Dominion Energy South Carolina (SCG) 10-K 24 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 20, 2017	Jun. 30, 2016
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, 2016
Document Fiscal Year Focus	2,016
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		142,916,917
Entity Public Float			$ 10,771,377,513
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, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,296,147

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Assets
Utility Plant In Service	$ 13,444,000,000	$ 12,883,000,000
Accumulated Depreciation and Amortization	(4,446,000,000)	(4,307,000,000)
Construction Work in Progress	4,845,000,000	4,051,000,000
Nuclear Fuel, Net of Accumulated Amortization	271,000,000	308,000,000
Goodwill, Net of Writedown of $230	210,000,000	210,000,000
Utility Plant, Net	14,324,000,000	13,145,000,000
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	276,000,000	280,000,000
Assets held in trust, net-nuclear decommissioning	123,000,000	115,000,000
Other investments	76,000,000	71,000,000
Nonutility Property and Investments, Net	475,000,000	466,000,000
Current Assets:
Cash and cash equivalents	208,000,000	176,000,000
Receivables, net of allowance for uncollectible accounts	616,000,000	505,000,000
Income taxes	142,000,000	0
Accounts and Other Receivables, Net, Current	127,000,000	227,000,000
Inventories (at average cost):
Fuel	136,000,000	164,000,000
Materials and supplies	155,000,000	148,000,000
Prepaid Expense	105,000,000	115,000,000
Other Assets, Current	17,000,000	43,000,000
Total Current Assets	1,506,000,000	1,378,000,000
Deferred Debits and Other Assets:
Regulatory assets	2,130,000,000	1,937,000,000
Other	272,000,000	220,000,000
Regulated Entity, Other Assets, Noncurrent	2,402,000,000	2,157,000,000
Total	18,707,000,000	17,146,000,000
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,390,000,000	2,390,000,000
Retained Earnings, Unappropriated	3,384,000,000	3,118,000,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	(49,000,000)	(65,000,000)
Common equity	5,725,000,000	5,443,000,000
Long-term Debt, Excluding Current Maturities	6,473,000,000	5,882,000,000
Total Capitalization	12,198,000,000	11,325,000,000
Current Liabilities:
Short-term borrowings	941,000,000	531,000,000
Long-term Debt, Current Maturities	17,000,000	116,000,000
Accounts payable	404,000,000	590,000,000
Customer deposits and customer prepayments	168,000,000	137,000,000
Taxes accrued	201,000,000	242,000,000
Interest accrued	84,000,000	83,000,000
Dividends declared	80,000,000	76,000,000
Derivative financial instruments	35,000,000	50,000,000
Other	135,000,000	127,000,000
Total Current Liabilities	2,065,000,000	1,952,000,000
Deferred Credits and Other Liabilities:
Deferred income taxes, net	2,159,000,000	1,907,000,000
Asset retirement obligations	558,000,000	520,000,000
Pension and other postretirement benefits	373,000,000	315,000,000
Unrecognized tax benefits	219,000,000	44,000,000
Regulatory liabilities	930,000,000	855,000,000
Other	205,000,000	228,000,000
Total Deferred Credits and Other Liabilities	4,444,000,000	3,869,000,000
Commitments and Contingencies (Note 10)	0	0
Total	18,707,000,000	17,146,000,000
SCE&G
Assets
Utility Plant In Service	11,510,000,000	11,153,000,000
Accumulated Depreciation and Amortization	(3,991,000,000)	(3,869,000,000)
Construction Work in Progress	4,813,000,000	3,997,000,000
Nuclear Fuel, Net of Accumulated Amortization	271,000,000	308,000,000
Utility Plant, Net	12,603,000,000	11,589,000,000
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	69,000,000	68,000,000
Assets held in trust, net-nuclear decommissioning	123,000,000	115,000,000
Other investments	3,000,000	1,000,000
Nonutility Property and Investments, Net	195,000,000	184,000,000
Current Assets:
Cash and cash equivalents	164,000,000	130,000,000
Receivables, net of allowance for uncollectible accounts	378,000,000	324,000,000
Income taxes	53,000,000
Due from Affiliate, Current	16,000,000	22,000,000
Accounts and Other Receivables, Net, Current	94,000,000	202,000,000
Inventories (at average cost):
Fuel	83,000,000	98,000,000
Materials and supplies	143,000,000	136,000,000
Prepayments	88,000,000	92,000,000
Other Assets, Current	1,000,000	15,000,000
Total Current Assets	1,020,000,000	1,019,000,000
Deferred Debits and Other Assets:
Regulatory assets	2,030,000,000	1,857,000,000
Other	243,000,000	116,000,000
Regulated Entity, Other Assets, Noncurrent	2,273,000,000	1,973,000,000
Total	16,091,000,000	14,765,000,000
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,860,000,000	2,760,000,000
Retained Earnings, Unappropriated	2,481,000,000	2,265,000,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3,000,000)	(3,000,000)
Common equity	5,338,000,000	5,022,000,000
Stockholders' Equity Attributable to Noncontrolling Interest	134,000,000	129,000,000
Total Equity	5,472,000,000	5,151,000,000
Long-term Debt, Excluding Current Maturities	5,154,000,000	4,659,000,000
Total Capitalization	10,626,000,000	9,810,000,000
Current Liabilities:
Short-term borrowings	804,000,000	420,000,000
Long-term Debt, Current Maturities	12,000,000	110,000,000
Accounts payable	247,000,000	469,000,000
Due to Affiliate, Current	122,000,000	113,000,000
Customer deposits and customer prepayments	126,000,000	93,000,000
Taxes accrued	195,000,000	299,000,000
Interest accrued	68,000,000	66,000,000
Dividends declared	79,000,000	75,000,000
Derivative financial instruments	28,000,000	34,000,000
Other	55,000,000	61,000,000
Total Current Liabilities	1,736,000,000	1,740,000,000
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,939,000,000	1,732,000,000
Asset retirement obligations	522,000,000	488,000,000
Pension and other postretirement benefits	232,000,000	186,000,000
Unrecognized tax benefits	236,000,000	44,000,000
Regulatory liabilities	695,000,000	635,000,000
Other	89,000,000	113,000,000
Due to Affiliate, Noncurrent	16,000,000	17,000,000
Total Deferred Credits and Other Liabilities	3,729,000,000	3,215,000,000
Commitments and Contingencies (Note 10)	0	0
Total	$ 16,091,000,000	$ 14,765,000,000

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Public Utilities, Property, Plant and Equipment, Net	$ 14,324	$ 13,145
Regulated Entity, Other Assets, Noncurrent	2,402	2,157
Nonutility property, accumulated depreciation	138	124
Receivables, net of allowance for uncollectible accounts	6	5
Assets, Current	$ 1,506	$ 1,378
Common Stock, Shares, Outstanding	142.9	142.9
SCE&G
Public Utilities, Property, Plant and Equipment, Net	$ 12,603	$ 11,589
Regulated Entity, Other Assets, Noncurrent	2,273	1,973
Receivables, net of allowance for uncollectible accounts	3	3
Assets, Current	$ 1,020	$ 1,019
Common Stock, Shares, Outstanding	40.3	40.3
VIEs | SCE&G
Public Utilities, Property, Plant and Equipment, Net	$ 756	$ 700
Regulated Entity, Other Assets, Noncurrent	52	53
Assets, Current	$ 85	$ 88

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Revenues:
Electric Domestic Regulated Revenue	$ 2,614	$ 2,551	$ 2,622
Regulated Operating Revenue, Gas	788	811	1,028
Gas-nonregulated	825	1,018	1,301
Regulated and Unregulated Operating Revenue	4,227	4,380	4,951
Operating Expenses [Abstract]
Fuel used in electric generation	576	660	793
Purchased power	64	52	81
Gas purchased for resale	1,054	1,287	1,729
Other operation and maintenance	755	715	728
Depreciation and amortization	371	358	384
Other taxes	254	234	229
Total Operating Expenses	3,074	3,306	3,944
Gain (Loss) On Disposition Of Regulated Business Net Of Transaction Costs		234
Operating Income	1,153	1,308	1,007
Other Income (Expense):
Other income	64	75	122
Other expenses	(38)	(60)	(64)
Gain (Loss) On Disposition Of Unregulated Business Net Of Transaction Costs		107
Interest charges, net of allowance for borrowed funds used during construction	(342)	(318)	(312)
Allowance for equity funds used during construction	29	27	33
Total Other Expense	(287)	(169)	(221)
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	866	1,139	786
Income Tax Expense (Benefit)	271	393	248
Income Available to Common Shareholders	$ 595	$ 746	$ 538
Earnings Per Share, Basic and Diluted	$ 4.16	$ 5.22	$ 3.79
Dividends Common Stock Declared	$ 329	$ 312	$ 298
Weighted Average Common Shares Outstanding (millions)
Weighted Average Number of Shares Outstanding, Basic	142.9	142.9	141.9
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 2.30	$ 2.18	$ 2.10
SCE&G
Operating Revenues:
Electric Domestic Regulated Revenue	$ 2,614	$ 2,551	$ 2,621
Regulated Operating Revenue, Gas	366	372	461
Regulated Operating Revenue	2,986	2,930	3,091
Operating Expenses [Abstract]
Fuel used in electric generation	472	559	644
Purchased power	64	52	81
Gas purchased for resale	174	162	210
Other operation and maintenance	403	380	382
Depreciation and amortization	302	294	315
Other taxes	227	211	202
Total Operating Expenses	1,973	1,996	2,261
Operating Income	1,013	934	830
Other Income (Expense):
Other income	29	31	80
Other expenses	(24)	(31)	(34)
Interest charges, net of allowance for borrowed funds used during construction	(270)	(248)	(228)
Allowance for equity funds used during construction	26	25	28
Total Other Expense	(239)	(223)	(154)
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	774	711	676
Income Tax Expense (Benefit)	248	231	218
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	526	480	458
Net Income (Loss) Attributable to Noncontrolling Interest	13	14	12
Earnings Available to Common Shareholder	513	466	446
Dividends Common Stock Declared	305	285	272
Affiliated Entity [Member] | SCE&G
Operating Revenues:
Electric Domestic Regulated Revenue	5	6	8
Regulated Operating Revenue, Gas	1	1	1
Operating Expenses [Abstract]
Fuel used in electric generation	104	102	155
Gas purchased for resale	9	31	73
Other operation and maintenance	211	199	193
Other taxes	$ 7	$ 6	$ 6

CONSOLIDATED STATEMENTS OF INC5

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Interest charges, allowance for borrowed funds used during construction	$ 19	$ 15	$ 16
SCE&G
Interest charges, allowance for borrowed funds used during construction	$ 18	$ 14	$ 14

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Available to Common Shareholders	$ 595	$ 746	$ 538
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Net of Tax	4	(12)	(14)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	17	10	11
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax	0	0	(5)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax	(1)	0	1
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	(1)	0	(4)
Other Comprehensive Income (Loss), Net of Tax	16	10	(15)
Net Income (Loss) Attributable to Parent [Abstract]
Total Comprehensive Income (Loss)	611	756	523
SCE&G
Other Comprehensive Income (Loss), Net of Tax		0	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	526	480	458
Other Comprehensive Income (Loss)
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax	0	0	0
Less comprehensive income attributable to noncontrolling interest	13	14	12
Net Income (Loss) Attributable to Parent [Abstract]
Total Comprehensive Income (Loss)	526	480	458
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	526	480	458
SCEG excluding VIEs [Member]
Income Available to Common Shareholders	513	466	446
Net Income (Loss) Attributable to Parent [Abstract]
Total Comprehensive Income (Loss)	513	466	446
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	$ 6	$ 15	$ (4)

CONSOLIDATED STATEMENTS OF COM7

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ 2	$ (7)	$ (9)
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	9	(2)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	$ 0	$ 0	$ (3)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flows from Operating Activities
Net Income (Loss) Available to Common Stockholders, Basic	$ 595	$ 746	$ 538
Adjustments to reconcile net income to net cash provided from operating activities:
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		(355)
Deferred income taxes, net	242	(31)	235
Depreciation and amortization	389	368	403
Amortization of nuclear fuel	57	46	45
Allowance for equity funds used during construction	(29)	(27)	(33)
Carrying cost recovery	(17)	(12)	(9)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	112	(188)	33
Increase (Decrease) in Income Taxes Receivable	(142)
Increase (Decrease) in Inventories	43	16	62
Increase (Decrease) in Prepaid Expense	(11)	(211)	235
Increase (Decrease) in Other Regulatory Assets	114	31	138
Increase (Decrease) in Regulatory liabilities	(2)	(1)	(104)
Increase (Decrease) in Accounts Payable	44	(78)	36
Unrecognized tax benefits, increase (decrease)	175	31	10
Increase (Decrease) in Taxes accrued	(41)	61	(24)
Increase (Decrease) in Pension and Postretirement Obligations	51	(6)	133
Increase (Decrease) in Derivative Assets and Liabilities	(9)	(9)	18
Changes in other assets	44	3	35
Changes in other liabilities	81	(23)	(15)
Net Cash Provided from Operating Activities	1,092	1,059	730
Cash Flows From Investing Activities
Property additions and construction expenditures	(1,579)	(1,153)	(1,092)
Proceeds from Sale of Property, Plant, and Equipment		647
Proceeds from investments (including derivative collateral posted)	860	1,117	347
Purchase of investments (including derivative collateral posted)	(788)	(1,018)	(475)
Payments upon interest rate contract settlement	(113)	(263)	(95)
Payments for (Proceeds from) Hedge, Investing Activities	0	10
Net Cash Used for Investing Activities	(1,620)	(660)	(1,315)
Cash Flows from Financing Activities
Proceeds from Issuance of Common Stock	0	14	98
Proceeds from issuance of long-term debt	592	491	294
Repayments of Long-term Debt	(117)	(166)	(54)
Dividends	(325)	(309)	(294)
Short-term borrowings, net	410	(387)	542
Proceeds from (Payments for) Other Financing Activities	0	(3)
Net Cash Provided From Financing Activities	560	(360)	586
Net (Decrease) Increase in Cash and Cash Equivalents	32	39	1
Cash and Cash Equivalents, January 1	176	137	136
Cash and Cash Equivalents, December 31	208	176	137
Supplemental Cash Flow Information
Cash paid for-Interest (net of capitalized interest )	328	306	301
Cash paid for-Income taxes	229	184	299
Proceeds from Income Tax Refunds	166
Cash Flow, Noncash Investing and Financing Activities Disclosure
Accrued construction expenditures	109	244	180
Capital Lease Obligations Incurred	15	6	5
SCE&G
Cash Flows from Operating Activities
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	526	480	458
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income taxes, net	207	8	187
Depreciation and amortization	310	294	318
Amortization of nuclear fuel	57	46	45
Allowance for equity funds used during construction	(26)	(25)	(28)
Carrying cost recovery	(17)	(12)	(9)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	47	(85)	(51)
Increase (Decrease) in Due from Affiliates, Current	(3)	16	(90)
Increase (Decrease) in Income Taxes Receivable	(53)
Increase (Decrease) in Inventories	35	24	52
Increase (Decrease) in Prepaid Expense	4	(70)	89
Increase (Decrease) in Other Regulatory Assets	94	29	116
Increase (Decrease) in Regulatory liabilities	(5)	(3)	(103)
Increase (Decrease) in Accounts Payable	8	11	(49)
Unrecognized tax benefits, increase (decrease)	192	31	10
Increase (Decrease) in Due to Affiliates, Current	13	(17)	63
Increase (Decrease) in Taxes accrued	(104)	129	(53)
Increase (Decrease) in Pension and Postretirement Obligations	39	(5)	106
Changes in other assets	99	(57)	15
Changes in other liabilities	58	(28)	16
Increase (Decrease) in Due to Affiliates	(1)	(6)	(9)
Net Cash Provided from Operating Activities	922	1,078	641
Cash Flows From Investing Activities
Property additions and construction expenditures	(1,399)	(1,008)	(934)
Proceeds from investments (including derivative collateral posted)	794	975	275
Purchase of investments (including derivative collateral posted)	(740)	(887)	(381)
Payments upon interest rate contract settlement	(113)	(263)	(95)
Payments for (Proceeds from) Hedge, Investing Activities		10
Proceeds from Investment In Affiliate	9	71
Investment In Affiliate			(80)
Net Cash Used for Investing Activities	(1,449)	(1,102)	(1,215)
Cash Flows from Financing Activities
Proceeds from issuance of long-term debt	494	491	294
Repayments of Long-term Debt	(112)	(11)	(48)
Dividends	(301)	(285)	(260)
Short-term borrowings, net	384	(289)	458
Short-term borrowings-affiliate,net	(4)	(50)	56
Contributions from parent	100	204	89
Payment to Parent representing the return of Contribution Proceeds	0	(4)	(7)
Proceeds from (Payments for) Other Financing Activities	0	(2)
Net Cash Provided From Financing Activities	561	54	582
Net (Decrease) Increase in Cash and Cash Equivalents	34	30	8
Cash and Cash Equivalents, January 1	130	100	92
Cash and Cash Equivalents, December 31	164	130	100
Supplemental Cash Flow Information
Cash paid for-Interest (net of capitalized interest )	251	228	210
Cash paid for-Income taxes	289	89	177
Proceeds from Income Tax Refunds	189	84
Cash Flow, Noncash Investing and Financing Activities Disclosure
Accrued construction expenditures	95	230	151
Capital Lease Obligations Incurred	$ 14	$ 6	$ 5

CONSOLIDATED STATEMENTS OF CAS9

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parentheticals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash paid for interest, capitalized interest	$ 19	$ 15	$ 16
SCE&G
Cash paid for interest, capitalized interest	$ 18	$ 14	$ 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]
Common Stock, Value, Outstanding				$ 2,479
Stockholders' Equity Attributable to Noncontrolling Interest					$ 117
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			$ 4,489
Stockholders' Equity Attributable to Parent at Dec. 31, 2013	$ 4,664
Shares, Outstanding at Dec. 31, 2013	141			40
Stockholders' Equity before Treasury Stock at Dec. 31, 2013	$ 2,289
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2013	(52)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax at Dec. 31, 2013	(8)
Retained Earnings, Unappropriated at Dec. 31, 2013	2,444			$ 1,896
Treasury Stock, Value at Dec. 31, 2013	(9)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2013	$ (60)			(3)
Stock Issued During Period, Shares, New Issues	2
Stock Issued During Period, Value, Other	$ 99
Stock Repurchased During Period, Value	1
Common stock issued	98
Dividends, Common Stock	(298)		(272)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(11)
Net Income (Loss) Attributable to Noncontrolling Interest			12		12
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			458
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent			0	0
Contributions from parent			89		1
Dividends			(272)	(265)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(7)
Other Comprehensive Income (Loss), Net of Tax	(15)		0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(14)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	(5)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	3
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Reclassified During Period, Net of Tax	1		0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	523		458	446
Proceeds from Contribution from Parent, net of return of Proceeds			82	81
Income Available to Common Shareholders	$ 538			$ 446
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 2.10
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), Pension and Other Postretirement Benefit Plans, Net of 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)
Stockholders' Equity Attributable to Parent at Dec. 31, 2014	4,987
Common Stock, Value, Outstanding				2,560
Stockholders' Equity Attributable to Noncontrolling Interest					123
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			4,757
AOCI before Tax, Attributable to Parent	$ (4)	$ (19)
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
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			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), Pension and Other Postretirement Benefit Plans, Net of Tax at Dec. 31, 2015	(12)
Retained Earnings, Unappropriated at Dec. 31, 2015	3,118		2,265	$ 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		5,022
Common Stock, Value, Outstanding	2,390		2,760	2,760
Stockholders' Equity Attributable to Noncontrolling Interest			129		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
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			526
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent			0	0
Contributions from parent			100		0
Dividends			(305)	(297)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(8)
Other Comprehensive Income (Loss), Net of Tax	16
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	4
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	(1)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	13
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Reclassified During Period, Net of Tax	0		0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	611		526	513
Proceeds from Contribution from Parent, net of return of Proceeds				100
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), Pension and Other Postretirement Benefit Plans, Net of 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

