirement Obligation, Liabilities Settled	(9,000,000)	(11,000,000)
Asset Retirement Obligation, Accretion Expense	23,000,000	22,000,000
Asset Retirement Obligation, Revision of Estimate	(7,000,000)	$ 23,000,000
Nuclear Insurance
scg_Maximum Insurance Coverage for each Nuclear Plant by ANI	450,000,000
Federal Limit on Public Liability Claims from Nuclear Incident Approximate	13,400,000,000
Maximum liability assessment per reactor for each nuclear incident	127,300,000
Maximum yearly assessment per reactor	18,900,000
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3	84,800,000
Maximum Insurance Coverage for Nuclear events	2,750,000,000
NEIL Maximum Insurance Coverage To Nuclear Facility For Property Damage And Outage Costs From Non-Nuclear Event	2,330,000,000
Maximum prosepective insurance premium per nuclear incident	22,300,000
Maximum amount of coverage to nuclear facility for property damage and outage costs	2,750,000,000
EMANI Maximum Insurance Coverage for Summer Station Unit 1 For Property Damage And Outage Costs From Non-Nuclear Event	415,000,000
EMANI Maximum Retrospective Premium Assessment	2,000,000
Environmental
Environmental Remediation Expense	9,900,000
Deferred costs, net of costs previously recovered through rates and insurance settlements included in regulatory assets	24,600,000
Nuclear Generation
Asset Retirement Obligation Nuclear Decommissioning	208,000,000
SCE&G | SCE&G
Nuclear Insurance
Maximum yearly assessment per reactor	$ 12,600,000

COMMITMENTS AND CONTINGENCIES N

COMMITMENTS AND CONTINGENCIES Nuclear (Details) - USD ($)	3 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Utilities Operating Expense, Impairments	$ 210,000,000		$ 1,118,000,000
Utilities Operating Loss, Impairment, Net of Taxes			690,000,000
Project Costs, Excluding Transmission Costs			1,200,000,000
Disallowance of Costs			670,000,000
Nuclear Production Tax Credits			1.4
Guaranty Fee Income			2,200,000,000
Other Receivables, Gross, Current			1,016,000,000
EPC Amendment, Fixed Price Option, Price for subcontractor and other supplier-related costs subject to Dec 2016 DRB order			6,082,000,000
Estimate of aggregate amount of subcontractor and vendor liens filed			60,000,000
Regulatory Request to Lower Revenues			445,000,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances			1,900,000,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery			0.035
Customer Refundable Fees, Refund Payments			$ 1,300,000,000
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%
Costs Not to Be Recovered Under Merger Agreement			$ 1,700,000,000
Settlement Proceeds			1,000,000,000
Property, Plant and Equipment, Additions			180,000,000
Remaining Impairment Loss Recorded			280,000,000
Remaining Impairment Loss			1,700,000,000
Remaining Impairment Costs, Regulatory Assets, Post Merger			856,000,000
Impairment Cost, Additional Liabilities, Post Merger			1,875,000,000
Monetization Settlement less Contractor Lien Settlements			1,062,000,000
Monetization Settlement Exceeding Costs Incurred			1,095,000,000
Long-term Debt, Current Maturities			727,000,000	$ 17,000,000
Impairment Loss Related to Amounts Previously Deferred in Regulatory Assets			(361,000,000)
Impairment of Nuclear Fuel			87,000,000
Future Operating Impairment Loss			4,800,000,000
Additional Impairment, Joint Petition not Approved			3,976,000,000
Additional Impairment Related to Revised Rates			1,900,000,000
Short-term borrowings			350,000,000	$ 941,000,000
Less Nuclear Project and switchyard assets transferred for use by Unit 1			84,000,000
Debt Instrument, Periodic Payment, Interest			335,000,000
Operating Leases, Future Minimum Payments Due			34,000,000
Long-term Line of Credit			1,800,000,000
Summer Station New Units [Domain]
Other Receivables, Gross, Current			1,847,000,000
SCE&G
Utilities Operating Expense, Impairments			1,118,000,000
Guaranty Fee Income			1,200,000,000
EPC Amendment, Fixed Price Option, Price for subcontractor and other supplier-related costs subject to Dec 2016 DRB order			3.345
Total New Nuclear Project Cost Approved By SCPSC In September 2015			6,800,000,000
EPC Contract Amendment, Total New Nuclear Project Cost Including Amendment Increase			$ 7,700,000,000
Public Utilities, Authorized Allowable Return on Common Equity, Percentage			10.50%	10.50%	11.00%
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015			$ 831,000,000
Estimate of aggregate amount of subcontractor and vendor liens filed			33,000,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances				$ 61,000,000
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery			61,000,000
Long-term Debt, Current Maturities			723,000,000	12,000,000
Short-term borrowings			252,000,000	$ 804,000,000
Debt Instrument, Periodic Payment, Interest			259,000,000
Operating Leases, Future Minimum Payments Due			26,000,000
Long-term Line of Credit			1,200,000,000
Summer Station New Units and Transmission Assets [Domain]
Guaranty Assets			$ 150,000,000
Summer Station New Units [Domain]
Jointly Owned Utility Plant, Proportionate Ownership Share			55.00%	55.00%
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress				$ 4,200,000,000
jointly owned utility plant ownership, construction financing cost			$ 3,500,000,000
SCE&G
Guaranty Assets			$ 82,500,000
Scenario, Forecast [Member] | SCE&G
Public Utilities, Authorized Allowable Return on Common Equity, Percentage		10.25%