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2016
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. ServiceCare, Inc. South Carolina Generating Company, Inc. SCANA Services, Inc. Public Service Company of North Carolina, Incorporated SCANA Corporate Security Services, Inc. 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. Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation. 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 $485 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 income. 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 and were included within All Other in Note 12. 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. Reclassifications Certain prior period amounts have been reclassified to conform to the current presentation, as follows: Statements of Cash Flows - For the Company and Consolidated SCE&G, non-cash changes in fair value of interest rate swaps were reclassified as an offset to the changes in certain assets and liabilities section within the reconciliations of Net Income to Net Cash Provided From Operating Activities as follows: December 31, Millions of dollars 2015 2014 Derivative financial instruments $ (174 ) $ 207 Regulatory assets 179 (234 ) Regulatory liabilities 4 (29 ) Other assets (15 ) 32 Other liabilities 6 24 In addition, due to insignificance, the caption for Losses from equity method investments has been eliminated, and the amounts have been reclassified and included within the caption of Changes in Other assets. The reclassifications above had no effect on Net Cash Provided From Operating Activities or on any other subtotal in the consolidated statements of cash flows. Statements of Comprehensive Income - For Consolidated SCE&G, operating revenues and operating expenses from transactions with nonconsolidated affiliates are presented separately. A detail of such transactions are included in Note 11. Segment of Business Information Disclosure - For the Company, the Gas Marketing segment includes the information formerly reported in two separate marketing segments. See Note 12 for the required disclosures. 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 5.3% for 2016, 6.1% for 2015, and 7.2% for 2014. Consolidated SCE&G calculated AFC using average composite rates of 4.7% for 2016, 5.6% for 2015, and 6.5% for 2014. 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. 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: 2016 2015 2014 SCE&G 2.56 % 2.55 % 2.85 % GENCO 2.66 % 2.66 % 2.66 % CGT — — 2.11 % PSNC Energy 2.90 % 2.94 % 2.98 % Weighted average of above 2.61 % 2.61 % 2.84 % Consolidated SCE&G 2.56 % 2.56 % 2.84 % 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. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel. Jointly Owned Utility Plant SCE&G jointly owns and is the operator of Unit 1. In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. As of December 31, 2016 2015 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.3 billion — $ 1.2 billion — Accumulated depreciation $ 634.4 million — $ 620.4 million — Construction work in progress $ 167.7 million $ 4.2 billion $ 214.6 million $ 3.4 billion For a discussion of expected cash outlays and expected in-service dates for the New Units and a description of SCE&G's agreement to acquire an additional 5% ownership in the New Units, see Note 10. 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 Unit 1 and the New Units. These amounts totaled $76.2 million at December 31, 2016 and $178.8 million at December 31, 2015. 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, 2016, and 2015, SCE&G incurred $23.8 million and $16.5 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 $26.8 million for the Fall 2015 outage and $1.8 million in 2016 in preparation for the Spring 2017 outage. 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 evaluation as of January 1, 2017 and was not required to use the two-step quantitative assessment. In evaluations for preceding periods, the Company's step one assessment utilized the assistance of an independent appraisal in determining its estimate of fair value. In such evaluations, step one indicated no impairment, and no impairment charges were recorded. 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 trusteed asset balance 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 and treasury bills. 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. Other receivables consist primarily of amounts due from Santee Cooper related to the construction and operation of 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 utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. The counterparty held, through an agency relationship, 40% and 46% of PSNC Energy’s natural gas inventory at December 31, 2016 and December 31, 2015, respectively, with a carrying value of $9.8 million and $17.7 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to rate payers. PSNC Energy expects to replace this agreement when it expires on March 31, 2017. 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 they are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, they are charged or credited to income tax expense. 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 in 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. 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. Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 12) are presented within Operating Income, 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. Unbilled revenues totaled $178.9 million at December 31, 2016 and $129.1 million at December 31, 2015 for the Company. Unbilled revenues totaled $117.6 million at December 31, 2016 and $101.5 million at December 31, 2015 for Consolidated SCE&G. 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 hearings. 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 hearings. 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 Basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. When applicable, diluted earnings per share are computed using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. New Accounting Matters In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, have begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation. In May 2015, the FASB issued accounting guidance removing the requirement to categorize within the fair value hierarchy investments for which fair values are estimated using the NAV practical expedient. Disclosures about investments in certain entities that calculate NAV per share are limited under this guidance to those investments for which the entity has elected to estimate the fair value using the NAV practical expedient. The Company and Consolidated SCE&G elected to adopt this guidance on a retrospective basis. The adoption resulted in the reclassification of fair value related to the pension plan’s investment in the common collective trust, joint venture interest, and limited partnership as of December 31, 2015. See Note 8. In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G expect to adopt this guidance in the first quarter of 2017 and do not expect it to have a significant impact on their respective financial statements. In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and have determined adoption of this guidance will not have a significant impact on their respective financial statements. 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. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the initial identification and analysis of leasing and related contracts to which the guidance might be applicable have begun. In addition, the Company and Consolidated SCE&G have begun evaluating certain third party software tools that may assist with this implementation and ongoing compliance. In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities are required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G adopted this guidance in the fourth quarter of 2016 and, based on the nature of their share-based awards practices, the adoption had no impact on their respective financial statements. 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 is intended to result in certain 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 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. 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 impact their respective financial statements. In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G expect to adopt this guidance in the first quarter 2017 and it is not expected to have a material impact on their respective financial statements. In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018 and the Company and Consolidated SCE&G expect no impact on their respective financial statements. In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test. The same one-step impairment test will be applied to goodwill at all reporting units, even those with zero or negative carrying amounts. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that adoption will have a material impact on their respective financial statements.
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. ServiceCare, Inc. South Carolina Generating Company, Inc. SCANA Services, Inc. Public Service Company of North Carolina, Incorporated SCANA Corporate Security Services, Inc. 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. Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation. 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 $485 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 income. 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 and were included within All Other in Note 12. 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. Reclassifications Certain prior period amounts have been reclassified to conform to the current presentation, as follows: Statements of Cash Flows - For the Company and Consolidated SCE&G, non-cash changes in fair value of interest rate swaps were reclassified as an offset to the changes in certain assets and liabilities section within the reconciliations of Net Income to Net Cash Provided From Operating Activities as follows: December 31, Millions of dollars 2015 2014 Derivative financial instruments $ (174 ) $ 207 Regulatory assets 179 (234 ) Regulatory liabilities 4 (29 ) Other assets (15 ) 32 Other liabilities 6 24 In addition, due to insignificance, the caption for Losses from equity method investments has been eliminated, and the amounts have been reclassified and included within the caption of Changes in Other assets. The reclassifications above had no effect on Net Cash Provided From Operating Activities or on any other subtotal in the consolidated statements of cash flows. Statements of Comprehensive Income - For Consolidated SCE&G, operating revenues and operating expenses from transactions with nonconsolidated affiliates are presented separately. A detail of such transactions are included in Note 11. Segment of Business Information Disclosure - For the Company, the Gas Marketing segment includes the information formerly reported in two separate marketing segments. See Note 12 for the required disclosures. 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 5.3% for 2016, 6.1% for 2015, and 7.2% for 2014. Consolidated SCE&G calculated AFC using average composite rates of 4.7% for 2016, 5.6% for 2015, and 6.5% for 2014. 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. 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: 2016 2015 2014 SCE&G 2.56 % 2.55 % 2.85 % GENCO 2.66 % 2.66 % 2.66 % CGT — — 2.11 % PSNC Energy 2.90 % 2.94 % 2.98 % Weighted average of above 2.61 % 2.61 % 2.84 % Consolidated SCE&G 2.56 % 2.56 % 2.84 % 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. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel. Jointly Owned Utility Plant SCE&G jointly owns and is the operator of Unit 1. In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. As of December 31, 2016 2015 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.3 billion — $ 1.2 billion — Accumulated depreciation $ 634.4 million — $ 620.4 million — Construction work in progress $ 167.7 million $ 4.2 billion $ 214.6 million $ 3.4 billion For a discussion of expected cash outlays and expected in-service dates for the New Units and a description of SCE&G's agreement to acquire an additional 5% ownership in the New Units, see Note 10. 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 Unit 1 and the New Units. These amounts totaled $76.2 million at December 31, 2016 and $178.8 million at December 31, 2015. 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, 2016, and 2015, SCE&G incurred $23.8 million and $16.5 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 $26.8 million for the Fall 2015 outage and $1.8 million in 2016 in preparation for the Spring 2017 outage. 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 evaluation as of January 1, 2017 and was not required to use the two-step quantitative assessment. In evaluations for preceding periods, the Company's step one assessment utilized the assistance of an independent appraisal in determining its estimate of fair value. In such evaluations, step one indicated no impairment, and no impairment charges were recorded. 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 trusteed asset balance 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 and treasury bills. 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. Other receivables consist primarily of amounts due from Santee Cooper related to the construction and operation of 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 utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. The counterparty held, through an agency relationship, 40% and 46% of PSNC Energy’s natural gas inventory at December 31, 2016 and December 31, 2015, respectively, with a carrying value of $9.8 million and $17.7 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to rate payers. PSNC Energy expects to replace this agreement when it expires on March 31, 2017. 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 they are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, they are charged or credited to income tax expense. 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 in 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. 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. Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 12) are presented within Operating Income, 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. Unbilled revenues totaled $178.9 million at December 31, 2016 and $129.1 million at December 31, 2015 for the Company. Unbilled revenues totaled $117.6 million at December 31, 2016 and $101.5 million at December 31, 2015 for Consolidated SCE&G. 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 hearings. 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 hearings. 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 Basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. When applicable, diluted earnings per share are computed using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. New Accounting Matters In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, have begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation. In May 2015, the FASB issued accounting guidance removing the requirement to categorize within the fair value hierarchy investments for which fair values are estimated using the NAV practical expedient. Disclosures about investments in certain entities that calculate NAV per share are limited under this guidance to those investments for which the entity has elected to estimate the fair value using the NAV practical expedient. The Company and Consolidated SCE&G elected to adopt this guidance on a retrospective basis. The adoption resulted in the reclassification of fair value related to the pension plan’s investment in the common collective trust, joint venture interest, and limited partnership as of December 31, 2015. See Note 8. In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G expect to adopt this guidance in the first quarter of 2017 and do not expect it to have a significant impact on their respective financial statements. In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and have determined adoption of this guidance will not have a significant impact on their respective financial statements. 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. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the initial identification and analysis of leasing and related contracts to which the guidance might be applicable have begun. In addition, the Company and Consolidated SCE&G have begun evaluating certain third party software tools that may assist with this implementation and ongoing compliance. In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities are required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G adopted this guidance in the fourth quarter of 2016 and, based on the nature of their share-based awards practices, the adoption had no impact on their respective financial statements. 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 is intended to result in certain 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 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. 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 impact their respective financial statements. In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G expect to adopt this guidance in the first quarter 2017 and it is not expected to have a material impact on their respective financial statements. In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018 and the Company and Consolidated SCE&G expect no impact on their respective financial statements. In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test. The same one-step impairment test will be applied to goodwill at all reporting units, even those with zero or negative carrying amounts. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that adoption will have a material impact on their respective financial statements.

RATE AND OTHER REGULATORY MATTE

RATE AND OTHER REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2016
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. Pursuant to an April 2014 SCPSC order, SCE&G increased its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs approved by the SCPSC in March 2014. In addition, pursuant to the April 2014 order, electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments were fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs from May 1, 2014 through April 30, 2015. The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel. As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings. 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 a settlement agreement among SCE&G, ORS, and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, 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. By order dated September 16, 2015, the SCPSC approved SCE&G's request to adopt lower depreciation rates for electric and common plant effective January 1, 2015. These rates were based on the results of a depreciation study conducted by SCE&G using utility plant balances as of December 31, 2014. In connection with the adoption of the revised depreciation rates, SCE&G recorded lower depreciation expense of approximately $29 million ( $.12 per share) in 2015, and pursuant to the SCPSC order, SCE&G reduced its electric operating revenues by approximately $14.5 million ( $.06 per share) with an offset to under-collected fuel included within Receivables in the balance sheet. Accordingly, SCE&G's net income for 2015 increased approximately $9.8 million as a result of this change in estimate. 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. In October 2016, the SCPSC initiated its 2017 annual review of base rates for fuel costs. A public hearing for this annual review is scheduled for April 6, 2017. Electric - Base Rates Pursuant to an SCPSC order, SCE&G removes from rate base certain deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs on those amounts during periods in which they are not included in rate base. Such carrying costs are determined at SCE&G’s weighted average long-term debt borrowing rate and are recorded as a regulatory asset and other income. Carrying costs totaled $14.0 million and $9.5 million during 2016 and 2015, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized. 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 2016 First billing cycle of May $37.6 million 2015 First billing cycle of May $32.0 million 2014 First billing cycle of May $15.4 million In April 2014, the SCPSC issued an order approving, among other things, SCE&G’s request to utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of SCE&G’s DSM Programs rate rider. This order also allowed SCE&G to apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to offset previously deferred amounts. By order dated April 29, 2016, the SCPSC approved SCE&G’s request to increase its pension costs rider. The increased pension rider is 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. In January 2017, 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 the DSM Programs, along with an incentive to invest in such programs. Electric - BLRA Under the BLRA, SCE&G may file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Rate adjustments are based on SCE&G's updated cost of debt and capital structure and on an allowed ROE. The SCPSC has approved recovery of the following amounts. Year Increase Effective for bills rendered on and after Amount Allowed ROE 2016 2.7% November 27 $64.4 million 10.50% * 2015 2.6% October 30 $64.5 million 11.00% 2014 2.8% October 30 $66.2 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 the New Units which were developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option. The approved construction schedule designates contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Units 2 and 3, respectively. The approved capital cost schedule includes incremental capital costs that total $831 million . SCE&G’s total project capital cost is now estimated at 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 new nuclear construction from 10.5% to 10.25% . This revised ROE will 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 may not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request is denied because SCE&G is out of compliance with its approved capital cost schedule or BLRA construction milestone schedule. In most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. See also New Nuclear Construction in Note 10. On December 14, 2016, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement. These parties may appeal this decision to the South Carolina Supreme Court once the SCPSC’s order has been issued. SCE&G cannot determine when the SCPSC will issue its order in this matter or if that order will be appealed. 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 2016 1.2 % Increase $4.1 million 2015 No change — 2014 0.6 % Decrease $2.6 million 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, 2016, 2015 and 2014 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. 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, PSNC Energy was authorized to implement a tracker that provides for biannual rate adjustments to recover the revenue requirement associated with integrity management plant investment and associated costs resulting from prevailing federal standards for pipeline integrity and safety that are not otherwise included in current base rates. The new rates are effective for services rendered on or after November 1, 2016. In November 2016, in connection with PSNC Energy's 2016 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, 2016. 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. Other than 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 2016 2015 2016 2015 Regulatory Assets: Accumulated deferred income taxes $ 316 $ 298 $ 307 $ 291 AROs and related funding 425 405 403 384 Deferred employee benefit plan costs 342 325 309 295 Deferred losses on interest rate derivatives 620 535 620 535 Unrecovered plant 117 127 117 127 Environmental remediation costs 32 42 26 35 DSM Programs 59 61 59 61 Pipeline integrity management costs 33 19 6 4 Carrying costs on deferred tax assets related to nuclear construction 32 18 32 18 Deferred storm damage costs 20 — 20 — Deferred costs related to uncertain tax position 15 — 15 — Other 119 107 116 107 Total Regulatory Assets $ 2,130 $ 1,937 $ 2,030 $ 1,857 Regulatory Liabilities: Asset removal costs $ 755 $ 732 $ 529 $ 519 Deferred gains on interest rate derivatives 151 96 151 96 Other 24 27 15 20 Total Regulatory Liabilities $ 930 $ 855 $ 695 $ 635 Accumulated deferred income tax liabilities that arise from utility operations that have not been included in customer rates are recorded as a regulatory asset. A substantial portion of these regulatory assets 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. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station 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 110 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. In 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or 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, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. 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. Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy, and are expected to be recovered over periods of up to approximately 18 years. DSM Programs represent SCE&G's deferred costs associated with such programs, and such deferred costs are currently being recovered over approximately five years through an approved rate rider. Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to natural gas pipelines located near moderate to high density populations. PSNC Energy will recover costs totaling $20.3 million over a five -year period beginning November 2016, and remaining costs of $7.0 million have been deferred pending future approval of rate recovery. SCE&G began amortizing $1.9 million of such costs annually in November 2015. Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2020. 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 represent 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 are expected to be recovered through utility rates following ultimate resolution of the claims. See also Note 5. Various other regulatory assets are expected to be recovered through rates over periods up to 2047. Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most 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 the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders. 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 or other changes in the regulatory environment or changes in accounting requirements, the Company or Consolidated SCE&G could be required to write off 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.
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. Pursuant to an April 2014 SCPSC order, SCE&G increased its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs approved by the SCPSC in March 2014. In addition, pursuant to the April 2014 order, electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments were fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs from May 1, 2014 through April 30, 2015. The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel. As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings. 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 a settlement agreement among SCE&G, ORS, and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, 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. By order dated September 16, 2015, the SCPSC approved SCE&G's request to adopt lower depreciation rates for electric and common plant effective January 1, 2015. These rates were based on the results of a depreciation study conducted by SCE&G using utility plant balances as of December 31, 2014. In connection with the adoption of the revised depreciation rates, SCE&G recorded lower depreciation expense of approximately $29 million ( $.12 per share) in 2015, and pursuant to the SCPSC order, SCE&G reduced its electric operating revenues by approximately $14.5 million ( $.06 per share) with an offset to under-collected fuel included within Receivables in the balance sheet. Accordingly, SCE&G's net income for 2015 increased approximately $9.8 million as a result of this change in estimate. 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. In October 2016, the SCPSC initiated its 2017 annual review of base rates for fuel costs. A public hearing for this annual review is scheduled for April 6, 2017. Electric - Base Rates Pursuant to an SCPSC order, SCE&G removes from rate base certain deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs on those amounts during periods in which they are not included in rate base. Such carrying costs are determined at SCE&G’s weighted average long-term debt borrowing rate and are recorded as a regulatory asset and other income. Carrying costs totaled $14.0 million and $9.5 million during 2016 and 2015, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized. 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 2016 First billing cycle of May $37.6 million 2015 First billing cycle of May $32.0 million 2014 First billing cycle of May $15.4 million In April 2014, the SCPSC issued an order approving, among other things, SCE&G’s request to utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of SCE&G’s DSM Programs rate rider. This order also allowed SCE&G to apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to offset previously deferred amounts. By order dated April 29, 2016, the SCPSC approved SCE&G’s request to increase its pension costs rider. The increased pension rider is 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. In January 2017, 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 the DSM Programs, along with an incentive to invest in such programs. Electric - BLRA Under the BLRA, SCE&G may file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Rate adjustments are based on SCE&G's updated cost of debt and capital structure and on an allowed ROE. The SCPSC has approved recovery of the following amounts. Year Increase Effective for bills rendered on and after Amount Allowed ROE 2016 2.7% November 27 $64.4 million 10.50% * 2015 2.6% October 30 $64.5 million 11.00% 2014 2.8% October 30 $66.2 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 the New Units which were developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option. The approved construction schedule designates contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Units 2 and 3, respectively. The approved capital cost schedule includes incremental capital costs that total $831 million . SCE&G’s total project capital cost is now estimated at 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 new nuclear construction from 10.5% to 10.25% . This revised ROE will 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 may not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request is denied because SCE&G is out of compliance with its approved capital cost schedule or BLRA construction milestone schedule. In most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. See also New Nuclear Construction in Note 10. On December 14, 2016, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement. These parties may appeal this decision to the South Carolina Supreme Court once the SCPSC’s order has been issued. SCE&G cannot determine when the SCPSC will issue its order in this matter or if that order will be appealed. 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 2016 1.2 % Increase $4.1 million 2015 No change — 2014 0.6 % Decrease $2.6 million 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, 2016, 2015 and 2014 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. 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, PSNC Energy was authorized to implement a tracker that provides for biannual rate adjustments to recover the revenue requirement associated with integrity management plant investment and associated costs resulting from prevailing federal standards for pipeline integrity and safety that are not otherwise included in current base rates. The new rates are effective for services rendered on or after November 1, 2016. In November 2016, in connection with PSNC Energy's 2016 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, 2016. 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. Other than 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 2016 2015 2016 2015 Regulatory Assets: Accumulated deferred income taxes $ 316 $ 298 $ 307 $ 291 AROs and related funding 425 405 403 384 Deferred employee benefit plan costs 342 325 309 295 Deferred losses on interest rate derivatives 620 535 620 535 Unrecovered plant 117 127 117 127 Environmental remediation costs 32 42 26 35 DSM Programs 59 61 59 61 Pipeline integrity management costs 33 19 6 4 Carrying costs on deferred tax assets related to nuclear construction 32 18 32 18 Deferred storm damage costs 20 — 20 — Deferred costs related to uncertain tax position 15 — 15 — Other 119 107 116 107 Total Regulatory Assets $ 2,130 $ 1,937 $ 2,030 $ 1,857 Regulatory Liabilities: Asset removal costs $ 755 $ 732 $ 529 $ 519 Deferred gains on interest rate derivatives 151 96 151 96 Other 24 27 15 20 Total Regulatory Liabilities $ 930 $ 855 $ 695 $ 635 Accumulated deferred income tax liabilities that arise from utility operations that have not been included in customer rates are recorded as a regulatory asset. A substantial portion of these regulatory assets 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. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station 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 110 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. In 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or 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, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. 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. Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy, and are expected to be recovered over periods of up to approximately 18 years. DSM Programs represent SCE&G's deferred costs associated with such programs, and such deferred costs are currently being recovered over approximately five years through an approved rate rider. Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to natural gas pipelines located near moderate to high density populations. PSNC Energy will recover costs totaling $20.3 million over a five -year period beginning November 2016, and remaining costs of $7.0 million have been deferred pending future approval of rate recovery. SCE&G began amortizing $1.9 million of such costs annually in November 2015. Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2020. 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 represent 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 are expected to be recovered through utility rates following ultimate resolution of the claims. See also Note 5. Various other regulatory assets are expected to be recovered through rates over periods up to 2047. Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most 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 the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders. 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 or other changes in the regulatory environment or changes in accounting requirements, the Company or Consolidated SCE&G could be required to write off 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.

COMMON EQUITY

COMMON EQUITY	12 Months Ended
	Dec. 31, 2016
Schedule of Capitalization, Equity [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	COMMON EQUITY 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. However, SCE&G’s bond indenture and PSNC Energy’s note purchase and debenture purchase agreements each contain provisions that, under certain circumstances, which the Company and, in the case of SCE&G, Consolidated SCE&G consider to be remote, could limit the payment of cash dividends on their respective common stock. The Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At December 31, 2016 and 2015, retained earnings of approximately $79.0 million and $72.4 million , respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock. Authorized shares of common stock were 200 million as of December 31, 2016 and 2015. SCANA issued no common stock during the year ended December 31, 2016. SCANA issued common stock valued at $14.3 million (when issued) during the year ended December 31, 2015, to satisfy the requirements of deferred compensation and dividend reinvestment plans. Authorized shares of SCE&G common stock were 50 million as of December 31, 2016 and 2015. 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, 2016 and 2015.
SCE&G
Schedule of Capitalization, Equity [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	3. COMMON EQUITY 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. However, SCE&G’s bond indenture and PSNC Energy’s note purchase and debenture purchase agreements each contain provisions that, under certain circumstances, which the Company and, in the case of SCE&G, Consolidated SCE&G consider to be remote, could limit the payment of cash dividends on their respective common stock. The Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At December 31, 2016 and 2015, retained earnings of approximately $79.0 million and $72.4 million , respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock. Authorized shares of common stock were 200 million as of December 31, 2016 and 2015. SCANA issued no common stock during the year ended December 31, 2016. SCANA issued common stock valued at $14.3 million (when issued) during the year ended December 31, 2015, to satisfy the requirements of deferred compensation and dividend reinvestment plans. Authorized shares of SCE&G common stock were 50 million as of December 31, 2016 and 2015. 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, 2016 and 2015.

LONG-TERM AND SHORT-TERM DEBT

LONG-TERM AND SHORT-TERM DEBT	12 Months Ended
	Dec. 31, 2015
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, 2016 2015 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) 2017 - 2034 79 1.63 % 84 1.11 % SCE&G First Mortgage Bonds (secured) 2018 - 2065 4,840 5.79 % 4,340 5.78 % GENCO Notes (secured) 2017 - 2024 213 5.93 % 220 5.92 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.51 % 122 3.51 % PSNC Energy Senior Debentures and Notes 2020 - 2046 450 5.53 % 350 5.93 % Nuclear Fuel Financing 2016 — — % 100 0.78 % Other 2017 - 2027 27 2.76 % 18 2.72 % Total debt 6,531 6,034 Current maturities of long-term debt (17 ) (116 ) Unamortized discount, net (1 ) — Unamortized debt issuance costs (40 ) (36 ) Total long-term debt, net $ 6,473 $ 5,882 Consolidated SCE&G December 31, 2016 2015 Dollars in millions Maturity Balance Rate Balance Rate First Mortgage Bonds (secured) 2018 - 2065 $ 4,840 5.79 % $ 4,340 5.78 % GENCO Notes (secured) 2017 - 2024 213 5.93 % 220 5.92 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.51 % 122 3.51 % Nuclear Fuel Financing 2016 — — % 100 0.78 % Other 2017 - 2027 26 2.76 % 17 2.63 % Total debt 5,201 4,799 Current maturities of long-term debt (12 ) (110 ) Unamortized premium, net 1 2 Unamortized debt issuance costs (36 ) (32 ) Total long-term debt, net $ 5,154 $ 4,659 (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, 2016 (rate of 0.76% ) and 2015 (rate of 0.03% ) which are hedged by fixed swaps. In June 2016, SCE&G issued $425 million of 4.1% first mortgage bonds due June 15, 2046. In addition, 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 2016, PSNC Energy issued $100 million of 4.13% senior notes due June 22, 2046. Proceeds from this sale were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes. In May 2015, SCE&G issued $500 million of 5.1% first mortgage bonds due June 1, 2065. Proceeds from this sale 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. The Company's long-term debt maturities will be $17 million in 2017, $726 million in 2018, $15 million in 2019, $365 million in 2020 and $493 million in 2021. These amounts include, for Consolidated SCE&G, $12 million in 2017, $722 million in 2018, $11 million in 2019, $10 million in 2020 and $39 million in 2021. 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 outstanding (Bond Ratio). For the year ended December 31, 2016, the Bond Ratio was 5.12 . Lines of Credit and Short-Term Borrowings At December 31, 2016 and 2015, 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: December 31, 2016 Millions of dollars Total SCANA SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 $ 500.0 — $ 500.0 — Three-year, expiring December 2018 $ 200.0 — $ 200.0 — Total committed long-term $ 2,000.0 $ 400.0 $ 1,400.0 $ 200.0 Outstanding commercial paper (270 or fewer days) $ 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 December 31, 2015 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) $ 531.4 $ 37.4 $ 420.2 $ 73.8 Weighted average interest rate 1.19 % 0.74 % 0.77 % Letters of credit supported by LOC $ 3.3 $ 3.0 $ 0.3 — Available $ 1,465.4 $ 359.6 $ 979.6 $ 126.2 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. 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, 2016 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $29 million . At December 31, 2015 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $33 million and money pool investments due from an affiliate of $9 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, 2016 2015 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) 2017 - 2034 79 1.63 % 84 1.11 % SCE&G First Mortgage Bonds (secured) 2018 - 2065 4,840 5.79 % 4,340 5.78 % GENCO Notes (secured) 2017 - 2024 213 5.93 % 220 5.92 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.51 % 122 3.51 % PSNC Energy Senior Debentures and Notes 2020 - 2046 450 5.53 % 350 5.93 % Nuclear Fuel Financing 2016 — — % 100 0.78 % Other 2017 - 2027 27 2.76 % 18 2.72 % Total debt 6,531 6,034 Current maturities of long-term debt (17 ) (116 ) Unamortized discount, net (1 ) — Unamortized debt issuance costs (40 ) (36 ) Total long-term debt, net $ 6,473 $ 5,882 Consolidated SCE&G December 31, 2016 2015 Dollars in millions Maturity Balance Rate Balance Rate First Mortgage Bonds (secured) 2018 - 2065 $ 4,840 5.79 % $ 4,340 5.78 % GENCO Notes (secured) 2017 - 2024 213 5.93 % 220 5.92 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.51 % 122 3.51 % Nuclear Fuel Financing 2016 — — % 100 0.78 % Other 2017 - 2027 26 2.76 % 17 2.63 % Total debt 5,201 4,799 Current maturities of long-term debt (12 ) (110 ) Unamortized premium, net 1 2 Unamortized debt issuance costs (36 ) (32 ) Total long-term debt, net $ 5,154 $ 4,659 (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, 2016 (rate of 0.76% ) and 2015 (rate of 0.03% ) which are hedged by fixed swaps. In June 2016, SCE&G issued $425 million of 4.1% first mortgage bonds due June 15, 2046. In addition, 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 2016, PSNC Energy issued $100 million of 4.13% senior notes due June 22, 2046. Proceeds from this sale were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes. In May 2015, SCE&G issued $500 million of 5.1% first mortgage bonds due June 1, 2065. Proceeds from this sale 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. The Company's long-term debt maturities will be $17 million in 2017, $726 million in 2018, $15 million in 2019, $365 million in 2020 and $493 million in 2021. These amounts include, for Consolidated SCE&G, $12 million in 2017, $722 million in 2018, $11 million in 2019, $10 million in 2020 and $39 million in 2021. 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 outstanding (Bond Ratio). For the year ended December 31, 2016, the Bond Ratio was 5.12 . Lines of Credit and Short-Term Borrowings At December 31, 2016 and 2015, 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: December 31, 2016 Millions of dollars Total SCANA SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 $ 500.0 — $ 500.0 — Three-year, expiring December 2018 $ 200.0 — $ 200.0 — Total committed long-term $ 2,000.0 $ 400.0 $ 1,400.0 $ 200.0 Outstanding commercial paper (270 or fewer days) $ 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 December 31, 2015 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) $ 531.4 $ 37.4 $ 420.2 $ 73.8 Weighted average interest rate 1.19 % 0.74 % 0.77 % Letters of credit supported by LOC $ 3.3 $ 3.0 $ 0.3 — Available $ 1,465.4 $ 359.6 $ 979.6 $ 126.2 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. 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, 2016 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $29 million . At December 31, 2015 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $33 million and money pool investments due from an affiliate of $9 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, 2016
income tax [Line Items]
Income Tax Disclosure [Text Block]	INCOME TAXES Components of income tax expense are as follows: The Company Consolidated SCE&G Millions of dollars 2016 2015 2014 2016 2015 2014 Current taxes: Federal $ 36 $ 382 $ 38 $ 50 $ 208 $ 39 State 13 57 (4 ) 13 32 (6 ) Total current taxes 49 439 34 63 240 33 Deferred tax (benefit) expense, net: Federal 203 (36 ) 184 167 (3 ) 157 State 21 (7 ) 34 20 (3 ) 32 Total deferred taxes 224 (43 ) 218 187 (6 ) 189 Investment tax credits: Amortization of amounts deferred-state — (1 ) (1 ) — (1 ) (1 ) Amortization of amounts deferred-federal (2 ) (2 ) (3 ) (2 ) (2 ) (3 ) Total investment tax credits (2 ) (3 ) (4 ) (2 ) (3 ) (4 ) Total income tax expense $ 271 $ 393 $ 248 $ 248 $ 231 $ 218 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 2016 2015 2014 2016 2015 2014 Net income $ 595 $ 746 $ 538 $ 513 $ 466 $ 446 Income tax expense 271 393 248 248 231 218 Noncontrolling interest — — — 13 14 12 Total pre-tax income $ 866 $ 1,139 $ 786 $ 774 $ 711 $ 676 Income taxes on above at statutory federal income tax rate $ 303 $ 399 $ 275 $ 271 $ 249 $ 237 Increases (decreases) attributed to: State income taxes (less federal income tax effect) 27 38 24 26 24 21 State investment tax credits (less federal income tax effect) (5 ) (6 ) (5 ) (5 ) (6 ) (5 ) Allowance for equity funds used during construction (10 ) (9 ) (11 ) (9 ) (9 ) (10 ) Deductible dividends—401(k) Retirement Savings Plan (10 ) (10 ) (10 ) — — — Amortization of federal investment tax credits (2 ) (2 ) (3 ) (2 ) (2 ) (3 ) Section 41 tax credits — 1 (3 ) — 1 (3 ) Section 45 tax credits (8 ) (9 ) (9 ) (8 ) (9 ) (9 ) Domestic production activities deduction (23 ) (18 ) (7 ) (23 ) (18 ) (7 ) Realization of basis differences upon sale of subsidiaries — 7 — — — — Other differences, net (1 ) 2 (3 ) (2 ) 1 (3 ) Total income tax expense $ 271 $ 393 $ 248 $ 248 $ 231 $ 218 The tax effects of significant temporary differences comprising net deferred tax liability are as follows: The Company Consolidated SCE&G Millions of dollars 2016 2015 2016 2015 Deferred tax assets: Nondeductible accruals $ 148 $ 135 $ 53 $ 52 Asset retirement obligation, including nuclear decommissioning 213 199 200 187 Financial instruments 22 35 — 2 Unamortized investment tax credits 15 16 15 16 Deferred fuel costs 17 8 17 7 Other 10 5 8 2 Total deferred tax assets 425 398 293 266 Deferred tax liabilities: Property, plant and equipment 2,159 1,906 1,856 1,644 Deferred employee benefit plan costs 105 96 93 85 Regulatory asset, asset retirement obligation 143 135 135 127 Regulatory asset, unrecovered plant 45 49 45 49 Demand side management costs 23 23 23 23 Prepayments 32 31 30 29 Other 77 65 50 41 Total deferred tax liabilities 2,584 2,305 2,232 1,998 Net deferred tax liability $ 2,159 $ 1,907 $ 1,939 $ 1,732 The State of North Carolina lowered its corporate income tax rate from 6.9% to 6.0% in 2014, 5.0% in 2015, 4% in 2016 and 3% effective January 1, 2017. 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 2007 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2015 as a result of claims discussed below in Changes in Unrecognized Tax Benefits. 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 2016 2015 2014 2016 2015 2014 Unrecognized tax benefits, January 1 $ 49 $ 16 $ 3 $ 49 $ 16 $ 3 Gross increases—uncertain tax positions in prior period 94 33 — 94 33 — Gross decreases—uncertain tax positions in prior period — (2 ) — — (2 ) — Gross increases—current period uncertain tax positions 207 2 13 207 2 13 Unrecognized tax benefits, December 31 $ 350 $ 49 $ 16 $ 350 $ 49 $ 16 During 2013 and 2014, SCANA 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). SCANA also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In September 2016, SCANA claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the ongoing design and construction activities of the New Units, in its 2015 income tax returns. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. The IRS examined the claims in the amended 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. These income tax deductions and credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are required to be recorded as unrecognized tax benefits in the financial statements. As of December 31, 2016, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $350 million ( $219 million and $236 million for the Company and Consolidated SCE&G, respectively, net of the impact of state deductions on federal returns, and net of certain operating loss and tax credit carryforwards and receivables related to the uncertain tax positions). If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate (see discussion below regarding deferral of benefits related to 2015 forward). It is reasonably possible that these unrecognized tax benefits may increase by an additional $292 million within the next 12 months as additional expenditures giving rise to pilot model tax benefits are incurred. It is also reasonably possible that these unrecognized tax benefits may decrease by $49 million within the next 12 months if the claims on the amended returns which are currently in appeals are resolved and that resolution were also applied to the 2013 and 2014 returns. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through December 31, 2016. In connection with the research and experimentation deduction and credit claims reflected on the 2015 income tax returns and the expectation of similar claims to be made in determining 2016’s taxable income, the Company and Consolidated SCE&G have recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, and expect that such (net) deferred costs, along with any interest (see below) and other related deferred costs, will be recoverable through customer rates in future years. SCE&G's current customer rates reflect the availability of domestic production activities deductions (see Note 2). Estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 income tax returns has been deferred as a regulatory asset and is expected to be recoverable through customer rates in future years. See also Note 2. 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. In 2016, the amount recorded for such interest income is $1.8 million and interest expense is $0.9 million . Such amounts were not significant in 2015 or 2014. No amounts have been recorded for tax penalties for any periods presented.
SCE&G
income tax [Line Items]
Income Tax Disclosure [Text Block]	INCOME TAXES Components of income tax expense are as follows: The Company Consolidated SCE&G Millions of dollars 2016 2015 2014 2016 2015 2014 Current taxes: Federal $ 36 $ 382 $ 38 $ 50 $ 208 $ 39 State 13 57 (4 ) 13 32 (6 ) Total current taxes 49 439 34 63 240 33 Deferred tax (benefit) expense, net: Federal 203 (36 ) 184 167 (3 ) 157 State 21 (7 ) 34 20 (3 ) 32 Total deferred taxes 224 (43 ) 218 187 (6 ) 189 Investment tax credits: Amortization of amounts deferred-state — (1 ) (1 ) — (1 ) (1 ) Amortization of amounts deferred-federal (2 ) (2 ) (3 ) (2 ) (2 ) (3 ) Total investment tax credits (2 ) (3 ) (4 ) (2 ) (3 ) (4 ) Total income tax expense $ 271 $ 393 $ 248 $ 248 $ 231 $ 218 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 2016 2015 2014 2016 2015 2014 Net income $ 595 $ 746 $ 538 $ 513 $ 466 $ 446 Income tax expense 271 393 248 248 231 218 Noncontrolling interest — — — 13 14 12 Total pre-tax income $ 866 $ 1,139 $ 786 $ 774 $ 711 $ 676 Income taxes on above at statutory federal income tax rate $ 303 $ 399 $ 275 $ 271 $ 249 $ 237 Increases (decreases) attributed to: State income taxes (less federal income tax effect) 27 38 24 26 24 21 State investment tax credits (less federal income tax effect) (5 ) (6 ) (5 ) (5 ) (6 ) (5 ) Allowance for equity funds used during construction (10 ) (9 ) (11 ) (9 ) (9 ) (10 ) Deductible dividends—401(k) Retirement Savings Plan (10 ) (10 ) (10 ) — — — Amortization of federal investment tax credits (2 ) (2 ) (3 ) (2 ) (2 ) (3 ) Section 41 tax credits — 1 (3 ) — 1 (3 ) Section 45 tax credits (8 ) (9 ) (9 ) (8 ) (9 ) (9 ) Domestic production activities deduction (23 ) (18 ) (7 ) (23 ) (18 ) (7 ) Realization of basis differences upon sale of subsidiaries — 7 — — — — Other differences, net (1 ) 2 (3 ) (2 ) 1 (3 ) Total income tax expense $ 271 $ 393 $ 248 $ 248 $ 231 $ 218 The tax effects of significant temporary differences comprising net deferred tax liability are as follows: The Company Consolidated SCE&G Millions of dollars 2016 2015 2016 2015 Deferred tax assets: Nondeductible accruals $ 148 $ 135 $ 53 $ 52 Asset retirement obligation, including nuclear decommissioning 213 199 200 187 Financial instruments 22 35 — 2 Unamortized investment tax credits 15 16 15 16 Deferred fuel costs 17 8 17 7 Other 10 5 8 2 Total deferred tax assets 425 398 293 266 Deferred tax liabilities: Property, plant and equipment 2,159 1,906 1,856 1,644 Deferred employee benefit plan costs 105 96 93 85 Regulatory asset, asset retirement obligation 143 135 135 127 Regulatory asset, unrecovered plant 45 49 45 49 Demand side management costs 23 23 23 23 Prepayments 32 31 30 29 Other 77 65 50 41 Total deferred tax liabilities 2,584 2,305 2,232 1,998 Net deferred tax liability $ 2,159 $ 1,907 $ 1,939 $ 1,732 The State of North Carolina lowered its corporate income tax rate from 6.9% to 6.0% in 2014, 5.0% in 2015, 4% in 2016 and 3% effective January 1, 2017. 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 2007 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2015 as a result of claims discussed below in Changes in Unrecognized Tax Benefits. 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 2016 2015 2014 2016 2015 2014 Unrecognized tax benefits, January 1 $ 49 $ 16 $ 3 $ 49 $ 16 $ 3 Gross increases—uncertain tax positions in prior period 94 33 — 94 33 — Gross decreases—uncertain tax positions in prior period — (2 ) — — (2 ) — Gross increases—current period uncertain tax positions 207 2 13 207 2 13 Unrecognized tax benefits, December 31 $ 350 $ 49 $ 16 $ 350 $ 49 $ 16 During 2013 and 2014, SCANA 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). SCANA also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In September 2016, SCANA claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the ongoing design and construction activities of the New Units, in its 2015 income tax returns. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. The IRS examined the claims in the amended 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. These income tax deductions and credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are required to be recorded as unrecognized tax benefits in the financial statements. As of December 31, 2016, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $350 million ( $219 million and $236 million for the Company and Consolidated SCE&G, respectively, net of the impact of state deductions on federal returns, and net of certain operating loss and tax credit carryforwards and receivables related to the uncertain tax positions). If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate (see discussion below regarding deferral of benefits related to 2015 forward). It is reasonably possible that these unrecognized tax benefits may increase by an additional $292 million within the next 12 months as additional expenditures giving rise to pilot model tax benefits are incurred. It is also reasonably possible that these unrecognized tax benefits may decrease by $49 million within the next 12 months if the claims on the amended returns which are currently in appeals are resolved and that resolution were also applied to the 2013 and 2014 returns. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through December 31, 2016. In connection with the research and experimentation deduction and credit claims reflected on the 2015 income tax returns and the expectation of similar claims to be made in determining 2016’s taxable income, the Company and Consolidated SCE&G have recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, and expect that such (net) deferred costs, along with any interest (see below) and other related deferred costs, will be recoverable through customer rates in future years. SCE&G's current customer rates reflect the availability of domestic production activities deductions (see Note 2). Estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 income tax returns has been deferred as a regulatory asset and is expected to be recoverable through customer rates in future years. See also Note 2. 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. In 2016, the amount recorded for such interest income is $1.8 million and interest expense is $0.9 million . Such amounts were not significant in 2015 or 2014. No amounts have been recorded for tax penalties for any periods presented.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2016
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 as cash flow hedges and fair value changes and settlement amounts related to them are recorded as regulatory assets and liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances and gains may be amortized to interest expense or may be applied as otherwise directed by the SCPSC. 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, 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 As of December 31, 2015 Commodity 7,530,000 11,842,500 19,372,500 Energy Management (a) — 38,857,480 38,857,480 Total (a) 7,530,000 50,699,980 58,229,980 (a) Includes amounts related to basis swap contracts totaling 730,721 MMBTU in 2016 and 1,842,048 MMBTU in 2015. The aggregate notional amounts of the interest rate swaps were as follows: The Company Consolidated SCE&G Millions of dollars December 31, 2016 December 31, 2015 December 31, 2016 December 31, 2015 Designated as hedging instruments $ 115.6 $ 120.0 $ 36.4 $ 36.4 Not designated as hedging instruments 1,285.0 1,235.0 1,285.0 1,235.0 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, 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 As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 28 9 Commodity contracts Other current assets 1 Derivative financial instruments 4 Total — $ 37 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 $ 10 Other deferred debits and other assets 5 5 Derivative financial instruments $ 33 $ 33 Other deferred credits and other liabilities 22 22 Commodity contracts Other current assets 1 Energy management contracts Other current assets 11 2 Other deferred debits and other assets 3 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 30 $ 69 $ 15 $ 55 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, 2016 Interest rate contracts — Interest expense $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (3 ) Interest expense $ (3 ) Year Ended December 31, 2014 Interest rate contracts $ (9 ) 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, 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 ) Year Ended December 31, 2014 Interest rate contracts $ (6 ) Interest expense $ (7 ) Commodity contracts (8 ) Gas purchased for resale 4 Total $ (14 ) $ (3 ) As of December 31, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $5.4 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.2 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of December 31, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the second quarter of 2019. As of December 31, 2016, 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 $1.8 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 Regulatory Accounts Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars Location Amount Year Ended December 31, 2016 Interest rate contracts $ (34 ) Interest Expense $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (69 ) Other income $ 5 Year Ended December 31, 2014 Interest rate contracts $ (352 ) Other income $ 64 Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. As of December 31, 2016, 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 $2.4 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, 2016 December 31, 2015 December 31, 2016 December 31, 2015 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 50.3 $ 95.2 $ 30.3 $ 57.0 Fair value of collateral already posted 29.2 50.4 9.2 13.4 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 21.1 44.8 21.1 43.6 in Net Asset Position Aggregate fair value of derivatives in net asset position $ 62.9 $ 7.3 $ 62.0 $ 7.3 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 62.9 7.3 62.0 7.3 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 $1.5 million related to $9.0 million in commodity derivatives that are in a net asset position at December 31, 2016, compared to letters of credit of $3.0 million related to derivatives of $14.0 million at December 31, 2015, 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, 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 As of December 31, 2015 Gross Amounts of Recognized Assets $ 15 $ 1 $ 15 $ 31 $ 15 Gross Amounts Offset in Statement of Financial Position (1 ) (1 ) Net Amounts Presented in Statement of Financial Position 15 1 14 30 15 Gross Amounts Not Offset - Financial Instruments (8 ) (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received Net Amount $ 7 $ 1 $ 14 $ 22 $ 7 Balance sheet location Other current assets $ 22 $ 10 Other deferred debits and other assets 8 5 Total $ 30 $ 15 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, 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 As of December 31, 2015 Gross Amounts of Recognized Liabilities $ 87 $ 5 $ 15 $ 107 $ 65 Gross Amounts Offset in Statement of Financial Position (1 ) (1 ) Net Amounts Presented in Statement of Financial Position 87 5 14 106 65 Gross Amounts Not Offset - Financial Instruments (8 ) (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (36 ) (5 ) (9 ) (50 ) (13 ) Net Amount $ 43 $ — $ 5 $ 48 $ 44 Balance sheet location Other current assets $ 3 Derivative financial instruments 50 $ 34 Other deferred credits and other liabilities 53 31 Total $ 106 $ 65
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 as cash flow hedges and fair value changes and settlement amounts related to them are recorded as regulatory assets and liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances and gains may be amortized to interest expense or may be applied as otherwise directed by the SCPSC. 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, 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 As of December 31, 2015 Commodity 7,530,000 11,842,500 19,372,500 Energy Management (a) — 38,857,480 38,857,480 Total (a) 7,530,000 50,699,980 58,229,980 (a) Includes amounts related to basis swap contracts totaling 730,721 MMBTU in 2016 and 1,842,048 MMBTU in 2015. The aggregate notional amounts of the interest rate swaps were as follows: The Company Consolidated SCE&G Millions of dollars December 31, 2016 December 31, 2015 December 31, 2016 December 31, 2015 Designated as hedging instruments $ 115.6 $ 120.0 $ 36.4 $ 36.4 Not designated as hedging instruments 1,285.0 1,235.0 1,285.0 1,235.0 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, 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 As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 28 9 Commodity contracts Other current assets 1 Derivative financial instruments 4 Total — $ 37 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 $ 10 Other deferred debits and other assets 5 5 Derivative financial instruments $ 33 $ 33 Other deferred credits and other liabilities 22 22 Commodity contracts Other current assets 1 Energy management contracts Other current assets 11 2 Other deferred debits and other assets 3 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 30 $ 69 $ 15 $ 55 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, 2016 Interest rate contracts — Interest expense $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (3 ) Interest expense $ (3 ) Year Ended December 31, 2014 Interest rate contracts $ (9 ) 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, 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 ) Year Ended December 31, 2014 Interest rate contracts $ (6 ) Interest expense $ (7 ) Commodity contracts (8 ) Gas purchased for resale 4 Total $ (14 ) $ (3 ) As of December 31, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $5.4 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.2 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of December 31, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the second quarter of 2019. As of December 31, 2016, 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 $1.8 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 Regulatory Accounts Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars Location Amount Year Ended December 31, 2016 Interest rate contracts $ (34 ) Interest Expense $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (69 ) Other income $ 5 Year Ended December 31, 2014 Interest rate contracts $ (352 ) Other income $ 64 Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. As of December 31, 2016, 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 $2.4 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, 2016 December 31, 2015 December 31, 2016 December 31, 2015 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 50.3 $ 95.2 $ 30.3 $ 57.0 Fair value of collateral already posted 29.2 50.4 9.2 13.4 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 21.1 44.8 21.1 43.6 in Net Asset Position Aggregate fair value of derivatives in net asset position $ 62.9 $ 7.3 $ 62.0 $ 7.3 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 62.9 7.3 62.0 7.3 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 $1.5 million related to $9.0 million in commodity derivatives that are in a net asset position at December 31, 2016, compared to letters of credit of $3.0 million related to derivatives of $14.0 million at December 31, 2015, 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, 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 As of December 31, 2015 Gross Amounts of Recognized Assets $ 15 $ 1 $ 15 $ 31 $ 15 Gross Amounts Offset in Statement of Financial Position (1 ) (1 ) Net Amounts Presented in Statement of Financial Position 15 1 14 30 15 Gross Amounts Not Offset - Financial Instruments (8 ) (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received Net Amount $ 7 $ 1 $ 14 $ 22 $ 7 Balance sheet location Other current assets $ 22 $ 10 Other deferred debits and other assets 8 5 Total $ 30 $ 15 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, 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 As of December 31, 2015 Gross Amounts of Recognized Liabilities $ 87 $ 5 $ 15 $ 107 $ 65 Gross Amounts Offset in Statement of Financial Position (1 ) (1 ) Net Amounts Presented in Statement of Financial Position 87 5 14 106 65 Gross Amounts Not Offset - Financial Instruments (8 ) (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (36 ) (5 ) (9 ) (50 ) (13 ) Net Amount $ 43 $ — $ 5 $ 48 $ 44 Balance sheet location Other current assets $ 3 Derivative financial instruments 50 $ 34 Other deferred credits and other liabilities 53 31 Total $ 106 $ 65