AFFILIATED TRANSACTIONS - SCEG

AFFILIATED TRANSACTIONS - SCEG (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Affiliated Transaction [Line Items]
Proceeds from Equity Method Investment, Distribution	$ 2.8	$ 3.7	$ 4
Equity Method Investments	4.6	5.5	4.1
Canadys Refined Coal [Member]
Affiliated Transaction [Line Items]
Related Party Transaction Purchases from Related Party	162.1	161.8	233.2
Due to Related Parties	4.9	16.1
Sales to Affiliate	$ 161.1	160.8	232
Equity Method Investment, Ownership Percentage	40.00%
Related Party Tax Expense, Due from Affiliates, Current	$ 4.9	16
SCE&G
Affiliated Transaction [Line Items]
Due to Related Parties	37	29
Due to Affiliate, Current	102	122
Due from Affiliate, Current	32	16
Accounts Payable, Related Parties, Current	42	63.5
Related Party Tax Expense, Due to Affiliates, Current	10	8.8
CGT [Member]
Affiliated Transaction [Line Items]
Related Party Transaction Purchases from Related Party			3.4
Retail Gas and Energy Marketing Segment [Member]
Affiliated Transaction [Line Items]
Cost of Natural Gas Purchases	127.4	111.5	128.5
SCANA Services [Member]
Affiliated Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 302.8	$ 337.7	$ 300