FAIR VALUE MEASUREMENTS, INCLUD

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES	12 Months Ended
	Dec. 31, 2016
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. 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, 2016 As of December 31, 2015 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 2 Level 1 Level 2 Level 2 Assets: Available for sale securities $ 14 — — $ 11 — — Held to maturity securities — $ 7 — — — — Interest rate contracts — 71 $ 71 — $ 15 $ 15 Commodity contracts 8 1 — 1 — — Energy management contracts 6 4 — — 14 — Liabilities: Interest rate contracts — 58 39 — 87 65 Commodity contracts — — — 1 4 — Energy management contracts 2 10 — 4 12 — 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, 2016 and December 31, 2015 were as follows: As of December 31, 2016 As of December 31, 2015 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,489.8 $ 7,183.3 $ 5,997.6 $ 6,445.7 Consolidated SCE&G 5,166.0 5,752.3 4,769.0 5,129.1 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.
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. 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, 2016 As of December 31, 2015 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 2 Level 1 Level 2 Level 2 Assets: Available for sale securities $ 14 — — $ 11 — — Held to maturity securities — $ 7 — — — — Interest rate contracts — 71 $ 71 — $ 15 $ 15 Commodity contracts 8 1 — 1 — — Energy management contracts 6 4 — — 14 — Liabilities: Interest rate contracts — 58 39 — 87 65 Commodity contracts — — — 1 4 — Energy management contracts 2 10 — 4 12 — 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, 2016 and December 31, 2015 were as follows: As of December 31, 2016 As of December 31, 2015 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,489.8 $ 7,183.3 $ 5,997.6 $ 6,445.7 Consolidated SCE&G 5,166.0 5,752.3 4,769.0 5,129.1 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.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2016
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 2016 2015 2016 2015 2016 2015 2016 2015 Benefit obligation, January 1 $ 855.4 $ 919.5 $ 253.6 $ 268.2 $ 724.0 $ 773.7 $ 191.7 $ 204.1 Service cost 20.7 24.1 4.4 5.3 16.9 19.3 3.6 4.4 Interest cost 39.4 38.2 12.1 11.4 33.4 32.2 9.9 9.4 Plan participants’ contributions — — 1.7 2.4 — — 1.3 1.9 Actuarial (gain) loss 45.0 (62.4 ) 14.0 (21.2 ) 41.8 (47.0 ) 11.5 (15.7 ) Benefits paid (56.2 ) (64.0 ) (11.1 ) (12.5 ) (47.7 ) (54.2 ) (9.1 ) (10.3 ) Amounts Funded to parent n/a n/a n/a n/a — — (1.7 ) (2.1 ) Benefit obligation, December 31 $ 904.3 $ 855.4 $ 274.7 $ 253.6 $ 768.4 $ 724.0 $ 207.2 $ 191.7 In 2015, based on an evaluation of the mortality experience of the pension plan, a custom mortality table was adopted for purposes of measuring pension and other postretirement benefit obligations at year-end. This change resulted in an actuarial gain for pension and other postretirement benefit obligations for the Company of approximately $21.5 million and $2.4 million , respectively. This change resulted in an actuarial gain for pension and other postretirement benefit obligations for Consolidated SCE&G of approximately $18.2 million and $2.0 million , respectively. The accumulated benefit obligation for pension benefits for the Company was $ 874.3 million at the end of 2016 and $ 829.3 million at the end of 2015. The accumulated benefit obligation for pension benefits for Consolidated SCE&G was $742.9 million at the end of 2016 and $702.0 million at the end of 2015.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 2016 2015 2016 2015 Annual discount rate used to determine benefit obligation 4.22 % 4.68 % 4.30 % 4.78 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 % A 6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017. The rate was assumed to decrease gradually to 5.0% for 2021 and to remain at that level thereafter. A one percent increase in the assumed health care cost trend rate for the Company would increase the postretirement benefit obligation by $0.8 million at December 31, 2016 and by $0.8 million at December 31, 2015. A one percent decrease in the assumed health care cost trend rate for the Company would decrease the postretirement benefit obligation by $0.7 million at December 31, 2016 and by $0.7 million at December 31, 2015. A one percent increase in the assumed health care cost trend rate for Consolidated SCE&G would increase the postretirement benefit obligation by $0.6 million at December 31, 2016 and by $0.6 million at December 31, 2015. A one percent decrease in the assumed health care cost trend rate for Consolidated SCE&G would decrease the postretirement benefit obligation by $0.6 million at December 31, 2016 and by $0.6 million at December 31, 2015. Funded Status The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2016 2015 2016 2015 2016 2015 2016 2015 Fair value of plan assets $ 793.6 $ 781.7 — — $ 732.9 $ 720.1 — — Benefit obligation 904.3 855.4 $ 274.7 $ 253.6 768.4 724.0 $ 207.2 $ 191.7 Funded status $ (110.7 ) $ (73.7 ) $ (274.7 ) $ (253.6 ) $ (35.5 ) $ (3.9 ) $ (207.2 ) $ (191.7 ) 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, 2016 2015 2016 2015 2016 2015 2016 2015 Current liability — — $ (12.6 ) $ (11.9 ) — — $ (10.4 ) $ (9.8 ) Noncurrent liability $ (110.7 ) $ (73.7 ) (262.1 ) (241.7 ) $ (35.5 ) $ (3.9 ) (196.8 ) (181.9 ) 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, 2016 2015 2016 2015 2016 2015 2016 2015 Net actuarial loss $ 10.4 $ 10.4 $ 2.5 $ 1.7 $ 1.9 $ 2.0 $ 1.0 $ 0.7 Prior service cost 0.1 0.2 — — — — — — Total $ 10.5 $ 10.6 $ 2.5 $ 1.7 $ 1.9 $ 2.0 $ 1.0 $ 0.7 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, 2016 2015 2016 2015 2016 2015 2016 2015 Net actuarial loss $ 236.1 $ 219.4 $ 34.7 $ 24.0 $ 208.8 $ 193.7 $ 29.3 $ 20.4 Prior service cost 2.5 5.9 — 0.3 2.2 5.2 — 0.2 Total $ 238.6 $ 225.3 $ 34.7 $ 24.3 $ 211.0 $ 198.9 $ 29.3 $ 20.6 In connection with the joint ownership of Summer Station, pension costs attributable to Santee Cooper as of December 31, 2016 and 2015 totaled $23.4 million and $20.3 million, respectively, and was recorded within deferred debits. The unfunded postretirement benefit obligation attributable to Santee Cooper as of December 31, 2016 and 2015 totaled $15.8 million and $13.8 million, respectively, and also was recorded within deferred debits. Changes in Fair Value of Plan Assets The Company Consolidated SCE&G Pension Benefits Pension Benefits Millions of dollars 2016 2015 2016 2015 Fair value of plan assets, January 1 $ 781.7 $ 861.8 $ 720.1 $ 783.6 Actual return (loss) on plan assets 68.1 (16.1 ) 60.5 (9.3 ) Benefits paid (56.2 ) (64.0 ) (47.7 ) (54.2 ) Fair value of plan assets, December 31 $ 793.6 $ 781.7 $ 732.9 $ 720.1 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, 2016 and 2015 and the target allocation for 2017 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2017 2016 2015 Equity Securities 58 % 57 % 57 % Fixed Income 33 % 32 % 32 % Hedge Funds 9 % 11 % 11 % For 2017, the expected long-term rate of return on assets will be 7.25% . 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, 2016 and 2015, 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 2016 2015 2016 2015 Investments with fair value measure at Level 2: Mutual funds $ 125 $ 125 $ 115 $ 115 Short-term investment vehicles 16 14 15 12 US Treasury securities 18 22 17 20 Corporate debt securities 82 78 76 72 Municipals 14 14 13 13 Total assets in the fair value hierarchy 255 253 236 232 Investments at net asset value: Common collective trust 453 413 418 381 Joint venture interests 86 83 79 77 Limited partnership — 33 — 30 Total investments at fair value $ 794 $ 782 $ 733 $ 720 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 2016 or 2015. In addition, in 2015 the fair value of pension plan assets totaling $413 million for the Company and $381 million for Consolidated SCE&G were previously depicted as mutual funds but have been reclassified as Common collective trust for the current presentation. 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 assets 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 2017 $ 63.1 $ 12.9 $ 63.1 $ 10.6 2018 65.1 13.7 65.1 11.2 2019 64.5 14.5 64.5 11.9 2020 64.7 15.3 64.7 12.5 2021 67.1 15.9 67.1 13.1 2022-2026 324.4 86.0 324.4 70.5 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 2016 2015 2014 2016 2015 2014 Service cost $ 20.7 $ 24.1 $ 20.0 $ 4.4 $ 5.3 $ 4.6 Interest cost 39.4 38.2 40.4 12.1 11.4 12.0 Expected return on assets (55.9 ) (62.0 ) (66.7 ) n/a n/a n/a Prior service cost amortization 3.9 4.1 4.1 0.3 0.4 0.3 Amortization of actuarial losses 14.8 13.6 4.8 0.5 2.1 — Net periodic benefit cost $ 22.9 $ 18.0 $ 2.6 $ 17.3 $ 19.2 $ 16.9 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2016 2015 2014 2016 2015 2014 Service cost $ 16.9 $ 19.3 $ 16.0 $ 3.6 $ 4.4 $ 3.6 Interest cost 33.4 32.2 34.1 9.9 9.4 9.4 Expected return on assets (47.4 ) (52.2 ) (56.3 ) n/a n/a n/a Prior service cost amortization 3.4 3.4 3.5 0.3 0.3 0.3 Amortization of actuarial losses 12.5 11.4 4.0 0.4 1.7 — Net periodic benefit cost $ 18.8 $ 14.1 $ 1.3 $ 14.2 $ 15.8 $ 13.3 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 2016 2015 2014 2016 2015 2014 Current year actuarial (gain) loss $ 0.6 $ 2.7 $ 3.1 $ 0.8 $ (1.2 ) $ 1.3 Amortization of actuarial losses (0.6 ) (0.4 ) (0.2 ) — (0.1 ) — Amortization of prior service cost (0.1 ) (0.1 ) (0.2 ) — (0.1 ) — Total recognized in OCI $ (0.1 ) $ 2.2 $ 2.7 $ 0.8 $ (1.4 ) $ 1.3 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2016 2015 2014 2016 2015 2014 Current year actuarial (gain) loss — $ 0.2 $ 0.2 $ 0.3 $ (0.3 ) $ 0.4 Amortization of actuarial losses $ (0.1 ) (0.1 ) (0.1 ) — — — Amortization of prior service cost — (0.1 ) (0.1 ) — — — Total recognized in OCI $ (0.1 ) $ — $ — $ 0.3 $ (0.3 ) $ 0.4 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 2016 2015 2014 2016 2015 2014 Current year actuarial (gain) loss $ 29.4 $ 9.2 $ 101.3 $ 11.1 $ (18.0 ) $ 19.4 Amortization of actuarial losses (12.7 ) (11.9 ) (4.0 ) (0.4 ) (1.8 ) — Amortization of prior service cost (3.4 ) (3.7 ) (3.2 ) (0.3 ) (0.3 ) (0.3 ) Total recognized in regulatory assets $ 13.3 $ (6.4 ) $ 94.1 $ 10.4 $ (20.1 ) $ 19.1 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2016 2015 2014 2016 2015 2014 Current year actuarial (gain) loss $ 26.3 $ 12.2 $ 87.7 $ 9.2 $ (14.0 ) $ 15.8 Amortization of actuarial losses (11.2 ) (10.4 ) (3.5 ) (0.3 ) (1.5 ) — Amortization of prior service cost (3.0 ) (3.1 ) (2.8 ) (0.2 ) (0.3 ) (0.2 ) Total recognized in regulatory assets $ 12.1 $ (1.3 ) $ 81.4 $ 8.7 $ (15.8 ) $ 15.6 Significant Assumptions Used in Determining Net Periodic Benefit Cost Pension Benefits Other Postretirement Benefits 2016 2015 2014 2016 2015 2014 Discount rate 4.68 % 4.20 % 5.03 % 4.78 % 4.30 % 5.19 % Expected return on plan assets 7.50 % 7.50 % 8.00 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % 3.75 % Health care cost trend rate n/a n/a n/a 7.00 % 7.00 % 7.40 % 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 2020 2020 The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2017 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant : Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 0.6 $ 0.1 Prior service cost 0.1 — Total $ 0.7 $ 0.1 The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2017 are as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Actuarial loss $ 13.6 $ 1.2 $ 12.0 $ 1.0 Prior service cost 1.4 — 1.3 — Total $ 15.0 $ 1.2 $ 13.3 $ 1.0 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 $27.5 million in 2016, $26.2 million in 2015 and $25.8 million in 2014. These matching contributions included those made by Consolidated SCE&G, which totaled $22.9 million in 2016, $21.8 million in 2015 and $20.7 million in 2014. 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 2016 2015 2016 2015 2016 2015 2016 2015 Benefit obligation, January 1 $ 855.4 $ 919.5 $ 253.6 $ 268.2 $ 724.0 $ 773.7 $ 191.7 $ 204.1 Service cost 20.7 24.1 4.4 5.3 16.9 19.3 3.6 4.4 Interest cost 39.4 38.2 12.1 11.4 33.4 32.2 9.9 9.4 Plan participants’ contributions — — 1.7 2.4 — — 1.3 1.9 Actuarial (gain) loss 45.0 (62.4 ) 14.0 (21.2 ) 41.8 (47.0 ) 11.5 (15.7 ) Benefits paid (56.2 ) (64.0 ) (11.1 ) (12.5 ) (47.7 ) (54.2 ) (9.1 ) (10.3 ) Amounts Funded to parent n/a n/a n/a n/a — — (1.7 ) (2.1 ) Benefit obligation, December 31 $ 904.3 $ 855.4 $ 274.7 $ 253.6 $ 768.4 $ 724.0 $ 207.2 $ 191.7 In 2015, based on an evaluation of the mortality experience of the pension plan, a custom mortality table was adopted for purposes of measuring pension and other postretirement benefit obligations at year-end. This change resulted in an actuarial gain for pension and other postretirement benefit obligations for the Company of approximately $21.5 million and $2.4 million , respectively. This change resulted in an actuarial gain for pension and other postretirement benefit obligations for Consolidated SCE&G of approximately $18.2 million and $2.0 million , respectively. The accumulated benefit obligation for pension benefits for the Company was $ 874.3 million at the end of 2016 and $ 829.3 million at the end of 2015. The accumulated benefit obligation for pension benefits for Consolidated SCE&G was $742.9 million at the end of 2016 and $702.0 million at the end of 2015.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 2016 2015 2016 2015 Annual discount rate used to determine benefit obligation 4.22 % 4.68 % 4.30 % 4.78 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 % A 6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017. The rate was assumed to decrease gradually to 5.0% for 2021 and to remain at that level thereafter. A one percent increase in the assumed health care cost trend rate for the Company would increase the postretirement benefit obligation by $0.8 million at December 31, 2016 and by $0.8 million at December 31, 2015. A one percent decrease in the assumed health care cost trend rate for the Company would decrease the postretirement benefit obligation by $0.7 million at December 31, 2016 and by $0.7 million at December 31, 2015. A one percent increase in the assumed health care cost trend rate for Consolidated SCE&G would increase the postretirement benefit obligation by $0.6 million at December 31, 2016 and by $0.6 million at December 31, 2015. A one percent decrease in the assumed health care cost trend rate for Consolidated SCE&G would decrease the postretirement benefit obligation by $0.6 million at December 31, 2016 and by $0.6 million at December 31, 2015. Funded Status The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2016 2015 2016 2015 2016 2015 2016 2015 Fair value of plan assets $ 793.6 $ 781.7 — — $ 732.9 $ 720.1 — — Benefit obligation 904.3 855.4 $ 274.7 $ 253.6 768.4 724.0 $ 207.2 $ 191.7 Funded status $ (110.7 ) $ (73.7 ) $ (274.7 ) $ (253.6 ) $ (35.5 ) $ (3.9 ) $ (207.2 ) $ (191.7 ) 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, 2016 2015 2016 2015 2016 2015 2016 2015 Current liability — — $ (12.6 ) $ (11.9 ) — — $ (10.4 ) $ (9.8 ) Noncurrent liability $ (110.7 ) $ (73.7 ) (262.1 ) (241.7 ) $ (35.5 ) $ (3.9 ) (196.8 ) (181.9 ) 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, 2016 2015 2016 2015 2016 2015 2016 2015 Net actuarial loss $ 10.4 $ 10.4 $ 2.5 $ 1.7 $ 1.9 $ 2.0 $ 1.0 $ 0.7 Prior service cost 0.1 0.2 — — — — — — Total $ 10.5 $ 10.6 $ 2.5 $ 1.7 $ 1.9 $ 2.0 $ 1.0 $ 0.7 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, 2016 2015 2016 2015 2016 2015 2016 2015 Net actuarial loss $ 236.1 $ 219.4 $ 34.7 $ 24.0 $ 208.8 $ 193.7 $ 29.3 $ 20.4 Prior service cost 2.5 5.9 — 0.3 2.2 5.2 — 0.2 Total $ 238.6 $ 225.3 $ 34.7 $ 24.3 $ 211.0 $ 198.9 $ 29.3 $ 20.6 In connection with the joint ownership of Summer Station, pension costs attributable to Santee Cooper as of December 31, 2016 and 2015 totaled $23.4 million and $20.3 million, respectively, and was recorded within deferred debits. The unfunded postretirement benefit obligation attributable to Santee Cooper as of December 31, 2016 and 2015 totaled $15.8 million and $13.8 million, respectively, and also was recorded within deferred debits. Changes in Fair Value of Plan Assets The Company Consolidated SCE&G Pension Benefits Pension Benefits Millions of dollars 2016 2015 2016 2015 Fair value of plan assets, January 1 $ 781.7 $ 861.8 $ 720.1 $ 783.6 Actual return (loss) on plan assets 68.1 (16.1 ) 60.5 (9.3 ) Benefits paid (56.2 ) (64.0 ) (47.7 ) (54.2 ) Fair value of plan assets, December 31 $ 793.6 $ 781.7 $ 732.9 $ 720.1 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, 2016 and 2015 and the target allocation for 2017 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2017 2016 2015 Equity Securities 58 % 57 % 57 % Fixed Income 33 % 32 % 32 % Hedge Funds 9 % 11 % 11 % For 2017, the expected long-term rate of return on assets will be 7.25% . 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, 2016 and 2015, 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 2016 2015 2016 2015 Investments with fair value measure at Level 2: Mutual funds $ 125 $ 125 $ 115 $ 115 Short-term investment vehicles 16 14 15 12 US Treasury securities 18 22 17 20 Corporate debt securities 82 78 76 72 Municipals 14 14 13 13 Total assets in the fair value hierarchy 255 253 236 232 Investments at net asset value: Common collective trust 453 413 418 381 Joint venture interests 86 83 79 77 Limited partnership — 33 — 30 Total investments at fair value $ 794 $ 782 $ 733 $ 720 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 2016 or 2015. In addition, in 2015 the fair value of pension plan assets totaling $413 million for the Company and $381 million for Consolidated SCE&G were previously depicted as mutual funds but have been reclassified as Common collective trust for the current presentation. 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 assets 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 2017 $ 63.1 $ 12.9 $ 63.1 $ 10.6 2018 65.1 13.7 65.1 11.2 2019 64.5 14.5 64.5 11.9 2020 64.7 15.3 64.7 12.5 2021 67.1 15.9 67.1 13.1 2022-2026 324.4 86.0 324.4 70.5 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 2016 2015 2014 2016 2015 2014 Service cost $ 20.7 $ 24.1 $ 20.0 $ 4.4 $ 5.3 $ 4.6 Interest cost 39.4 38.2 40.4 12.1 11.4 12.0 Expected return on assets (55.9 ) (62.0 ) (66.7 ) n/a n/a n/a Prior service cost amortization 3.9 4.1 4.1 0.3 0.4 0.3 Amortization of actuarial losses 14.8 13.6 4.8 0.5 2.1 — Net periodic benefit cost $ 22.9 $ 18.0 $ 2.6 $ 17.3 $ 19.2 $ 16.9 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2016 2015 2014 2016 2015 2014 Service cost $ 16.9 $ 19.3 $ 16.0 $ 3.6 $ 4.4 $ 3.6 Interest cost 33.4 32.2 34.1 9.9 9.4 9.4 Expected return on assets (47.4 ) (52.2 ) (56.3 ) n/a n/a n/a Prior service cost amortization 3.4 3.4 3.5 0.3 0.3 0.3 Amortization of actuarial losses 12.5 11.4 4.0 0.4 1.7 — Net periodic benefit cost $ 18.8 $ 14.1 $ 1.3 $ 14.2 $ 15.8 $ 13.3 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 2016 2015 2014 2016 2015 2014 Current year actuarial (gain) loss $ 0.6 $ 2.7 $ 3.1 $ 0.8 $ (1.2 ) $ 1.3 Amortization of actuarial losses (0.6 ) (0.4 ) (0.2 ) — (0.1 ) — Amortization of prior service cost (0.1 ) (0.1 ) (0.2 ) — (0.1 ) — Total recognized in OCI $ (0.1 ) $ 2.2 $ 2.7 $ 0.8 $ (1.4 ) $ 1.3 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2016 2015 2014 2016 2015 2014 Current year actuarial (gain) loss — $ 0.2 $ 0.2 $ 0.3 $ (0.3 ) $ 0.4 Amortization of actuarial losses $ (0.1 ) (0.1 ) (0.1 ) — — — Amortization of prior service cost — (0.1 ) (0.1 ) — — — Total recognized in OCI $ (0.1 ) $ — $ — $ 0.3 $ (0.3 ) $ 0.4 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 2016 2015 2014 2016 2015 2014 Current year actuarial (gain) loss $ 29.4 $ 9.2 $ 101.3 $ 11.1 $ (18.0 ) $ 19.4 Amortization of actuarial losses (12.7 ) (11.9 ) (4.0 ) (0.4 ) (1.8 ) — Amortization of prior service cost (3.4 ) (3.7 ) (3.2 ) (0.3 ) (0.3 ) (0.3 ) Total recognized in regulatory assets $ 13.3 $ (6.4 ) $ 94.1 $ 10.4 $ (20.1 ) $ 19.1 Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2016 2015 2014 2016 2015 2014 Current year actuarial (gain) loss $ 26.3 $ 12.2 $ 87.7 $ 9.2 $ (14.0 ) $ 15.8 Amortization of actuarial losses (11.2 ) (10.4 ) (3.5 ) (0.3 ) (1.5 ) — Amortization of prior service cost (3.0 ) (3.1 ) (2.8 ) (0.2 ) (0.3 ) (0.2 ) Total recognized in regulatory assets $ 12.1 $ (1.3 ) $ 81.4 $ 8.7 $ (15.8 ) $ 15.6 Significant Assumptions Used in Determining Net Periodic Benefit Cost Pension Benefits Other Postretirement Benefits 2016 2015 2014 2016 2015 2014 Discount rate 4.68 % 4.20 % 5.03 % 4.78 % 4.30 % 5.19 % Expected return on plan assets 7.50 % 7.50 % 8.00 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % 3.75 % Health care cost trend rate n/a n/a n/a 7.00 % 7.00 % 7.40 % 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 2020 2020 The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2017 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant : Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 0.6 $ 0.1 Prior service cost 0.1 — Total $ 0.7 $ 0.1 The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2017 are as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Actuarial loss $ 13.6 $ 1.2 $ 12.0 $ 1.0 Prior service cost 1.4 — 1.3 — Total $ 15.0 $ 1.2 $ 13.3 $ 1.0 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 $27.5 million in 2016, $26.2 million in 2015 and $25.8 million in 2014. These matching contributions included those made by Consolidated SCE&G, which totaled $22.9 million in 2016, $21.8 million in 2015 and $20.7 million in 2014. 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, 2016
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 2014-2016 performance cycle provides for performance measurement and award determination on an annual basis, with payment of awards being deferred until after the end of the three -year performance cycle. The 2015-2017 and 2016-2018 awards are based on performance over a single three -year cycle. In the performance cycle for the 2014-2016 awards, 20% of the performance awards were granted in the form of restricted share units, which are liability awards payable in cash, and 80% 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. For each of the 2015-2017 and 2016-2018 awards, 30% are in the form of restricted share units and 70% are in the form of performance shares. 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. At the Company's discretion, awards under the 2014-2016 performance cycle were paid in cash in February 2017 totaling $ 28.0 million for the Company, of which $ 20.2 million was attributable to Consolidated SCE&G (including amounts allocated from SCANA Services). Cash-settled liabilities related to earlier performance cycles totaled approximately $ 18.4 million in 2016, $ 20.8 million in 2015 and $ 11.8 million in 2014 for the Company and approximately $ 13.2 million in 2016, $ 6.3 million in 2015 and $ 1.9 million in 2014 for Consolidated SCE&G. Fair value adjustments for all performance cycles resulted in compensation expense recognized in the statements of income totaling approximately $ 25.6 million in 2016, $ 18.0 million in 2015 and $ 20.3 million in 2014 for the Company, of which approximately $ 17.3 million in 2016, $ 12.2 million in 2015 and $ 12.6 million in 2014 for Consolidated SCE&G (including amounts allocated from SCANA Services). Such fair value adjustments also resulted in capitalized compensation costs of $ 3.3 million in 2016, $ 2.3 million in 2015 and $ 3.1 million in 2014 for the Company and $ 3.1 million in 2016, $ 0.6 million in 2015 and $ 0.6 million in 2014 for Consolidated SCE&G. At December 31, 2016, unrecognized compensation cost, which is expected to be recognized over a weighted-average period of 18 months , was $ 23.4 million for the Company and $ 17.2 million for Consolidated SCE&G.
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 2014-2016 performance cycle provides for performance measurement and award determination on an annual basis, with payment of awards being deferred until after the end of the three -year performance cycle. The 2015-2017 and 2016-2018 awards are based on performance over a single three -year cycle. In the performance cycle for the 2014-2016 awards, 20% of the performance awards were granted in the form of restricted share units, which are liability awards payable in cash, and 80% 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. For each of the 2015-2017 and 2016-2018 awards, 30% are in the form of restricted share units and 70% are in the form of performance shares. 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. At the Company's discretion, awards under the 2014-2016 performance cycle were paid in cash in February 2017 totaling $ 28.0 million for the Company, of which $ 20.2 million was attributable to Consolidated SCE&G (including amounts allocated from SCANA Services). Cash-settled liabilities related to earlier performance cycles totaled approximately $ 18.4 million in 2016, $ 20.8 million in 2015 and $ 11.8 million in 2014 for the Company and approximately $ 13.2 million in 2016, $ 6.3 million in 2015 and $ 1.9 million in 2014 for Consolidated SCE&G. Fair value adjustments for all performance cycles resulted in compensation expense recognized in the statements of income totaling approximately $ 25.6 million in 2016, $ 18.0 million in 2015 and $ 20.3 million in 2014 for the Company, of which approximately $ 17.3 million in 2016, $ 12.2 million in 2015 and $ 12.6 million in 2014 for Consolidated SCE&G (including amounts allocated from SCANA Services). Such fair value adjustments also resulted in capitalized compensation costs of $ 3.3 million in 2016, $ 2.3 million in 2015 and $ 3.1 million in 2014 for the Company and $ 3.1 million in 2016, $ 0.6 million in 2015 and $ 0.6 million in 2014 for Consolidated SCE&G. At December 31, 2016, unrecognized compensation cost, which is expected to be recognized over a weighted-average period of 18 months , was $ 23.4 million for the Company and $ 17.2 million for Consolidated SCE&G.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2016
Commitment [Line Items]
Commitments and Contingencies Disclosure [Text Block]	10. COMMITMENTS AND CONTINGENCIES Nuclear Insurance Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper, a one-third owner of Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at SCE&G’s nuclear power plant. Price-Anderson provides funds up to $13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is currently liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.33 billion resulting from an event of a non-nuclear origin. In addition, a builder’s risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.8 million . SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $1.8 million . To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear or other incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position. New Nuclear Construction SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium in 2008 for the design and construction of the New Units. SCE&G's current ownership share in the New Units is 55%. As discussed below, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. EPC Contract and BLRA Matters The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are 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 New Units. Estimated operating costs, including the depreciation of the utility plant costs, are then to be recovered through rates beginning when the construction of each New Unit is completed and placed into service. The BLRA also provides that, in the event of abandonment prior to plant completion, construction work in progress costs incurred, including AFC, and a return on those costs may be recoverable through rates, so long as SCE&G demonstrates by a preponderance of the evidence that its decision to abandon the New Unit(s) was prudent. As of December 31, 2016, SCE&G’s investment in the New Units, including related transmission, totaled $4.5 billion , for which the financing costs on $3.8 billion have been reflected in rates under the BLRA. See Note 2 for a description of rate changes which have occurred under the BLRA. The SCPSC granted initial approval of the construction schedule and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. The Consortium has experienced delays throughout much of the project to date, and forecasted work crew efficiency and productivity metrics have not been met. In response, 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. Some of these increased costs were the result of the schedule delays and were the subject of dispute. 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 October 2015 Amendment became effective in December 2015, upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I. Following that acquisition, Stone & Webster continues to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC has engaged Fluor as a subcontracted construction manager. Among other things, the October 2015 Amendment provided SCE&G and Santee Cooper an irrevocable 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, executed the fixed price option, subject to SCPSC approval, on July 1, 2016. The October 2015 Amendment: (i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium, (ii) revised the contractual guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively, (iii) revised the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn Internal Revenue Code Section 45J production tax credits (see also below), resulting in escalating liquidated damages that are capped at an aggregate of $338 million per New Unit (SCE&G’s 55% portion being approximately $186 million per New Unit), (iv) provided for payment to the Consortium of a completion bonus of $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits, (v) provided for development of a revised construction milestone payment schedule, (vi) provided that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project, (vii) provided for an explicit definition of Change in Law designed to reduce the likelihood of certain future commercial disputes, with the Consortium also acknowledging and agreeing that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19, and (viii) eliminated the requirement or ability of any party to bring suit regarding disputes before substantial completion of the project. As part of its responsibility as a subcontracted construction manager, Fluor has reviewed and assisted in the development of an updated integrated project schedule which reflects WEC’s revised estimated completion dates of April 2020 and December 2020 for Units 2 and 3, respectively. These later dates remain within the SCPSC-approved 18-month contingency periods provided for under the BLRA, and achievement of such dates would also allow the output of both units to qualify, under current law, for federal production tax credits (see below). However, there is substantial uncertainty as to WEC’s ability to meet these dates given its historical inability to achieve forecasted productivity and work force efficiency levels. November 2016 SCPSC Order In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for the New Units which were developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option. See also Note 2. The approved construction schedule designates contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Units 2 and 3, respectively. The approved capital cost schedule includes incremental capital costs that total $831 million . SCE&G’s total project capital cost is now estimated at 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 new nuclear construction from 10.5% to 10.25%. This revised ROE will 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 may not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request is denied because SCE&G is out of compliance with its approved capital cost schedule or BLRA construction milestone schedule. In most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. On December 14, 2016, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement. These parties may appeal this decision to the South Carolina Supreme Court once the SCPSC’s order has been issued. SCE&G cannot determine when the SCPSC will issue its order in this matter or if that order will be appealed. Construction Milestone Payment Schedule and Related DRB Activity The October 2015 Amendment established a DRB process for resolving certain commercial claims and disputes. The DRB is comprised of three members chosen by the parties, and amounts in dispute of less than $5 million will be resolved by the DRB without recourse. Amounts in dispute greater than $5 million will be resolved by the DRB for the remainder of the construction of the New Units, with a reserved right to further arbitrate or to litigate such issues at the conclusion of construction. On December 2, 2016 the DRB issued an order establishing a construction milestone payment schedule (see (v) in October 2015 Amendment above) on which SCE&G and WEC had been unable to agree subsequent to the October 2015 Amendment. The dispute related only to the timing of payments; the total amount to be paid was not in dispute. The DRB order provides that certain subcontractor and other supplier-related costs incurred by the Consortium will be reimbursed by the owners regardless of payment-milestone completion, but that other payments will be made only upon documented achievement of the agreed-upon payment-milestones. Such subcontractor and other supplier-related costs comprised approximately $873 million of the $3.345 billion of fixed option payments that were the subject of the DRB order. Payment and Performance Obligations and Certain Related Uncertainties Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and in connection with the October 2015 Amendment, Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Additionally, the EPC Contract provides the owners the right, exercisable upon certain conditions, to obtain payment and performance bonds from WEC equal to 15% of the highest projected three months billings during the applicable year, and their aggregate nominal coverage will not excee d $100 million (or $55 million for SCE&G's 55% share). SCE&G and Santee Cooper are responsible for the cost of the bonds. In late 2015, Toshiba's credit ratings declined to below investment grade following disclosures regarding its operating and financial performance and near-term liquidity. As a result, pursuant to the above-described terms of the EPC Contract, SCE&G has obtained standby letters of credit in lieu of payment and performance bonds from WEC totalin g $45 million (or approximatel y $25 million for SCE&G's 55% share). These standby letters of credit expire annually in February, and they automatically renew for successive one-year periods until their final expiration date of August 31, 2020, unless the issuer provides a minimum 60-day notice that it will not renew. If the issuer provides notice that it will not renew, SCE&G may draw upon the standby letter of credit prior to its expiration. In the event that WEC would be unable to meet its payment and performance obligations under the EPC Contract, it is anticipated this funding would provide a source of liquidity to assist in an orderly transition. In addition, the EPC Contract provides that upon the request of SCE&G, and at owners' cost, the Consortium must escrow certain intellectual property and software for the owners' benefit to assist in completion of the New Units. An escrow arrangement has been established, and certain intellectual property and software have been deposited. Additional deposits are anticipated. In December 2016 through February 2017, Toshiba and WEC announced further deterioration in their financial position and liquidity related to write-downs arising from WEC’s acquisition of Stone and Webster from CB&I (discussed above). The announcements noted that WEC and Toshiba have determined that significant losses will be incurred under the EPC Contract for the New Units and under a similar engineering, procurement and construction agreement for other units currently being constructed in the United States. This determination has impacted their allocation of the CB&I purchase price, resulting in recognition of a large amount of goodwill which has in turn been determined to be impaired. Preliminary recognition of this impairment loss (in excess of $6 billion ) has left Toshiba with negative shareholders' equity and threatened its liquidity. In January 2017, Toshiba’s credit ratings were further reduced. In response, Toshiba has indicated its interest in monetizing portions of its business as it attempts to restructure and restore its financial position. Toshiba has also indicated that it will withdraw from the nuclear construction business prospectively and that it will significantly alter its risk management oversight of its nuclear power business. WEC has told the Company that it and Toshiba are committed to completing the New Units. Toshiba has acknowledged its parental guaranty to the project, but it has informed the Company that no specific commitment regarding completion of the New Units has been agreed to by it so far. Toshiba also announced that it had requested (and successfully received) a one-month extension of the deadline for submitting its securities report to Japanese securities regulators for the quarter ended December 31, 2016 to allow an internal investigation into the adequacy of internal controls relating to the purchase price allocation process for WEC’s acquisition of Stone & Webster and concerns that senior management at WEC may have exerted inappropriate pressure in order to advance the purchase price allocation process. As part of the announcement, it was stated that Toshiba’s audit committee was concerned that an invalidation of internal controls (or even the possibility thereof) might affect Toshiba’s quarterly financial statements, and that two law firms had been separately retained by the audit committee and WEC to assist with this investiga tion. Although progress o n the project was seen in December 2016 and January 2017, including the placement of the first of Unit 2’s two steam generators, significant risks and uncertainties remain concerning WEC’s ability to improve work force efficiency and productivity performance and to continue to fulfill its performance and financial commitments and Toshiba's ability to perform under its payment guaranty with respect to the project. In particular, there can be no assurance that their creditors will continue to provide support or that other sources of liquidity will emerge or continue to be available. In the event that WEC were to fail to complete the project in breach of its obligations under the EPC Contract, its payment obligations for damages would increase substantially above the amount of the liquidated damages described above, but would still be subject to limitations. SCE&G and Santee Cooper, the co-owner of the New Units, continue to evaluate various actions which might be taken in the event that Toshiba and WEC are unable or unwilling to complete the project. These include completing the work under possible arrangements with other contractors or, were it determined to be prudent, halting the project and leaving SCE&G to pursue cost recovery under the abandonment provisions of the BLRA. Also, in response to these developments and in light of the DRB-established construction milestone payment schedule, in February 2017, SCE&G initiated its solicitation for increased levels of standby letters of credit in lieu of payment and performance bonds referred to above. However, it is uncertain whether such additional levels of standby letters of credit will be available at reasonable cost or whether any letters of credit will continue to be renewed by their issuers. Finally, additional claims by the Consortium or SCE&G involving the project schedule, budget and performance may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues, and SCE&G expects to resolve disputes through those means. SCE&G expects to seek recovery through rates of any project costs that arise through such dispute resolution processes, as well as other project costs identified from time to time; however, any such request would be subject to the provisions of the November 2016 SCPSC order discussed above. There can be no assurance that recovery would be granted. Santee Cooper Matters As noted above, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction is subject to customary closing conditions, including receipt of necessary regulatory approvals. This transaction will not affect the payment obligations between the parties during construction of the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. SCE&G’s current projected cost for the additional 5% interest being acquired from Santee Cooper is approximately $850 million . Nuclear Production Tax Credits The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the IRC to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion . Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on current tax law and the contractual guaranteed substantial completion dates (and the recently revised forecasted dates of completion) provided above, both New Units would be operational and would qualify for the nuclear production tax credits; however, any further delays in the schedule or changes in tax law could adversely impact these conclusions. See also the Payment and Performance Obligations and Certain Related Uncertainties discussion above. When and to the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers. Other Project Matters When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation. SCE&G prepared and submitted an overall integration plan for the New Units to the NRC in August 2013. That plan remains under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units. Environmental The Company's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on the Company's and Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, the Company and Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company and Consolidated SCE&G expect to recover such expenditures and costs through existing ratemaking provisions. From a regulatory perspective, SCANA, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the SO 2 and NO X emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein. On August 3, 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO 2 from newly constructed fossil fuel-fired units. The final rule requires all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds CO 2 per MWh and new natural gas units to meet 1,000 pounds CO 2 per MWh. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G are monitoring the final rule, but do not plan to construct new coal-fired units in the foreseeable future. In addition, on August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national CO 2 emissions by 32% from 2005 levels by 2030. The rule also provides for nuclear reactors under construction, such as the New Units, to count towards compliance and establishes a phased-in compliance approach beginning in 2022. The rule gives each state from one to three years to issue SIPs, which will ultimately define the specific compliance methodology that will be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. The order of the Supreme Court has no immediate impact on SCE&G and GENCO or their generation operations. The Company and Consolidated SCE&G expect any costs incurred to comply with such rule to be recoverable through rates. In July 2011, the EPA issued the CSAPR to reduce emissions of SO 2 and NO X from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO 2 emissions and annual and ozone season NO X emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO 2 and NO X and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates. In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G and GENCO are in compliance with the MATS rule and expect to remain in compliance. The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule became effective on January 4, 2016. After this date, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five year permit cycle and thus may range from 2018 to 2023. The Company and Consolidated SCE&G expect that wastewater treatment technology retrofits will be required at Williams and Wateree Stations. Any costs incurred to comply with the ELG Rule are expected to be recoverable through rates. The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications to ensure compliance with this rule. Any costs incurred to comply with this rule are expected to be recoverable through rates. The EPA's final rule for CCR became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at SCE&G's and GENCO's coal-fired generating facilities. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. The Company and Consolidated SCE&G do not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future rates. The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2016, the federal government has not accepted any spent fuel from Unit 1, and it remains unclear when the repository may become available. SCE&G has constructed an independent spent fuel storage installation to accommodate the spent nuclear fuel output for the life of Unit 1. SCE&G may evaluate other technology as it becomes available. The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates. SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least
SCE&G
Commitment [Line Items]
Commitments and Contingencies Disclosure [Text Block]	10. COMMITMENTS AND CONTINGENCIES Nuclear Insurance Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper, a one-third owner of Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at SCE&G’s nuclear power plant. Price-Anderson provides funds up to $13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is currently liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.33 billion resulting from an event of a non-nuclear origin. In addition, a builder’s risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.8 million . SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $1.8 million . To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear or other incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position. New Nuclear Construction SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium in 2008 for the design and construction of the New Units. SCE&G's current ownership share in the New Units is 55%. As discussed below, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. EPC Contract and BLRA Matters The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are 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 New Units. Estimated operating costs, including the depreciation of the utility plant costs, are then to be recovered through rates beginning when the construction of each New Unit is completed and placed into service. The BLRA also provides that, in the event of abandonment prior to plant completion, construction work in progress costs incurred, including AFC, and a return on those costs may be recoverable through rates, so long as SCE&G demonstrates by a preponderance of the evidence that its decision to abandon the New Unit(s) was prudent. As of December 31, 2016, SCE&G’s investment in the New Units, including related transmission, totaled $4.5 billion , for which the financing costs on $3.8 billion have been reflected in rates under the BLRA. See Note 2 for a description of rate changes which have occurred under the BLRA. The SCPSC granted initial approval of the construction schedule and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. The Consortium has experienced delays throughout much of the project to date, and forecasted work crew efficiency and productivity metrics have not been met. In response, 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. Some of these increased costs were the result of the schedule delays and were the subject of dispute. 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 October 2015 Amendment became effective in December 2015, upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I. Following that acquisition, Stone & Webster continues to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC has engaged Fluor as a subcontracted construction manager. Among other things, the October 2015 Amendment provided SCE&G and Santee Cooper an irrevocable 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, executed the fixed price option, subject to SCPSC approval, on July 1, 2016. The October 2015 Amendment: (i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium, (ii) revised the contractual guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively, (iii) revised the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn Internal Revenue Code Section 45J production tax credits (see also below), resulting in escalating liquidated damages that are capped at an aggregate of $338 million per New Unit (SCE&G’s 55% portion being approximately $186 million per New Unit), (iv) provided for payment to the Consortium of a completion bonus of $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits, (v) provided for development of a revised construction milestone payment schedule, (vi) provided that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project, (vii) provided for an explicit definition of Change in Law designed to reduce the likelihood of certain future commercial disputes, with the Consortium also acknowledging and agreeing that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19, and (viii) eliminated the requirement or ability of any party to bring suit regarding disputes before substantial completion of the project. As part of its responsibility as a subcontracted construction manager, Fluor has reviewed and assisted in the development of an updated integrated project schedule which reflects WEC’s revised estimated completion dates of April 2020 and December 2020 for Units 2 and 3, respectively. These later dates remain within the SCPSC-approved 18-month contingency periods provided for under the BLRA, and achievement of such dates would also allow the output of both units to qualify, under current law, for federal production tax credits (see below). However, there is substantial uncertainty as to WEC’s ability to meet these dates given its historical inability to achieve forecasted productivity and work force efficiency levels. November 2016 SCPSC Order In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for the New Units which were developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option. See also Note 2. The approved construction schedule designates contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Units 2 and 3, respectively. The approved capital cost schedule includes incremental capital costs that total $831 million . SCE&G’s total project capital cost is now estimated at 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 new nuclear construction from 10.5% to 10.25%. This revised ROE will 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 may not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request is denied because SCE&G is out of compliance with its approved capital cost schedule or BLRA construction milestone schedule. In most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. On December 14, 2016, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement. These parties may appeal this decision to the South Carolina Supreme Court once the SCPSC’s order has been issued. SCE&G cannot determine when the SCPSC will issue its order in this matter or if that order will be appealed. Construction Milestone Payment Schedule and Related DRB Activity The October 2015 Amendment established a DRB process for resolving certain commercial claims and disputes. The DRB is comprised of three members chosen by the parties, and amounts in dispute of less than $5 million will be resolved by the DRB without recourse. Amounts in dispute greater than $5 million will be resolved by the DRB for the remainder of the construction of the New Units, with a reserved right to further arbitrate or to litigate such issues at the conclusion of construction. On December 2, 2016 the DRB issued an order establishing a construction milestone payment schedule (see (v) in October 2015 Amendment above) on which SCE&G and WEC had been unable to agree subsequent to the October 2015 Amendment. The dispute related only to the timing of payments; the total amount to be paid was not in dispute. The DRB order provides that certain subcontractor and other supplier-related costs incurred by the Consortium will be reimbursed by the owners regardless of payment-milestone completion, but that other payments will be made only upon documented achievement of the agreed-upon payment-milestones. Such subcontractor and other supplier-related costs comprised approximately $873 million of the $3.345 billion of fixed option payments that were the subject of the DRB order. Payment and Performance Obligations and Certain Related Uncertainties Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and in connection with the October 2015 Amendment, Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Additionally, the EPC Contract provides the owners the right, exercisable upon certain conditions, to obtain payment and performance bonds from WEC equal to 15% of the highest projected three months billings during the applicable year, and their aggregate nominal coverage will not excee d $100 million (or $55 million for SCE&G's 55% share). SCE&G and Santee Cooper are responsible for the cost of the bonds. In late 2015, Toshiba's credit ratings declined to below investment grade following disclosures regarding its operating and financial performance and near-term liquidity. As a result, pursuant to the above-described terms of the EPC Contract, SCE&G has obtained standby letters of credit in lieu of payment and performance bonds from WEC totalin g $45 million (or approximatel y $25 million for SCE&G's 55% share). These standby letters of credit expire annually in February, and they automatically renew for successive one-year periods until their final expiration date of August 31, 2020, unless the issuer provides a minimum 60-day notice that it will not renew. If the issuer provides notice that it will not renew, SCE&G may draw upon the standby letter of credit prior to its expiration. In the event that WEC would be unable to meet its payment and performance obligations under the EPC Contract, it is anticipated this funding would provide a source of liquidity to assist in an orderly transition. In addition, the EPC Contract provides that upon the request of SCE&G, and at owners' cost, the Consortium must escrow certain intellectual property and software for the owners' benefit to assist in completion of the New Units. An escrow arrangement has been established, and certain intellectual property and software have been deposited. Additional deposits are anticipated. In December 2016 through February 2017, Toshiba and WEC announced further deterioration in their financial position and liquidity related to write-downs arising from WEC’s acquisition of Stone and Webster from CB&I (discussed above). The announcements noted that WEC and Toshiba have determined that significant losses will be incurred under the EPC Contract for the New Units and under a similar engineering, procurement and construction agreement for other units currently being constructed in the United States. This determination has impacted their allocation of the CB&I purchase price, resulting in recognition of a large amount of goodwill which has in turn been determined to be impaired. Preliminary recognition of this impairment loss (in excess of $6 billion ) has left Toshiba with negative shareholders' equity and threatened its liquidity. In January 2017, Toshiba’s credit ratings were further reduced. In response, Toshiba has indicated its interest in monetizing portions of its business as it attempts to restructure and restore its financial position. Toshiba has also indicated that it will withdraw from the nuclear construction business prospectively and that it will significantly alter its risk management oversight of its nuclear power business. WEC has told the Company that it and Toshiba are committed to completing the New Units. Toshiba has acknowledged its parental guaranty to the project, but it has informed the Company that no specific commitment regarding completion of the New Units has been agreed to by it so far. Toshiba also announced that it had requested (and successfully received) a one-month extension of the deadline for submitting its securities report to Japanese securities regulators for the quarter ended December 31, 2016 to allow an internal investigation into the adequacy of internal controls relating to the purchase price allocation process for WEC’s acquisition of Stone & Webster and concerns that senior management at WEC may have exerted inappropriate pressure in order to advance the purchase price allocation process. As part of the announcement, it was stated that Toshiba’s audit committee was concerned that an invalidation of internal controls (or even the possibility thereof) might affect Toshiba’s quarterly financial statements, and that two law firms had been separately retained by the audit committee and WEC to assist with this investiga tion. Although progress o n the project was seen in December 2016 and January 2017, including the placement of the first of Unit 2’s two steam generators, significant risks and uncertainties remain concerning WEC’s ability to improve work force efficiency and productivity performance and to continue to fulfill its performance and financial commitments and Toshiba's ability to perform under its payment guaranty with respect to the project. In particular, there can be no assurance that their creditors will continue to provide support or that other sources of liquidity will emerge or continue to be available. In the event that WEC were to fail to complete the project in breach of its obligations under the EPC Contract, its payment obligations for damages would increase substantially above the amount of the liquidated damages described above, but would still be subject to limitations. SCE&G and Santee Cooper, the co-owner of the New Units, continue to evaluate various actions which might be taken in the event that Toshiba and WEC are unable or unwilling to complete the project. These include completing the work under possible arrangements with other contractors or, were it determined to be prudent, halting the project and leaving SCE&G to pursue cost recovery under the abandonment provisions of the BLRA. Also, in response to these developments and in light of the DRB-established construction milestone payment schedule, in February 2017, SCE&G initiated its solicitation for increased levels of standby letters of credit in lieu of payment and performance bonds referred to above. However, it is uncertain whether such additional levels of standby letters of credit will be available at reasonable cost or whether any letters of credit will continue to be renewed by their issuers. Finally, additional claims by the Consortium or SCE&G involving the project schedule, budget and performance may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues, and SCE&G expects to resolve disputes through those means. SCE&G expects to seek recovery through rates of any project costs that arise through such dispute resolution processes, as well as other project costs identified from time to time; however, any such request would be subject to the provisions of the November 2016 SCPSC order discussed above. There can be no assurance that recovery would be granted. Santee Cooper Matters As noted above, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction is subject to customary closing conditions, including receipt of necessary regulatory approvals. This transaction will not affect the payment obligations between the parties during construction of the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. SCE&G’s current projected cost for the additional 5% interest being acquired from Santee Cooper is approximately $850 million . Nuclear Production Tax Credits The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the IRC to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion . Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on current tax law and the contractual guaranteed substantial completion dates (and the recently revised forecasted dates of completion) provided above, both New Units would be operational and would qualify for the nuclear production tax credits; however, any further delays in the schedule or changes in tax law could adversely impact these conclusions. See also the Payment and Performance Obligations and Certain Related Uncertainties discussion above. When and to the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers. Other Project Matters When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation. SCE&G prepared and submitted an overall integration plan for the New Units to the NRC in August 2013. That plan remains under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units. Environmental The Company's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on the Company's and Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, the Company and Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company and Consolidated SCE&G expect to recover such expenditures and costs through existing ratemaking provisions. From a regulatory perspective, SCANA, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the SO 2 and NO X emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein. On August 3, 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO 2 from newly constructed fossil fuel-fired units. The final rule requires all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds CO 2 per MWh and new natural gas units to meet 1,000 pounds CO 2 per MWh. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G are monitoring the final rule, but do not plan to construct new coal-fired units in the foreseeable future. In addition, on August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national CO 2 emissions by 32% from 2005 levels by 2030. The rule also provides for nuclear reactors under construction, such as the New Units, to count towards compliance and establishes a phased-in compliance approach beginning in 2022. The rule gives each state from one to three years to issue SIPs, which will ultimately define the specific compliance methodology that will be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. The order of the Supreme Court has no immediate impact on SCE&G and GENCO or their generation operations. The Company and Consolidated SCE&G expect any costs incurred to comply with such rule to be recoverable through rates. In July 2011, the EPA issued the CSAPR to reduce emissions of SO 2 and NO X from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO 2 emissions and annual and ozone season NO X emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO 2 and NO X and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates. In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G and GENCO are in compliance with the MATS rule and expect to remain in compliance. The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule became effective on January 4, 2016. After this date, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five year permit cycle and thus may range from 2018 to 2023. The Company and Consolidated SCE&G expect that wastewater treatment technology retrofits will be required at Williams and Wateree Stations. Any costs incurred to comply with the ELG Rule are expected to be recoverable through rates. The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications to ensure compliance with this rule. Any costs incurred to comply with this rule are expected to be recoverable through rates. The EPA's final rule for CCR became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at SCE&G's and GENCO's coal-fired generating facilities. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. The Company and Consolidated SCE&G do not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future rates. The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2016, the federal government has not accepted any spent fuel from Unit 1, and it remains unclear when the repository may become available. SCE&G has constructed an independent spent fuel storage installation to accommodate the spent nuclear fuel output for the life of Unit 1. SCE&G may evaluate other technology as it becomes available. The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates. SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least