SEGMENT OF BUSINESS INFORMATI70

SEGMENT OF BUSINESS INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Gain (Loss) On Disposition Of Regulated Business Net Of Transaction Costs											$ 234
Total	$ 18,739				$ 18,707				$ 18,739	$ 18,707	17,146
Additions to Other Assets, Amount									1,225	1,579	1,153
Deferred Tax Assets, Gross	0				0				0	0	0
Electric Domestic Regulated Revenue									2,659	2,614	2,551
Regulated and Unregulated Operating Revenue	1,157	$ 1,076	$ 1,001	$ 1,173	1,057	$ 1,093	$ 905	$ 1,172	4,407	4,227	4,380
Intersegment Revenue									0	0	0
Operating Income	(609)	120	249	316	253	348	221	331	76	1,153	1,308
Interest Expense									363	342	318
Depreciation, Depletion and Amortization									382	371	358
Income Tax Expense (Benefit)									(112)	271	393
Income Available to Common Shareholders	(445)	34	121	171	125	189	105	176	(119)	595	746
Regulated Operating Revenue, Gas									874	788	811
Electric Operations
Segment Reporting Information [Line Items]
Total	11,979				11,929				11,979	11,929	10,883
Additions to Other Assets, Amount									207	1,275	1,087
Deferred Tax Assets, Gross	(6)				(9)				(6)	(9)	(5)
Electric Domestic Regulated Revenue									2,659
Intersegment Revenue									5	5	6
Operating Income									(161)	957	876
Interest Expense									19	17	17
Depreciation, Depletion and Amortization									295	287	277
Income Tax Expense (Benefit)									8	8	9
Gas Distribution
Segment Reporting Information [Line Items]
Total	3,259				2,892				3,259	2,892	2,606
Additions to Other Assets, Amount									417	276	203
Deferred Tax Assets, Gross	(25)				(32)				(25)	(32)	(29)
Regulated and Unregulated Operating Revenue									874	788	810
Intersegment Revenue									2	2	2
Operating Income									186	148	152
Interest Expense									28	25	23
Depreciation, Depletion and Amortization									85	82	77
Income Tax Expense (Benefit)									41	32	32
Gas Marketing [Member]
Segment Reporting Information [Line Items]
Total	230				230				230	230	201
Additions to Other Assets, Amount									2	2	2
Deferred Tax Assets, Gross	(9)				(11)				(9)	(11)	(15)
Regulated and Unregulated Operating Revenue									874	825	1,018
Intersegment Revenue									127	111	128
Interest Expense									1	1	1
Depreciation, Depletion and Amortization									2	2	2
Income Tax Expense (Benefit)									25	19	18
Income Available to Common Shareholders									27	30	28
All Other [member]
Segment Reporting Information [Line Items]
Total	1,042				1,124				1,042	1,124	998
Additions to Other Assets, Amount									7	11	15
Deferred Tax Assets, Gross	0				0				0	0	0
Regulated and Unregulated Operating Revenue									0	0	5
Intersegment Revenue									389	414	413
Operating Income									0	0	236
Interest Expense									0	0	1
Depreciation, Depletion and Amortization									16	16	16
Income Tax Expense (Benefit)									(7)	0	1
Income Available to Common Shareholders									(46)	(18)	185
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Total	2,229				2,532				2,229	2,532	2,458
Additions to Other Assets, Amount									592	15	(154)
Deferred Tax Assets, Gross	40				52				40	52	49
Regulated and Unregulated Operating Revenue									0	0	(4)
Intersegment Revenue									(523)	(532)	(549)
Operating Income									51	48	44
Interest Expense									315	299	276
Depreciation, Depletion and Amortization									(16)	(16)	(14)
Income Tax Expense (Benefit)									(179)	212	333
Income Available to Common Shareholders									(100)	583	533
SCE&G
Segment Reporting Information [Line Items]
Total	15,946				16,091				15,946	16,091	14,765
Additions to Other Assets, Amount									928	1,399	1,008
Deferred Tax Assets, Gross	0				0				0	0	0
Regulated Operating Revenue	739	856	756	719	695	882	692	717	3,070	2,986	2,930
Operating Income	(681)	$ 123	$ 246	$ 222	196	$ 359	$ 222	$ 236	(90)	1,013	934
Interest Expense									288	270	248
Depreciation, Depletion and Amortization									312	302	294
Income Tax Expense (Benefit)									(171)	248	231
SCE&G | Electric Operations
Segment Reporting Information [Line Items]
Total	11,979								11,979		10,883
Additions to Other Assets, Amount									207		1,087
Deferred Tax Assets, Gross	(6)								(6)		(5)
Operating Income									(161)		876
Interest Expense									19	17	17
Depreciation, Depletion and Amortization									295	287	277
SCE&G | Gas Distribution
Segment Reporting Information [Line Items]
Total	869				825				869	825	757
Additions to Other Assets, Amount									65	78	57
Regulated and Unregulated Operating Revenue									406	367	373
Operating Income									71	56	58
Depreciation, Depletion and Amortization									30	28	28
SCE&G | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Total	3,098				3,337				3,098	3,337	3,125
Additions to Other Assets, Amount									656	46	(136)
Deferred Tax Assets, Gross	$ 6				$ 9				6	9	5
Operating Income											0
Interest Expense									269	253	231
Depreciation, Depletion and Amortization									(13)	(13)	(11)
External revenue [Member] | SCE&G
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue									$ 2,664	$ 2,619	$ 2,557