AFFILIATED TRANSACTIONS

AFFILIATED TRANSACTIONS	12 Months Ended
	Dec. 31, 2016
Affiliated Transaction [Line Items]
AFFILIATED TRANSACTIONS	AFFILIATED TRANSACTIONS The Company: The Company received cash distributions from equity-method investees of $3.7 million in 2016, $4.0 million in 2015 and $7.8 million in 2014. The Company made investments in equity-method investees of $5.5 million in 2016, $4.1 million in 2015 and $5.7 million in 2014. 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. Consolidated SCE&G’s total purchases from this affiliate were $161.8 million in 2016, $233.2 million in 2015 and $260.3 million in 2014. Consolidated SCE&G’s total sales to this affiliate were $160.8 million in 2016, $232.0 million in 2015 and $259.0 million in 2014. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Consolidated SCE&G’s payable to this affiliate was $16.1 million at December 31, 2016 and $12.9 million at December 31, 2015. Consolidated SCE&G’s receivable from this affiliate was $16.0 million at December 31, 2016 and $12.8 million at December 31, 2015. Consolidated SCE&G: SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. Such purchases totaled approximately $111.5 million in 2016, $128.5 million in 2015 and $195.7 million in 2014. SCE&G’s payables to SCANA Energy for such purchases were $8.8 million and $7.5 million as of December 31, 2016 and 2015, respectively. 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, including amounts capitalized, totaled $337.7 million in 2016, $300.0 million in 2015 and $292.2 million in 2014. Amounts expensed are recorded in Other operation and maintenance - nonconsolidated affiliate and Other expenses on the consolidated statements of comprehensive income. Consolidated SCE&G's payables to SCANA Services for these services were $63.5 million and $57.0 million at December 31, 2016 and 2015, respectively. 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 and $30.0 million in 2014. 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]
AFFILIATED TRANSACTIONS	The Company and Consolidated SCE&G: SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. Consolidated SCE&G’s total purchases from this affiliate were $161.8 million in 2016, $233.2 million in 2015 and $260.3 million in 2014. Consolidated SCE&G’s total sales to this affiliate were $160.8 million in 2016, $232.0 million in 2015 and $259.0 million in 2014. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Consolidated SCE&G’s payable to this affiliate was $16.1 million at December 31, 2016 and $12.9 million at December 31, 2015. Consolidated SCE&G’s receivable from this affiliate was $16.0 million at December 31, 2016 and $12.8 million at December 31, 2015. Consolidated SCE&G: SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. Such purchases totaled approximately $111.5 million in 2016, $128.5 million in 2015 and $195.7 million in 2014. SCE&G’s payables to SCANA Energy for such purchases were $8.8 million and $7.5 million as of December 31, 2016 and 2015, respectively. 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, including amounts capitalized, totaled $337.7 million in 2016, $300.0 million in 2015 and $292.2 million in 2014. Amounts expensed are recorded in Other operation and maintenance - nonconsolidated affiliate and Other expenses on the consolidated statements of comprehensive income. Consolidated SCE&G's payables to SCANA Services for these services were $63.5 million and $57.0 million at December 31, 2016 and 2015, respectively. 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 and $30.0 million in 2014. 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.

SEGMENT OF BUSINESS INFORMATION

SEGMENT OF BUSINESS INFORMATION	12 Months Ended
	Dec. 31, 2016
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 and reflect the effect of certain reclassifications described therein. 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, a services company and other nonreportable segments that were insignificant for all periods presented. In addition, All Other includes gains from the sales of CGT and SCI (see Note 1) and their operating results and assets 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 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 or assets other than utility plant. For nonregulated operations, management uses net income 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 consist of the unallocated net income 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, 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. Reportable segments have changed from what was reported as of December 31, 2015 to combine the former Retail Gas Marketing and Energy Marketing segments into a single Gas Marketing segment. This change in reportable segments occurred due to changes in the structure of the Company’s internal organization which included the integration of strategic planning and reporting for these business units and the related integration of the chief operating decision maker’s assessment of performance and resource allocation. Corresponding amounts in prior periods have been revised to conform to the current presentation. Disclosure of Reportable Segments The Company: Millions of dollars Electric Operations Gas Distribution Gas Marketing All Other Adjustments/ Eliminations Consolidated Total 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 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 ) — 2014 External Revenue $ 2,622 $ 1,012 $ 1,301 $ 37 $ (21 ) $ 4,951 Intersegment Revenue 7 2 196 437 (642 ) — Operating Income 768 159 n/a 27 53 1,007 Interest Expense 19 22 1 5 265 312 Depreciation and Amortization 300 72 2 24 (14 ) 384 Income Tax Expense 7 33 19 12 177 248 Net Income (Loss) n/a n/a 31 (6 ) 513 538 Segment Assets 10,182 2,487 290 1,474 2,385 16,818 Expenditures for Assets 936 200 2 52 (98 ) 1,092 Deferred Tax Assets 11 29 20 15 (75 ) — Consolidated SCE&G: Millions of dollars Electric Gas Adjustments/ Consolidated 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 ) — 2014 External Revenue $ 2,629 $ 462 — $ 3,091 Operating Income 768 62 — 830 Interest Expense 19 — $ 209 228 Depreciation and Amortization 300 27 (12 ) 315 Segment Assets 10,182 721 3,175 14,078 Expenditures for Assets 936 55 (57 ) 934 Deferred Tax Assets 11 n/a (11 ) —
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 and reflect the effect of certain reclassifications described therein. 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, a services company and other nonreportable segments that were insignificant for all periods presented. In addition, All Other includes gains from the sales of CGT and SCI (see Note 1) and their operating results and assets 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 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 or assets other than utility plant. For nonregulated operations, management uses net income 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 consist of the unallocated net income 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, 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. Reportable segments have changed from what was reported as of December 31, 2015 to combine the former Retail Gas Marketing and Energy Marketing segments into a single Gas Marketing segment. This change in reportable segments occurred due to changes in the structure of the Company’s internal organization which included the integration of strategic planning and reporting for these business units and the related integration of the chief operating decision maker’s assessment of performance and resource allocation. Corresponding amounts in prior periods have been revised to conform to the current presentation. Disclosure of Reportable Segments The Company: Millions of dollars Electric Operations Gas Distribution Gas Marketing All Other Adjustments/ Eliminations Consolidated Total 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 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 ) — 2014 External Revenue $ 2,622 $ 1,012 $ 1,301 $ 37 $ (21 ) $ 4,951 Intersegment Revenue 7 2 196 437 (642 ) — Operating Income 768 159 n/a 27 53 1,007 Interest Expense 19 22 1 5 265 312 Depreciation and Amortization 300 72 2 24 (14 ) 384 Income Tax Expense 7 33 19 12 177 248 Net Income (Loss) n/a n/a 31 (6 ) 513 538 Segment Assets 10,182 2,487 290 1,474 2,385 16,818 Expenditures for Assets 936 200 2 52 (98 ) 1,092 Deferred Tax Assets 11 29 20 15 (75 ) — Consolidated SCE&G: Millions of dollars Electric Gas Adjustments/ Consolidated 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 ) — 2014 External Revenue $ 2,629 $ 462 — $ 3,091 Operating Income 768 62 — 830 Interest Expense 19 — $ 209 228 Depreciation and Amortization 300 27 (12 ) 315 Segment Assets 10,182 721 3,175 14,078 Expenditures for Assets 936 55 (57 ) 934 Deferred Tax Assets 11 n/a (11 ) —

QUARTERLY FINANCIAL INFORMATION

QUARTERLY FINANCIAL INFORMATION (Notes)	12 Months Ended
	Dec. 31, 2016
Entity Information [Line Items]
Quarterly Financial Information [Text Block]	QUARTERLY FINANCIAL DATA (UNAUDITED) The Company Millions of dollars, except per share amounts First Quarter Second Quarter Third Quarter Fourth Quarter Annual 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 .74 1.32 .87 4.16 2015 Total operating revenues $ 1,389 $ 967 $ 1,068 $ 956 $ 4,380 Operating income 586 216 292 214 1,308 Net income 400 99 149 98 746 Earnings per share 2.80 .69 1.04 .69 5.22 Consolidated SCE&G Millions of dollars First Quarter Second Quarter Third Quarter Fourth Quarter Annual 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 2015 Total operating revenues $ 772 $ 709 $ 806 $ 643 $ 2,930 Operating income 237 218 307 172 934 Net Income 126 111 167 76 480 Earnings Available to Common Shareholder 122 107 164 73 466
SCE&G
Entity Information [Line Items]
Quarterly Financial Information [Text Block]	13. QUARTERLY FINANCIAL DATA (UNAUDITED) The Company Millions of dollars, except per share amounts First Quarter Second Quarter Third Quarter Fourth Quarter Annual 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 .74 1.32 .87 4.16 2015 Total operating revenues $ 1,389 $ 967 $ 1,068 $ 956 $ 4,380 Operating income 586 216 292 214 1,308 Net income 400 99 149 98 746 Earnings per share 2.80 .69 1.04 .69 5.22 Consolidated SCE&G Millions of dollars First Quarter Second Quarter Third Quarter Fourth Quarter Annual 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 2015 Total operating revenues $ 772 $ 709 $ 806 $ 643 $ 2,930 Operating income 237 218 307 172 934 Net Income 126 111 167 76 480 Earnings Available to Common Shareholder 122 107 164 73 466

SUMMARY OF SIGNIFICANT ACCOUN24

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2016
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. ServiceCare, Inc. South Carolina Generating Company, Inc. SCANA Services, Inc. Public Service Company of North Carolina, Incorporated SCANA Corporate Security Services, Inc. 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. Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation. 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 $485 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 5.3% for 2016, 6.1% for 2015, and 7.2% for 2014. Consolidated SCE&G calculated AFC using average composite rates of 4.7% for 2016, 5.6% for 2015, and 6.5% for 2014. 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. 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: 2016 2015 2014 SCE&G 2.56 % 2.55 % 2.85 % GENCO 2.66 % 2.66 % 2.66 % CGT — — 2.11 % PSNC Energy 2.90 % 2.94 % 2.98 % Weighted average of above 2.61 % 2.61 % 2.84 % Consolidated SCE&G 2.56 % 2.56 % 2.84 % 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. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel.
Jointly Owned Plant Policy [Policy Text Block]	Jointly Owned Utility Plant SCE&G jointly owns and is the operator of Unit 1. In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. As of December 31, 2016 2015 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.3 billion — $ 1.2 billion — Accumulated depreciation $ 634.4 million — $ 620.4 million — Construction work in progress $ 167.7 million $ 4.2 billion $ 214.6 million $ 3.4 billion For a discussion of expected cash outlays and expected in-service dates for the New Units and a description of SCE&G's agreement to acquire an additional 5% ownership in the New Units, see Note 10. 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 Unit 1 and the New Units. These amounts totaled $76.2 million at December 31, 2016 and $178.8 million at December 31, 2015.
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, 2016, and 2015, SCE&G incurred $23.8 million and $16.5 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 $26.8 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 evaluation as of January 1, 2017 and was not required to use the two-step quantitative assessment. In evaluations for preceding periods, the Company's step one assessment utilized the assistance of an independent appraisal in determining its estimate of fair value. In such evaluations, step one indicated no impairment, and no impairment charges were recorded.
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 trusteed asset balance 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 and treasury bills.
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. Other receivables consist primarily of amounts due from Santee Cooper related to the construction and operation of jointly owned nuclear generating facilities at Summer Station.
Inventory, Policy [Policy Text Block]	Inventories Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable.
Asset Management and Supply Service Agreements [Policy Text Block]	PSNC Energy utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. The counterparty held, through an agency relationship, 40% and 46% of PSNC Energy’s natural gas inventory at December 31, 2016 and December 31, 2015, respectively, with a carrying value of $9.8 million and $17.7 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to rate payers.
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 they are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, they are charged or credited to income tax expense. 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 in 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. 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]	Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 12) are presented within Operating Income, 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. Unbilled revenues totaled $178.9 million at December 31, 2016 and $129.1 million at December 31, 2015 for the Company. Unbilled revenues totaled $117.6 million at December 31, 2016 and $101.5 million at December 31, 2015 for Consolidated SCE&G. 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 hearings. 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 hearings. 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 Per Share Basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. When applicable, diluted earnings per share are computed 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 In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, have begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation. In May 2015, the FASB issued accounting guidance removing the requirement to categorize within the fair value hierarchy investments for which fair values are estimated using the NAV practical expedient. Disclosures about investments in certain entities that calculate NAV per share are limited under this guidance to those investments for which the entity has elected to estimate the fair value using the NAV practical expedient. The Company and Consolidated SCE&G elected to adopt this guidance on a retrospective basis. The adoption resulted in the reclassification of fair value related to the pension plan’s investment in the common collective trust, joint venture interest, and limited partnership as of December 31, 2015. See Note 8. In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G expect to adopt this guidance in the first quarter of 2017 and do not expect it to have a significant impact on their respective financial statements. In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and have determined adoption of this guidance will not have a significant impact on their respective financial statements. 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. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the initial identification and analysis of leasing and related contracts to which the guidance might be applicable have begun. In addition, the Company and Consolidated SCE&G have begun evaluating certain third party software tools that may assist with this implementation and ongoing compliance. In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities are required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G adopted this guidance in the fourth quarter of 2016 and, based on the nature of their share-based awards practices, the adoption had no impact on their respective financial statements. 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 is intended to result in certain 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 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. 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 impact their respective financial statements. In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G expect to adopt this guidance in the first quarter 2017 and it is not expected to have a material impact on their respective financial statements. In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018 and the Company and Consolidated SCE&G expect no impact on their respective financial statements. In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test. The same one-step impairment test will be applied to goodwill at all reporting units, even those with zero or negative carrying amounts. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that adoption will have a material impact on their respective financial statements.
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. Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation. 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 $485 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 5.3% for 2016, 6.1% for 2015, and 7.2% for 2014. Consolidated SCE&G calculated AFC using average composite rates of 4.7% for 2016, 5.6% for 2015, and 6.5% for 2014. 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. 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: 2016 2015 2014 SCE&G 2.56 % 2.55 % 2.85 % GENCO 2.66 % 2.66 % 2.66 % CGT — — 2.11 % PSNC Energy 2.90 % 2.94 % 2.98 % Weighted average of above 2.61 % 2.61 % 2.84 % Consolidated SCE&G 2.56 % 2.56 % 2.84 % 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. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel.
Jointly Owned Plant Policy [Policy Text Block]	Jointly Owned Utility Plant SCE&G jointly owns and is the operator of Unit 1. In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. As of December 31, 2016 2015 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.3 billion — $ 1.2 billion — Accumulated depreciation $ 634.4 million — $ 620.4 million — Construction work in progress $ 167.7 million $ 4.2 billion $ 214.6 million $ 3.4 billion For a discussion of expected cash outlays and expected in-service dates for the New Units and a description of SCE&G's agreement to acquire an additional 5% ownership in the New Units, see Note 10. 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 Unit 1 and the New Units. These amounts totaled $76.2 million at December 31, 2016 and $178.8 million at December 31, 2015.
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, 2016, and 2015, SCE&G incurred $23.8 million and $16.5 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 $26.8 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 trusteed asset balance 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 and treasury bills.
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. Other receivables consist primarily of amounts due from Santee Cooper related to the construction and operation of 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 they are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, they are charged or credited to income tax expense. 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 in 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. 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]	Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 12) are presented within Operating Income, 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. Unbilled revenues totaled $178.9 million at December 31, 2016 and $129.1 million at December 31, 2015 for the Company. Unbilled revenues totaled $117.6 million at December 31, 2016 and $101.5 million at December 31, 2015 for Consolidated SCE&G. 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 hearings. 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 hearings. 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 In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, have begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation. In May 2015, the FASB issued accounting guidance removing the requirement to categorize within the fair value hierarchy investments for which fair values are estimated using the NAV practical expedient. Disclosures about investments in certain entities that calculate NAV per share are limited under this guidance to those investments for which the entity has elected to estimate the fair value using the NAV practical expedient. The Company and Consolidated SCE&G elected to adopt this guidance on a retrospective basis. The adoption resulted in the reclassification of fair value related to the pension plan’s investment in the common collective trust, joint venture interest, and limited partnership as of December 31, 2015. See Note 8. In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G expect to adopt this guidance in the first quarter of 2017 and do not expect it to have a significant impact on their respective financial statements. In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and have determined adoption of this guidance will not have a significant impact on their respective financial statements. 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. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the initial identification and analysis of leasing and related contracts to which the guidance might be applicable have begun. In addition, the Company and Consolidated SCE&G have begun evaluating certain third party software tools that may assist with this implementation and ongoing compliance. In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities are required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G adopted this guidance in the fourth quarter of 2016 and, based on the nature of their share-based awards practices, the adoption had no impact on their respective financial statements. 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 is intended to result in certain 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 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. 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 impact their respective financial statements. In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G expect to adopt this guidance in the first quarter 2017 and it is not expected to have a material impact on their respective financial statements. In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018 and the Company and Consolidated SCE&G expect no impact on their respective financial statements. In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test. The same one-step impairment test will be applied to goodwill at all reporting units, even those with zero or negative carrying amounts. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that adoption will have a material impact on their respective financial statements.

SUMMARY OF SIGNIFICANT ACCOUN25

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2016
Significant Accounting Policies
Reclassifications [Text Block]	December 31, Millions of dollars 2015 2014 Derivative financial instruments $ (174 ) $ 207 Regulatory assets 179 (234 ) Regulatory liabilities 4 (29 ) Other assets (15 ) 32 Other liabilities 6 24
Schedule of weighted avg depreciation rates [Table Text Block]	2016 2015 2014 SCE&G 2.56 % 2.55 % 2.85 % GENCO 2.66 % 2.66 % 2.66 % CGT — — 2.11 % PSNC Energy 2.90 % 2.94 % 2.98 % Weighted average of above 2.61 % 2.61 % 2.84 % Consolidated SCE&G 2.56 % 2.56 % 2.84 %
Schedule of Jointly Owned Utility Plants [Table Text Block]	As of December 31, 2016 2015 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.3 billion — $ 1.2 billion — Accumulated depreciation $ 634.4 million — $ 620.4 million — Construction work in progress $ 167.7 million $ 4.2 billion $ 214.6 million $ 3.4 billion
SCE&G
Significant Accounting Policies
Schedule of weighted avg depreciation rates [Table Text Block]	2016 2015 2014 SCE&G 2.56 % 2.55 % 2.85 % GENCO 2.66 % 2.66 % 2.66 % CGT — — 2.11 % PSNC Energy 2.90 % 2.94 % 2.98 % Weighted average of above 2.61 % 2.61 % 2.84 % Consolidated SCE&G 2.56 % 2.56 % 2.84 %
Schedule of Jointly Owned Utility Plants [Table Text Block]	As of December 31, 2016 2015 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.3 billion — $ 1.2 billion — Accumulated depreciation $ 634.4 million — $ 620.4 million — Construction work in progress $ 167.7 million $ 4.2 billion $ 214.6 million $ 3.4 billion

RATE AND OTHER REGULATORY MAT26

RATE AND OTHER REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2016
Public Utilities, General Disclosures
Demand reduction programs [Table Text Block]	Year Effective Amount 2016 First billing cycle of May $37.6 million 2015 First billing cycle of May $32.0 million 2014 First billing cycle of May $15.4 million
Schedule of Changes in Electric Rate BLRA [Table Text Block]	Year Increase Effective for bills rendered on and after Amount Allowed ROE 2016 2.7% November 27 $64.4 million 10.50% * 2015 2.6% October 30 $64.5 million 11.00% 2014 2.8% October 30 $66.2 million 11.00%
Schedule of Changes in Gas Rate RSA [Table Text Block]	Year Action Amount 2016 1.2 % Increase $4.1 million 2015 No change — 2014 0.6 % Decrease $2.6 million
Schedule of Regulatory Assets [Table Text Block]	. The Company Consolidated SCE&G December 31, December 31, Millions of dollars 2016 2015 2016 2015 Regulatory Assets: Accumulated deferred income taxes $ 316 $ 298 $ 307 $ 291 AROs and related funding 425 405 403 384 Deferred employee benefit plan costs 342 325 309 295 Deferred losses on interest rate derivatives 620 535 620 535 Unrecovered plant 117 127 117 127 Environmental remediation costs 32 42 26 35 DSM Programs 59 61 59 61 Pipeline integrity management costs 33 19 6 4 Carrying costs on deferred tax assets related to nuclear construction 32 18 32 18 Deferred storm damage costs 20 — 20 — Deferred costs related to uncertain tax position 15 — 15 — Other 119 107 116 107 Total Regulatory Assets $ 2,130 $ 1,937 $ 2,030 $ 1,857
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities: Asset removal costs $ 755 $ 732 $ 529 $ 519 Deferred gains on interest rate derivatives 151 96 151 96 Other 24 27 15 20 Total Regulatory Liabilities $ 930 $ 855 $ 695 $ 635
SCE&G
Public Utilities, General Disclosures
Demand reduction programs [Table Text Block]	Year Effective Amount 2016 First billing cycle of May $37.6 million 2015 First billing cycle of May $32.0 million 2014 First billing cycle of May $15.4 million
Schedule of Changes in Electric Rate BLRA [Table Text Block]	Year Increase Effective for bills rendered on and after Amount Allowed ROE 2016 2.7% November 27 $64.4 million 10.50% * 2015 2.6% October 30 $64.5 million 11.00% 2014 2.8% October 30 $66.2 million 11.00%
Schedule of Changes in Gas Rate RSA [Table Text Block]	Year Action Amount 2016 1.2 % Increase $4.1 million 2015 No change — 2014 0.6 % Decrease $2.6 million
Schedule of Regulatory Assets [Table Text Block]	The Company Consolidated SCE&G December 31, December 31, Millions of dollars 2016 2015 2016 2015 Regulatory Assets: Accumulated deferred income taxes $ 316 $ 298 $ 307 $ 291 AROs and related funding 425 405 403 384 Deferred employee benefit plan costs 342 325 309 295 Deferred losses on interest rate derivatives 620 535 620 535 Unrecovered plant 117 127 117 127 Environmental remediation costs 32 42 26 35 DSM Programs 59 61 59 61 Pipeline integrity management costs 33 19 6 4 Carrying costs on deferred tax assets related to nuclear construction 32 18 32 18 Deferred storm damage costs 20 — 20 — Deferred costs related to uncertain tax position 15 — 15 — Other 119 107 116 107 Total Regulatory Assets $ 2,130 $ 1,937 $ 2,030 $ 1,857
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities: Asset removal costs $ 755 $ 732 $ 529 $ 519 Deferred gains on interest rate derivatives 151 96 151 96 Other 24 27 15 20 Total Regulatory Liabilities $ 930 $ 855 $ 695 $ 635

LONG-TERM AND SHORT-TERM DEBT (

LONG-TERM AND SHORT-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Schedule of Debt [Table Text Block]	: The Company December 31, 2016 2015 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) 2017 - 2034 79 1.63 % 84 1.11 % SCE&G First Mortgage Bonds (secured) 2018 - 2065 4,840 5.79 % 4,340 5.78 % GENCO Notes (secured) 2017 - 2024 213 5.93 % 220 5.92 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.51 % 122 3.51 % PSNC Energy Senior Debentures and Notes 2020 - 2046 450 5.53 % 350 5.93 % Nuclear Fuel Financing 2016 — — % 100 0.78 % Other 2017 - 2027 27 2.76 % 18 2.72 % Total debt 6,531 6,034 Current maturities of long-term debt (17 ) (116 ) Unamortized discount, net (1 ) — Unamortized debt issuance costs (40 ) (36 ) Total long-term debt, net $ 6,473 $ 5,882
Schedule of Line of Credit Facilities [Text Block]	: December 31, 2016 Millions of dollars Total SCANA SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 $ 500.0 — $ 500.0 — Three-year, expiring December 2018 $ 200.0 — $ 200.0 — Total committed long-term $ 2,000.0 $ 400.0 $ 1,400.0 $ 200.0 Outstanding commercial paper (270 or fewer days) $ 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	December 31, 2015 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) $ 531.4 $ 37.4 $ 420.2 $ 73.8 Weighted average interest rate 1.19 % 0.74 % 0.77 % Letters of credit supported by LOC $ 3.3 $ 3.0 $ 0.3 — Available $ 1,465.4 $ 359.6 $ 979.6 $ 126.2
SCE&G
Debt Instrument [Line Items]
Schedule of Debt [Table Text Block]	Consolidated SCE&G December 31, 2016 2015 Dollars in millions Maturity Balance Rate Balance Rate First Mortgage Bonds (secured) 2018 - 2065 $ 4,840 5.79 % $ 4,340 5.78 % GENCO Notes (secured) 2017 - 2024 213 5.93 % 220 5.92 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.51 % 122 3.51 % Nuclear Fuel Financing 2016 — — % 100 0.78 % Other 2017 - 2027 26 2.76 % 17 2.63 % Total debt 5,201 4,799 Current maturities of long-term debt (12 ) (110 ) Unamortized premium, net 1 2 Unamortized debt issuance costs (36 ) (32 ) Total long-term debt, net $ 5,154 $ 4,659
Schedule of Line of Credit Facilities [Text Block]	December 31, 2016 Millions of dollars Total SCANA SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300.0 $ 400.0 $ 700.0 $ 200.0 Fuel Company five-year, expiring December 2020 $ 500.0 — $ 500.0 — Three-year, expiring December 2018 $ 200.0 — $ 200.0 — Total committed long-term $ 2,000.0 $ 400.0 $ 1,400.0 $ 200.0 Outstanding commercial paper (270 or fewer days) $ 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	December 31, 2015 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) $ 531.4 $ 37.4 $ 420.2 $ 73.8 Weighted average interest rate 1.19 % 0.74 % 0.77 % Letters of credit supported by LOC $ 3.3 $ 3.0 $ 0.3 — Available $ 1,465.4 $ 359.6 $ 979.6 $ 126.2

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2016
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 2016 2015 2014 2016 2015 2014 Current taxes: Federal $ 36 $ 382 $ 38 $ 50 $ 208 $ 39 State 13 57 (4 ) 13 32 (6 ) Total current taxes 49 439 34 63 240 33 Deferred tax (benefit) expense, net: Federal 203 (36 ) 184 167 (3 ) 157 State 21 (7 ) 34 20 (3 ) 32 Total deferred taxes 224 (43 ) 218 187 (6 ) 189 Investment tax credits: Amortization of amounts deferred-state — (1 ) (1 ) — (1 ) (1 ) Amortization of amounts deferred-federal (2 ) (2 ) (3 ) (2 ) (2 ) (3 ) Total investment tax credits (2 ) (3 ) (4 ) (2 ) (3 ) (4 ) Total income tax expense $ 271 $ 393 $ 248 $ 248 $ 231 $ 218
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	: The Company Consolidated SCE&G Millions of dollars 2016 2015 2014 2016 2015 2014 Net income $ 595 $ 746 $ 538 $ 513 $ 466 $ 446 Income tax expense 271 393 248 248 231 218 Noncontrolling interest — — — 13 14 12 Total pre-tax income $ 866 $ 1,139 $ 786 $ 774 $ 711 $ 676 Income taxes on above at statutory federal income tax rate $ 303 $ 399 $ 275 $ 271 $ 249 $ 237 Increases (decreases) attributed to: State income taxes (less federal income tax effect) 27 38 24 26 24 21 State investment tax credits (less federal income tax effect) (5 ) (6 ) (5 ) (5 ) (6 ) (5 ) Allowance for equity funds used during construction (10 ) (9 ) (11 ) (9 ) (9 ) (10 ) Deductible dividends—401(k) Retirement Savings Plan (10 ) (10 ) (10 ) — — — Amortization of federal investment tax credits (2 ) (2 ) (3 ) (2 ) (2 ) (3 ) Section 41 tax credits — 1 (3 ) — 1 (3 ) Section 45 tax credits (8 ) (9 ) (9 ) (8 ) (9 ) (9 ) Domestic production activities deduction (23 ) (18 ) (7 ) (23 ) (18 ) (7 ) Realization of basis differences upon sale of subsidiaries — 7 — — — — Other differences, net (1 ) 2 (3 ) (2 ) 1 (3 ) Total income tax expense $ 271 $ 393 $ 248 $ 248 $ 231 $ 218
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	: The Company Consolidated SCE&G Millions of dollars 2016 2015 2016 2015 Deferred tax assets: Nondeductible accruals $ 148 $ 135 $ 53 $ 52 Asset retirement obligation, including nuclear decommissioning 213 199 200 187 Financial instruments 22 35 — 2 Unamortized investment tax credits 15 16 15 16 Deferred fuel costs 17 8 17 7 Other 10 5 8 2 Total deferred tax assets 425 398 293 266 Deferred tax liabilities: Property, plant and equipment 2,159 1,906 1,856 1,644 Deferred employee benefit plan costs 105 96 93 85 Regulatory asset, asset retirement obligation 143 135 135 127 Regulatory asset, unrecovered plant 45 49 45 49 Demand side management costs 23 23 23 23 Prepayments 32 31 30 29 Other 77 65 50 41 Total deferred tax liabilities 2,584 2,305 2,232 1,998 Net deferred tax liability $ 2,159 $ 1,907 $ 1,939 $ 1,732
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2016 2015 2014 2016 2015 2014 Unrecognized tax benefits, January 1 $ 49 $ 16 $ 3 $ 49 $ 16 $ 3 Gross increases—uncertain tax positions in prior period 94 33 — 94 33 — Gross decreases—uncertain tax positions in prior period — (2 ) — — (2 ) — Gross increases—current period uncertain tax positions 207 2 13 207 2 13 Unrecognized tax benefits, December 31 $ 350 $ 49 $ 16 $ 350 $ 49 $ 16
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 2016 2015 2014 2016 2015 2014 Current taxes: Federal $ 36 $ 382 $ 38 $ 50 $ 208 $ 39 State 13 57 (4 ) 13 32 (6 ) Total current taxes 49 439 34 63 240 33 Deferred tax (benefit) expense, net: Federal 203 (36 ) 184 167 (3 ) 157 State 21 (7 ) 34 20 (3 ) 32 Total deferred taxes 224 (43 ) 218 187 (6 ) 189 Investment tax credits: Amortization of amounts deferred-state — (1 ) (1 ) — (1 ) (1 ) Amortization of amounts deferred-federal (2 ) (2 ) (3 ) (2 ) (2 ) (3 ) Total investment tax credits (2 ) (3 ) (4 ) (2 ) (3 ) (4 ) Total income tax expense $ 271 $ 393 $ 248 $ 248 $ 231 $ 218
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2016 2015 2014 2016 2015 2014 Net income $ 595 $ 746 $ 538 $ 513 $ 466 $ 446 Income tax expense 271 393 248 248 231 218 Noncontrolling interest — — — 13 14 12 Total pre-tax income $ 866 $ 1,139 $ 786 $ 774 $ 711 $ 676 Income taxes on above at statutory federal income tax rate $ 303 $ 399 $ 275 $ 271 $ 249 $ 237 Increases (decreases) attributed to: State income taxes (less federal income tax effect) 27 38 24 26 24 21 State investment tax credits (less federal income tax effect) (5 ) (6 ) (5 ) (5 ) (6 ) (5 ) Allowance for equity funds used during construction (10 ) (9 ) (11 ) (9 ) (9 ) (10 ) Deductible dividends—401(k) Retirement Savings Plan (10 ) (10 ) (10 ) — — — Amortization of federal investment tax credits (2 ) (2 ) (3 ) (2 ) (2 ) (3 ) Section 41 tax credits — 1 (3 ) — 1 (3 ) Section 45 tax credits (8 ) (9 ) (9 ) (8 ) (9 ) (9 ) Domestic production activities deduction (23 ) (18 ) (7 ) (23 ) (18 ) (7 ) Realization of basis differences upon sale of subsidiaries — 7 — — — — Other differences, net (1 ) 2 (3 ) (2 ) 1 (3 ) Total income tax expense $ 271 $ 393 $ 248 $ 248 $ 231 $ 218
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2016 2015 2016 2015 Deferred tax assets: Nondeductible accruals $ 148 $ 135 $ 53 $ 52 Asset retirement obligation, including nuclear decommissioning 213 199 200 187 Financial instruments 22 35 — 2 Unamortized investment tax credits 15 16 15 16 Deferred fuel costs 17 8 17 7 Other 10 5 8 2 Total deferred tax assets 425 398 293 266 Deferred tax liabilities: Property, plant and equipment 2,159 1,906 1,856 1,644 Deferred employee benefit plan costs 105 96 93 85 Regulatory asset, asset retirement obligation 143 135 135 127 Regulatory asset, unrecovered plant 45 49 45 49 Demand side management costs 23 23 23 23 Prepayments 32 31 30 29 Other 77 65 50 41 Total deferred tax liabilities 2,584 2,305 2,232 1,998 Net deferred tax liability $ 2,159 $ 1,907 $ 1,939 $ 1,732
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	The Company Consolidated SCE&G Millions of dollars 2016 2015 2014 2016 2015 2014 Unrecognized tax benefits, January 1 $ 49 $ 16 $ 3 $ 49 $ 16 $ 3 Gross increases—uncertain tax positions in prior period 94 33 — 94 33 — Gross decreases—uncertain tax positions in prior period — (2 ) — — (2 ) — Gross increases—current period uncertain tax positions 207 2 13 207 2 13 Unrecognized tax benefits, December 31 $ 350 $ 49 $ 16 $ 350 $ 49 $ 16

DERIVATIVE FINANCIAL INSTRUME29

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2016
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, 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 As of December 31, 2015 Commodity 7,530,000 11,842,500 19,372,500 Energy Management (a) — 38,857,480 38,857,480 Total (a) 7,530,000 50,699,980 58,229,980 (a) Includes amounts related to basis swap contracts totaling 730,721 MMBTU in 2016 and 1,842,048 MMBTU in 2015.
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, 2016 December 31, 2015 December 31, 2016 December 31, 2015 Designated as hedging instruments $ 115.6 $ 120.0 $ 36.4 $ 36.4 Not designated as hedging instruments 1,285.0 1,235.0 1,285.0 1,235.0
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, 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 As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 28 9 Commodity contracts Other current assets 1 Derivative financial instruments 4 Total — $ 37 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 $ 10 Other deferred debits and other assets 5 5 Derivative financial instruments $ 33 $ 33 Other deferred credits and other liabilities 22 22 Commodity contracts Other current assets 1 Energy management contracts Other current assets 11 2 Other deferred debits and other assets 3 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 30 $ 69 $ 15 $ 55
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, 2016 Interest rate contracts — Interest expense $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (3 ) Interest expense $ (3 ) Year Ended December 31, 2014 Interest rate contracts $ (9 ) 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, 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 ) Year Ended December 31, 2014 Interest rate contracts $ (6 ) Interest expense $ (7 ) Commodity contracts (8 ) Gas purchased for resale 4 Total $ (14 ) $ (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 Regulatory Accounts Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars Location Amount Year Ended December 31, 2016 Interest rate contracts $ (34 ) Interest Expense $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (69 ) Other income $ 5 Year Ended December 31, 2014 Interest rate contracts $ (352 ) Other income $ 64
Disclosure of Credit Derivatives [Table Text Block]	Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars December 31, 2016 December 31, 2015 December 31, 2016 December 31, 2015 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 50.3 $ 95.2 $ 30.3 $ 57.0 Fair value of collateral already posted 29.2 50.4 9.2 13.4 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 21.1 44.8 21.1 43.6 in Net Asset Position Aggregate fair value of derivatives in net asset position $ 62.9 $ 7.3 $ 62.0 $ 7.3 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 62.9 7.3 62.0 7.3
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, 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 As of December 31, 2015 Gross Amounts of Recognized Assets $ 15 $ 1 $ 15 $ 31 $ 15 Gross Amounts Offset in Statement of Financial Position (1 ) (1 ) Net Amounts Presented in Statement of Financial Position 15 1 14 30 15 Gross Amounts Not Offset - Financial Instruments (8 ) (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received Net Amount $ 7 $ 1 $ 14 $ 22 $ 7 Balance sheet location Other current assets $ 22 $ 10 Other deferred debits and other assets 8 5 Total $ 30 $ 15
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, 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 As of December 31, 2015 Gross Amounts of Recognized Liabilities $ 87 $ 5 $ 15 $ 107 $ 65 Gross Amounts Offset in Statement of Financial Position (1 ) (1 ) Net Amounts Presented in Statement of Financial Position 87 5 14 106 65 Gross Amounts Not Offset - Financial Instruments (8 ) (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (36 ) (5 ) (9 ) (50 ) (13 ) Net Amount $ 43 $ — $ 5 $ 48 $ 44 Balance sheet location Other current assets $ 3 Derivative financial instruments 50 $ 34 Other deferred credits and other liabilities 53 31 Total $ 106 $ 65
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, 2016 December 31, 2015 December 31, 2016 December 31, 2015 Designated as hedging instruments $ 115.6 $ 120.0 $ 36.4 $ 36.4 Not designated as hedging instruments 1,285.0 1,235.0 1,285.0 1,235.0
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, 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 As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 28 9 Commodity contracts Other current assets 1 Derivative financial instruments 4 Total — $ 37 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 $ 10 Other deferred debits and other assets 5 5 Derivative financial instruments $ 33 $ 33 Other deferred credits and other liabilities 22 22 Commodity contracts Other current assets 1 Energy management contracts Other current assets 11 2 Other deferred debits and other assets 3 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 30 $ 69 $ 15 $ 55
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, 2016 Interest rate contracts — Interest expense $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (3 ) Interest expense $ (3 ) Year Ended December 31, 2014 Interest rate contracts $ (9 ) 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 Regulatory Accounts Gain (Loss) Reclassified from Deferred Accounts into Income Millions of dollars Location Amount Year Ended December 31, 2016 Interest rate contracts $ (34 ) Interest Expense $ (2 ) Year Ended December 31, 2015 Interest rate contracts $ (69 ) Other income $ 5 Year Ended December 31, 2014 Interest rate contracts $ (352 ) Other income $ 64
Disclosure of Credit Derivatives [Table Text Block]	Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars December 31, 2016 December 31, 2015 December 31, 2016 December 31, 2015 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 50.3 $ 95.2 $ 30.3 $ 57.0 Fair value of collateral already posted 29.2 50.4 9.2 13.4 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 21.1 44.8 21.1 43.6 in Net Asset Position Aggregate fair value of derivatives in net asset position $ 62.9 $ 7.3 $ 62.0 $ 7.3 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 62.9 7.3 62.0 7.3
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, 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 As of December 31, 2015 Gross Amounts of Recognized Assets $ 15 $ 1 $ 15 $ 31 $ 15 Gross Amounts Offset in Statement of Financial Position (1 ) (1 ) Net Amounts Presented in Statement of Financial Position 15 1 14 30 15 Gross Amounts Not Offset - Financial Instruments (8 ) (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received Net Amount $ 7 $ 1 $ 14 $ 22 $ 7 Balance sheet location Other current assets $ 22 $ 10 Other deferred debits and other assets 8 5 Total $ 30 $ 15
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, 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 As of December 31, 2015 Gross Amounts of Recognized Liabilities $ 87 $ 5 $ 15 $ 107 $ 65 Gross Amounts Offset in Statement of Financial Position (1 ) (1 ) Net Amounts Presented in Statement of Financial Position 87 5 14 106 65 Gross Amounts Not Offset - Financial Instruments (8 ) (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (36 ) (5 ) (9 ) (50 ) (13 ) Net Amount $ 43 $ — $ 5 $ 48 $ 44 Balance sheet location Other current assets $ 3 Derivative financial instruments 50 $ 34 Other deferred credits and other liabilities 53 31 Total $ 106 $ 65

FAIR VALUE MEASUREMENTS, INCL30

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Measurement Inputs, Disclosure [Table Text Block]	As of December 31, 2016 As of December 31, 2015 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 2 Level 1 Level 2 Level 2 Assets: Available for sale securities $ 14 — — $ 11 — — Held to maturity securities — $ 7 — — — — Interest rate contracts — 71 $ 71 — $ 15 $ 15 Commodity contracts 8 1 — 1 — — Energy management contracts 6 4 — — 14 — Liabilities: Interest rate contracts — 58 39 — 87 65 Commodity contracts — — — 1 4 — Energy management contracts 2 10 — 4 12 —
Fair Value, by Balance Sheet Grouping [Table Text Block]	As of December 31, 2016 As of December 31, 2015 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,489.8 $ 7,183.3 $ 5,997.6 $ 6,445.7 Consolidated SCE&G 5,166.0 5,752.3 4,769.0 5,129.1
SCE&G
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Measurement Inputs, Disclosure [Table Text Block]	As of December 31, 2016 As of December 31, 2015 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 2 Level 1 Level 2 Level 2 Assets: Available for sale securities $ 14 — — $ 11 — — Held to maturity securities — $ 7 — — — — Interest rate contracts — 71 $ 71 — $ 15 $ 15 Commodity contracts 8 1 — 1 — — Energy management contracts 6 4 — — 14 — Liabilities: Interest rate contracts — 58 39 — 87 65 Commodity contracts — — — 1 4 — Energy management contracts 2 10 — 4 12 —
Fair Value, by Balance Sheet Grouping [Table Text Block]	As of December 31, 2016 As of December 31, 2015 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,489.8 $ 7,183.3 $ 5,997.6 $ 6,445.7 Consolidated SCE&G 5,166.0 5,752.3 4,769.0 5,129.1