DISPOSITIONS (Details)

DISPOSITIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016
Public Utilities, Property, Plant and Equipment, Net		$ 10,648	$ 14,324
Nonutility Property and Investments, Net		474	475
Assets, Current		1,851	1,506
Regulated Entity, Other Assets, Noncurrent		5,766	2,402
Liabilities, Current		2,113	2,065
Liabilities, Noncurrent		$ 5,465	$ 4,444
Pre-tax gain on sale of CGT and SCI	$ 342

OTHER INCOME (EXPENSE), NET (De

OTHER INCOME (EXPENSE), NET (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other income	$ 79	$ 64	$ 75
Other Nonoperating Expense	(46)	(38)	(60)
Public Utilities, Allowance for Funds Used During Construction, Additions	23	29	27
Nonoperating Income (Expense)	56	55	42
SCE&G
Other income	45	29	31
Other Nonoperating Expense	(25)	(24)	(31)
Public Utilities, Allowance for Funds Used During Construction, Additions	15	26	25
Nonoperating Income (Expense)	$ 35	$ 31	$ 25

QUARTERLY FINANCIAL INFORMATI73

QUARTERLY FINANCIAL INFORMATION (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Regulated and Unregulated Operating Revenue	$ 1,157	$ 1,076	$ 1,001	$ 1,173	$ 1,057	$ 1,093	$ 905	$ 1,172	$ 4,407	$ 4,227	$ 4,380
Operating Income (Loss)	(609)	120	249	316	253	348	221	331	76	1,153	1,308
Income Available to Common Shareholders	$ (445)	$ 34	$ 121	$ 171	$ 125	$ 189	$ 105	$ 176	$ (119)	$ 595	$ 746
Earnings Per Share, Basic and Diluted	$ (3.11)	$ 0.24	$ 0.85	$ 1.19	$ 0.87	$ 1.32	$ 0.74	$ 1.23	$ (0.83)	$ 4.16	$ 5.22
SCE&G
Regulated Operating Revenue	$ 739	$ 856	$ 756	$ 719	$ 695	$ 882	$ 692	$ 717	$ 3,070	$ 2,986	$ 2,930
Operating Income (Loss)	(681)	123	246	222	196	359	222	236	(90)	1,013	934
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(452)	42	126	112	93	204	113	116	(172)	526	480
Net Income (Loss) Attributable to Parent	$ (456)	$ 39	$ 123	$ 109	$ 89	$ 201	$ 110	$ 113	$ (185)	$ 513	$ 466

SUBSEQUENT EVENT (Details)

SUBSEQUENT EVENT (Details) $ in Billions	Jan. 02, 2018USD ($)shares
Subsequent Event [Line Items]
Common Stock for Common Stock | shares	0.6690
Value of Merger Transaction | $	$ 14.6

Schedule II (Details)

Schedule II (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	$ 6	$ 6	$ 5	$ 7
Valuation Allowances and Reserves, Charged to Cost and Expense	13	12	12
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	13	11	14
General Liability [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	9	9	6	5
Valuation Allowances and Reserves, Charged to Cost and Expense	8	5	11
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	8	2	10
SCE&G | Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	4	3	3	4
Valuation Allowances and Reserves, Charged to Cost and Expense	8	6	6
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	7	6	7
SCE&G | General Liability [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	8	8	5	$ 3
Valuation Allowances and Reserves, Charged to Cost and Expense	8	5	11
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	$ 8	$ 2	$ 9