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2016
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 2016 2015 2016 2015 2016 2015 2016 2015 Benefit obligation, January 1 $ 855.4 $ 919.5 $ 253.6 $ 268.2 $ 724.0 $ 773.7 $ 191.7 $ 204.1 Service cost 20.7 24.1 4.4 5.3 16.9 19.3 3.6 4.4 Interest cost 39.4 38.2 12.1 11.4 33.4 32.2 9.9 9.4 Plan participants’ contributions — — 1.7 2.4 — — 1.3 1.9 Actuarial (gain) loss 45.0 (62.4 ) 14.0 (21.2 ) 41.8 (47.0 ) 11.5 (15.7 ) Benefits paid (56.2 ) (64.0 ) (11.1 ) (12.5 ) (47.7 ) (54.2 ) (9.1 ) (10.3 ) Amounts Funded to parent n/a n/a n/a n/a — — (1.7 ) (2.1 ) Benefit obligation, December 31 $ 904.3 $ 855.4 $ 274.7 $ 253.6 $ 768.4 $ 724.0 $ 207.2 $ 191.7
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 2016 2015 2016 2015 Annual discount rate used to determine benefit obligation 4.22 % 4.68 % 4.30 % 4.78 % 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, 2016 2015 2016 2015 2016 2015 2016 2015 Fair value of plan assets $ 793.6 $ 781.7 — — $ 732.9 $ 720.1 — — Benefit obligation 904.3 855.4 $ 274.7 $ 253.6 768.4 724.0 $ 207.2 $ 191.7 Funded status $ (110.7 ) $ (73.7 ) $ (274.7 ) $ (253.6 ) $ (35.5 ) $ (3.9 ) $ (207.2 ) $ (191.7 )
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, 2016 2015 2016 2015 2016 2015 2016 2015 Current liability — — $ (12.6 ) $ (11.9 ) — — $ (10.4 ) $ (9.8 ) Noncurrent liability $ (110.7 ) $ (73.7 ) (262.1 ) (241.7 ) $ (35.5 ) $ (3.9 ) (196.8 ) (181.9 )
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 2016 2015 2014 2016 2015 2014 Current year actuarial (gain) loss $ 0.6 $ 2.7 $ 3.1 $ 0.8 $ (1.2 ) $ 1.3 Amortization of actuarial losses (0.6 ) (0.4 ) (0.2 ) — (0.1 ) — Amortization of prior service cost (0.1 ) (0.1 ) (0.2 ) — (0.1 ) — Total recognized in OCI $ (0.1 ) $ 2.2 $ 2.7 $ 0.8 $ (1.4 ) $ 1.3
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, 2016 2015 2016 2015 2016 2015 2016 2015 Net actuarial loss $ 236.1 $ 219.4 $ 34.7 $ 24.0 $ 208.8 $ 193.7 $ 29.3 $ 20.4 Prior service cost 2.5 5.9 — 0.3 2.2 5.2 — 0.2 Total $ 238.6 $ 225.3 $ 34.7 $ 24.3 $ 211.0 $ 198.9 $ 29.3 $ 20.6
Schedule of Changes in Fair Value of Plan Assets [Table Text Block]	The Company Consolidated SCE&G Pension Benefits Pension Benefits Millions of dollars 2016 2015 2016 2015 Fair value of plan assets, January 1 $ 781.7 $ 861.8 $ 720.1 $ 783.6 Actual return (loss) on plan assets 68.1 (16.1 ) 60.5 (9.3 ) Benefits paid (56.2 ) (64.0 ) (47.7 ) (54.2 ) Fair value of plan assets, December 31 $ 793.6 $ 781.7 $ 732.9 $ 720.1
Schedule of Allocation of Plan Assets [Table Text Block]	The pension plan asset allocation at December 31, 2016 and 2015 and the target allocation for 2017 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2017 2016 2015 Equity Securities 58 % 57 % 57 % Fixed Income 33 % 32 % 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 2016 2015 2016 2015 Investments with fair value measure at Level 2: Mutual funds $ 125 $ 125 $ 115 $ 115 Short-term investment vehicles 16 14 15 12 US Treasury securities 18 22 17 20 Corporate debt securities 82 78 76 72 Municipals 14 14 13 13 Total assets in the fair value hierarchy 255 253 236 232 Investments at net asset value: Common collective trust 453 413 418 381 Joint venture interests 86 83 79 77 Limited partnership — 33 — 30 Total investments at fair value $ 794 $ 782 $ 733 $ 720
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 2017 $ 63.1 $ 12.9 $ 63.1 $ 10.6 2018 65.1 13.7 65.1 11.2 2019 64.5 14.5 64.5 11.9 2020 64.7 15.3 64.7 12.5 2021 67.1 15.9 67.1 13.1 2022-2026 324.4 86.0 324.4 70.5
Schedule of Net Benefit Costs [Table Text Block]	The Company Pension Benefits Other Postretirement Benefits Millions of dollars 2016 2015 2014 2016 2015 2014 Service cost $ 20.7 $ 24.1 $ 20.0 $ 4.4 $ 5.3 $ 4.6 Interest cost 39.4 38.2 40.4 12.1 11.4 12.0 Expected return on assets (55.9 ) (62.0 ) (66.7 ) n/a n/a n/a Prior service cost amortization 3.9 4.1 4.1 0.3 0.4 0.3 Amortization of actuarial losses 14.8 13.6 4.8 0.5 2.1 — Net periodic benefit cost $ 22.9 $ 18.0 $ 2.6 $ 17.3 $ 19.2 $ 16.9
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, 2016 2015 2016 2015 2016 2015 2016 2015 Net actuarial loss $ 10.4 $ 10.4 $ 2.5 $ 1.7 $ 1.9 $ 2.0 $ 1.0 $ 0.7 Prior service cost 0.1 0.2 — — — — — — Total $ 10.5 $ 10.6 $ 2.5 $ 1.7 $ 1.9 $ 2.0 $ 1.0 $ 0.7
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 2016 2015 2014 2016 2015 2014 Current year actuarial (gain) loss $ 29.4 $ 9.2 $ 101.3 $ 11.1 $ (18.0 ) $ 19.4 Amortization of actuarial losses (12.7 ) (11.9 ) (4.0 ) (0.4 ) (1.8 ) — Amortization of prior service cost (3.4 ) (3.7 ) (3.2 ) (0.3 ) (0.3 ) (0.3 ) Total recognized in regulatory assets $ 13.3 $ (6.4 ) $ 94.1 $ 10.4 $ (20.1 ) $ 19.1
Schedule of Assumptions Used in Determining Net Periodic Benefit Cost [Table Text Block]	Pension Benefits Other Postretirement Benefits 2016 2015 2014 2016 2015 2014 Discount rate 4.68 % 4.20 % 5.03 % 4.78 % 4.30 % 5.19 % Expected return on plan assets 7.50 % 7.50 % 8.00 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % 3.75 % Health care cost trend rate n/a n/a n/a 7.00 % 7.00 % 7.40 % 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 2020 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 2017 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant : Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 0.6 $ 0.1 Prior service cost 0.1 — Total $ 0.7 $ 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 2017 are as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Actuarial loss $ 13.6 $ 1.2 $ 12.0 $ 1.0 Prior service cost 1.4 — 1.3 — Total $ 15.0 $ 1.2 $ 13.3 $ 1.0
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 2016 2015 2016 2015 2016 2015 2016 2015 Benefit obligation, January 1 $ 855.4 $ 919.5 $ 253.6 $ 268.2 $ 724.0 $ 773.7 $ 191.7 $ 204.1 Service cost 20.7 24.1 4.4 5.3 16.9 19.3 3.6 4.4 Interest cost 39.4 38.2 12.1 11.4 33.4 32.2 9.9 9.4 Plan participants’ contributions — — 1.7 2.4 — — 1.3 1.9 Actuarial (gain) loss 45.0 (62.4 ) 14.0 (21.2 ) 41.8 (47.0 ) 11.5 (15.7 ) Benefits paid (56.2 ) (64.0 ) (11.1 ) (12.5 ) (47.7 ) (54.2 ) (9.1 ) (10.3 ) Amounts Funded to parent n/a n/a n/a n/a — — (1.7 ) (2.1 ) Benefit obligation, December 31 $ 904.3 $ 855.4 $ 274.7 $ 253.6 $ 768.4 $ 724.0 $ 207.2 $ 191.7
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 2016 2015 2016 2015 Annual discount rate used to determine benefit obligation 4.22 % 4.68 % 4.30 % 4.78 % 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, 2016 2015 2016 2015 2016 2015 2016 2015 Fair value of plan assets $ 793.6 $ 781.7 — — $ 732.9 $ 720.1 — — Benefit obligation 904.3 855.4 $ 274.7 $ 253.6 768.4 724.0 $ 207.2 $ 191.7 Funded status $ (110.7 ) $ (73.7 ) $ (274.7 ) $ (253.6 ) $ (35.5 ) $ (3.9 ) $ (207.2 ) $ (191.7 )
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, 2016 2015 2016 2015 2016 2015 2016 2015 Net actuarial loss $ 10.4 $ 10.4 $ 2.5 $ 1.7 $ 1.9 $ 2.0 $ 1.0 $ 0.7 Prior service cost 0.1 0.2 — — — — — — Total $ 10.5 $ 10.6 $ 2.5 $ 1.7 $ 1.9 $ 2.0 $ 1.0 $ 0.7
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 2016 2015 2014 2016 2015 2014 Current year actuarial (gain) loss — $ 0.2 $ 0.2 $ 0.3 $ (0.3 ) $ 0.4 Amortization of actuarial losses $ (0.1 ) (0.1 ) (0.1 ) — — — Amortization of prior service cost — (0.1 ) (0.1 ) — — — Total recognized in OCI $ (0.1 ) $ — $ — $ 0.3 $ (0.3 ) $ 0.4
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, 2016 2015 2016 2015 2016 2015 2016 2015 Net actuarial loss $ 236.1 $ 219.4 $ 34.7 $ 24.0 $ 208.8 $ 193.7 $ 29.3 $ 20.4 Prior service cost 2.5 5.9 — 0.3 2.2 5.2 — 0.2 Total $ 238.6 $ 225.3 $ 34.7 $ 24.3 $ 211.0 $ 198.9 $ 29.3 $ 20.6
Schedule of Changes in Fair Value of Plan Assets [Table Text Block]	The Company Consolidated SCE&G Pension Benefits Pension Benefits Millions of dollars 2016 2015 2016 2015 Fair value of plan assets, January 1 $ 781.7 $ 861.8 $ 720.1 $ 783.6 Actual return (loss) on plan assets 68.1 (16.1 ) 60.5 (9.3 ) Benefits paid (56.2 ) (64.0 ) (47.7 ) (54.2 ) Fair value of plan assets, December 31 $ 793.6 $ 781.7 $ 732.9 $ 720.1
Schedule of Allocation of Plan Assets [Table Text Block]	The pension plan asset allocation at December 31, 2016 and 2015 and the target allocation for 2017 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2017 2016 2015 Equity Securities 58 % 57 % 57 % Fixed Income 33 % 32 % 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 2016 2015 2016 2015 Investments with fair value measure at Level 2: Mutual funds $ 125 $ 125 $ 115 $ 115 Short-term investment vehicles 16 14 15 12 US Treasury securities 18 22 17 20 Corporate debt securities 82 78 76 72 Municipals 14 14 13 13 Total assets in the fair value hierarchy 255 253 236 232 Investments at net asset value: Common collective trust 453 413 418 381 Joint venture interests 86 83 79 77 Limited partnership — 33 — 30 Total investments at fair value $ 794 $ 782 $ 733 $ 720
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 2017 $ 63.1 $ 12.9 $ 63.1 $ 10.6 2018 65.1 13.7 65.1 11.2 2019 64.5 14.5 64.5 11.9 2020 64.7 15.3 64.7 12.5 2021 67.1 15.9 67.1 13.1 2022-2026 324.4 86.0 324.4 70.5
Schedule of Net Benefit Costs [Table Text Block]	Consolidated SCE&G Pension Benefits Other Postretirement Benefits Millions of dollars 2016 2015 2014 2016 2015 2014 Service cost $ 16.9 $ 19.3 $ 16.0 $ 3.6 $ 4.4 $ 3.6 Interest cost 33.4 32.2 34.1 9.9 9.4 9.4 Expected return on assets (47.4 ) (52.2 ) (56.3 ) n/a n/a n/a Prior service cost amortization 3.4 3.4 3.5 0.3 0.3 0.3 Amortization of actuarial losses 12.5 11.4 4.0 0.4 1.7 — Net periodic benefit cost $ 18.8 $ 14.1 $ 1.3 $ 14.2 $ 15.8 $ 13.3
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]	Amounts recognized in accumulated other comprehensive loss were as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, 2016 2015 2016 2015 2016 2015 2016 2015 Net actuarial loss $ 10.4 $ 10.4 $ 2.5 $ 1.7 $ 1.9 $ 2.0 $ 1.0 $ 0.7 Prior service cost 0.1 0.2 — — — — — — Total $ 10.5 $ 10.6 $ 2.5 $ 1.7 $ 1.9 $ 2.0 $ 1.0 $ 0.7
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 2016 2015 2014 2016 2015 2014 Current year actuarial (gain) loss $ 26.3 $ 12.2 $ 87.7 $ 9.2 $ (14.0 ) $ 15.8 Amortization of actuarial losses (11.2 ) (10.4 ) (3.5 ) (0.3 ) (1.5 ) — Amortization of prior service cost (3.0 ) (3.1 ) (2.8 ) (0.2 ) (0.3 ) (0.2 ) Total recognized in regulatory assets $ 12.1 $ (1.3 ) $ 81.4 $ 8.7 $ (15.8 ) $ 15.6
Schedule of Assumptions Used in Determining Net Periodic Benefit Cost [Table Text Block]	Pension Benefits Other Postretirement Benefits 2016 2015 2014 2016 2015 2014 Discount rate 4.68 % 4.20 % 5.03 % 4.78 % 4.30 % 5.19 % Expected return on plan assets 7.50 % 7.50 % 8.00 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.00 % 3.00 % 3.00 % 3.75 % Health care cost trend rate n/a n/a n/a 7.00 % 7.00 % 7.40 % 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 2020 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 2017 are as follows: The Company Consolidated SCE&G Millions of Dollars Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Actuarial loss $ 13.6 $ 1.2 $ 12.0 $ 1.0 Prior service cost 1.4 — 1.3 — Total $ 15.0 $ 1.2 $ 13.3 $ 1.0

COMMITMENTS AND CONTINGENCIES A

COMMITMENTS AND CONTINGENCIES ARO (Tables)	12 Months Ended
	Dec. 31, 2016
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 2016 2015 2016 2015 Beginning balance $ 520 $ 563 $ 488 $ 536 Liabilities incurred — — — — Liabilities settled (11 ) (16 ) (11 ) (16 ) Accretion expense 23 25 22 23 Revisions in estimated cash flows 26 (52 ) 23 (55 ) Ending balance $ 558 $ 520 $ 522 $ 488
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 2016 2015 2016 2015 Beginning balance $ 520 $ 563 $ 488 $ 536 Liabilities incurred — — — — Liabilities settled (11 ) (16 ) (11 ) (16 ) Accretion expense 23 25 22 23 Revisions in estimated cash flows 26 (52 ) 23 (55 ) Ending balance $ 558 $ 520 $ 522 $ 488

COMMITMENTS AND CONTINGENCIES O

COMMITMENTS AND CONTINGENCIES Operating Leases Tables (Tables)	12 Months Ended
	Dec. 31, 2016
Operating Leased Assets [Line Items]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	Future Minimum Rental Payments Millions of dollars 2017 2018 2019 2020 2021 Thereafter The Company $ 31 $ 29 $ 28 $ 3 $ 3 $ 23 Consolidated SCE&G 25 23 22 1 — 17
Schedule of Rent Expense [Table Text Block]	Rent Expense Millions of dollars 2016 2015 2014 The Company $ 10.2 $ 11.1 $ 12.3 Consolidated SCE&G 12.2 12.3 12.1
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 2017 2018 2019 2020 2021 Thereafter The Company $ 31 $ 29 $ 28 $ 3 $ 3 $ 23 Consolidated SCE&G 25 23 22 1 — 17
Schedule of Rent Expense [Table Text Block]	Rent Expense Millions of dollars 2016 2015 2014 The Company $ 10.2 $ 11.1 $ 12.3 Consolidated SCE&G 12.2 12.3 12.1

SEGMENT OF BUSINESS INFORMATI34

SEGMENT OF BUSINESS INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2016
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 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 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 ) — 2014 External Revenue $ 2,622 $ 1,012 $ 1,301 $ 37 $ (21 ) $ 4,951 Intersegment Revenue 7 2 196 437 (642 ) — Operating Income 768 159 n/a 27 53 1,007 Interest Expense 19 22 1 5 265 312 Depreciation and Amortization 300 72 2 24 (14 ) 384 Income Tax Expense 7 33 19 12 177 248 Net Income (Loss) n/a n/a 31 (6 ) 513 538 Segment Assets 10,182 2,487 290 1,474 2,385 16,818 Expenditures for Assets 936 200 2 52 (98 ) 1,092 Deferred Tax Assets 11 29 20 15 (75 ) —
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 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 ) — 2014 External Revenue $ 2,629 $ 462 — $ 3,091 Operating Income 768 62 — 830 Interest Expense 19 — $ 209 228 Depreciation and Amortization 300 27 (12 ) 315 Segment Assets 10,182 721 3,175 14,078 Expenditures for Assets 936 55 (57 ) 934 Deferred Tax Assets 11 n/a (11 ) —

QUARTERLY FINANCIAL INFORMATI35

QUARTERLY FINANCIAL INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2016
Statement [Line Items]
Schedule of Quarterly Financial Information [Table Text Block]	The Company Millions of dollars, except per share amounts First Quarter Second Quarter Third Quarter Fourth Quarter Annual 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 .74 1.32 .87 4.16 2015 Total operating revenues $ 1,389 $ 967 $ 1,068 $ 956 $ 4,380 Operating income 586 216 292 214 1,308 Net income 400 99 149 98 746 Earnings per share 2.80 .69 1.04 .69 5.22
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 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 2015 Total operating revenues $ 772 $ 709 $ 806 $ 643 $ 2,930 Operating income 237 218 307 172 934 Net Income 126 111 167 76 480 Earnings Available to Common Shareholder 122 107 164 73 466

SUMMARY OF SIGNIFICANT ACCOUN36

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MWshares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)shares
Significant Accounting Policies
Pre-tax gain on sale of CGT and SCI		$ 342
Reclassifications, Cash Flow Statement, Derivative Financial Instruments		(174)	$ 207
Reclassifications, Cash Flow Statement, Regulatory Assets		179	(234)
Reclassifications, Cash Flow Statement, Regulatory liabilities		4	(29)
Reclassifications, Cash Flow Statement, Other assets		(15)	32
Reclassifications, Cash Flow Statement Other Liabilities		6	$ 24
Unbilled Receivables, Current	$ 178.9	129.1
Goodwill	$ 210	$ 210
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.61%	2.61%	2.84%
Public Utilities, Allowance for Funds Used During Construction, Additions	5.30%	6.10%	7.20%
Property, Plant and Equipment, Net	$ 276	$ 280
Earnings Per Share
Weighted Average Shares Outstanding - Basic | shares	142.9	142.9	141.9
SCEG and GENCO [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.56%	2.56%	2.84%
SCE&G
Significant Accounting Policies
Maintenance Costs	$ 18.4
Utilities Operating Expense, Maintenance	23.8	$ 16.5
Environmental Remediation Costs Recognized in Regulatory Assets	25.7
Decommissioning Liability, Noncurrent	$ 786.4
Decommissioning safe storage	60
Payments to Acquire Investments to be Held in Decommissioning Trust Fund	$ 3.2
Unbilled Receivables, Current	$ 117.6	$ 101.5
Accrual period of nuclear refueling charges (in months)	18
Amount accrued annually for nuclear fuel outages	$ 17.2
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.56%	2.55%	2.85%
Public Utilities, Allowance for Funds Used During Construction, Additions	4.70%	5.60%	6.50%
Property, Plant and Equipment, Net	$ 69	$ 68
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	$ 485
CGT [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	0.00%	0.00%	2.11%
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	2.90%	2.94%	2.98%
Asset Management and Supply Service Agreements
Natural gas inventory, carrying amount	$ 9.8	$ 17.7
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	40.00%	46.00%
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	$ 1,300	$ 1,200
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	634.4	620.4
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	167.7	214.6
Summer Station Unit 1 [Domain] | SCE&G
Significant Accounting Policies
Accounts Receivable, Net	$ 76.2	$ 178.8
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	$ 3,400
SCE&G
Significant Accounting Policies
Nuclear refueling outage cost	$ 1.8	$ 26.8
Jointly Owned Utility Plant, Proportionate Ownership Share	5.00%

RATE AND OTHER REGULATORY MAT37

RATE AND OTHER REGULATORY MATTERS RATE AND OTHER REGULATORY MATTERS (Details) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2014USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)$ / shares	Dec. 31, 2014USD ($)	Dec. 31, 2013
SCE&G
Fuel Cost Increase To Base Fuel Costs		$ 10.3
Deferred Amounts Applied To Undercollected Fuel Balance		46
Demand Side Management Program Costs, Noncurrent		$ 37.6	$ 32	$ 15.4
Capacity of renewable energy facilities by 2020		84.5
Depreciation Study 2015, Effect Of Lower Depreciation Rates Annually, Dollars			$ 29
Depreciation Study 2015, Effect Of Lower Depreciation Rates Annually, Per Share | $ / shares			$ 0.12
Depreciation Study 2015, Undercollected Fuel Amount Offset by Lower Depreciation Rates, Dollars			$ 14.5
Depreciation Study 2015, Undercollected Fuel Amount Offset by Lower Depreciation Rates, Per Share | $ / shares			$ 0.06
Depreciation Study 2015, Increase in Net Income			$ 9.8
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances		$ 61
SCPSC Order, Recovery Of Projected DER Program Costs		6.9
Carrying costs on deferred income tax assets		14	$ 9.5
Storm Damage Reserve Cost Applied				5
Derivative, Gain on Derivative				$ 17.8
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	$ 5
DSM Program SCPC January 2017 filing, cost and net lost revenue recovery [Line Items]		$ 37
Pipeline integrity management costs [Member] | PSNC Energy [Member]
Regulatory Asset, Amortization Period		5 years
Demand Side Management programs [Member] | SCE&G
Regulatory Asset, Amortization Period		5 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					30 years
Pension costs, gas [Member] | SCE&G
Regulatory Asset, Amortization Period					14 years
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period		110 years

RATE AND OTHER REGULATORY MAT38

RATE AND OTHER REGULATORY MATTERS ELECTRIC-BLRA (Details) - SCE&G - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Entity Information [Line Items]
Public Utilties increase (decrease) in retail electric rates		$ 64.4	$ 64.5	$ 66.2
Public Utilities, Authorized Allowable Return on Common Equity, Percentage		10.50%	11.00%	11.00%
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA		2.70%	2.60%	2.80%
November 2016 SCPSC Approved Project Costs above SCPSC 2015 order		$ 831
Scenario, Forecast [Member]
Entity Information [Line Items]
Public Utilities, Authorized Allowable Return on Common Equity, Percentage	10.25%

RATE AND OTHER REGULATORY MAT39

RATE AND OTHER REGULATORY MATTERS GAS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
SCE&G
Entity Information [Line Items]
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates	1.20%		(0.60%)
Public Utilities, Authorized Allowable Return on Common Equity, Percentage	10.50%	11.00%	11.00%
Public Utilities changes in Retail Natural Gas Rates Approved under RSA	$ 4.1		$ 2.6
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, 2016	Dec. 31, 2015	Dec. 31, 2013
Regulatory Assets, Noncurrent	$ 2,130	$ 1,937
Regulatory Liability, Noncurrent	930	855
Asset Retirement Obligation Costs [Member]
Regulatory Liability, Noncurrent	755	732
Deferred gains on interest rate derivatives [Member]
Regulatory Liability, Noncurrent	151	96
Other Regulatory Liability [Member]
Regulatory Liability, Noncurrent	24	27
Demand Side Management programs [Member]
Regulatory Assets, Noncurrent	59	61
Pipeline integrity management costs [Member]
Regulatory Assets, Noncurrent	33	19
carrying cost on nuclear [Member]
Regulatory Assets, Noncurrent	32	18
Storm Costs [Member]
Regulatory Assets, Noncurrent	20	0
Deferred costs uncertain tax position [Member]
Regulatory Assets, Noncurrent	$ 15	0
Deferred Income Tax Charge [Member]
Regulatory Asset, Amortization Period	85 years
Regulatory Assets, Noncurrent	$ 316	298
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period	110 years
Regulatory Assets, Noncurrent	$ 425	405
Pension Costs [Member]
Regulatory Assets, Noncurrent	342	325
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets, Noncurrent	620	535
Canadys Refined Coal [Member]
Regulatory Assets, Noncurrent	117	127
Environmental Restoration Costs [Member]
Regulatory Assets, Noncurrent	32	42
Other Regulatory Assets [Member]
Regulatory Assets, Noncurrent	119	107
SCE&G
Regulatory Assets, Noncurrent	2,030	1,857
Regulatory Liability, Noncurrent	695	635
SCE&G | Asset Retirement Obligation Costs [Member]
Regulatory Liability, Noncurrent	529	519
SCE&G | Deferred gains on interest rate derivatives [Member]
Regulatory Liability, Noncurrent	151	96
SCE&G | Other Regulatory Liability [Member]
Regulatory Liability, Noncurrent	$ 15	20
SCE&G | Demand Side Management programs [Member]
Regulatory Asset, Amortization Period	5 years
Regulatory Assets, Noncurrent	$ 59	61
SCE&G | Pipeline integrity management costs [Member]
Regulatory Assets, Noncurrent	6	4
Pipeline integrity management costs, annual amortization amount	$ 1.9
SCE&G | carrying cost on nuclear [Member]
Regulatory Asset, Amortization Period	10 years
Regulatory Assets, Noncurrent	$ 32	18
SCE&G | Storm Costs [Member]
Regulatory Assets, Noncurrent	20	0
SCE&G | Deferred costs uncertain tax position [Member]
Regulatory Assets, Noncurrent	15	0
SCE&G | Deferred Income Tax Charge [Member]
Regulatory Assets, Noncurrent	307	291
SCE&G | Asset Retirement Obligation Costs [Member]
Regulatory Assets, Noncurrent	$ 403	384
SCE&G | Pension Costs [Member]
Regulatory Asset, Amortization Period	11 years
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	$ 14		$ 63
Regulatory Assets, Noncurrent	309	295
SCE&G | Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets, Noncurrent	620	535
SCE&G | Canadys Refined Coal [Member]
Regulatory Assets, Noncurrent	$ 117	127
SCE&G | Environmental Restoration Costs [Member]
MPG environmental remediation	18
Regulatory Assets, Noncurrent	$ 26	35
SCE&G | Other Regulatory Assets [Member]
Regulatory Assets, Noncurrent	116	$ 107
PSNC Energy [Member]
Pipeline integrity management costs, amount recovering beginning November 2016	20.3
Pipeline integrity management costs, amount deferred pending future approval of rate recovery	$ 7
PSNC Energy [Member] | Pipeline integrity management costs [Member]
Regulatory Asset, Amortization Period	5 years

RATE AND OTHER REGULATORY MAT41

RATE AND OTHER REGULATORY MATTERS NARRATIVE (Details)	12 Months Ended
	Dec. 31, 2016
Deferred Income Tax Charge [Member]
Regulatory Asset, Amortization Period	85 years
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period	110 years
SCE&G | Demand Side Management programs [Member]
Regulatory Asset, Amortization Period	5 years
SCE&G | Pension Costs [Member]
Regulatory Asset, Amortization Period	11 years
SCE&G | carrying cost on nuclear [Member]
Regulatory Asset, Amortization Period	10 years
PSNC Energy [Member] | Pipeline integrity management costs [Member]
Regulatory Asset, Amortization Period	5 years

COMMON EQUITY (Details)

COMMON EQUITY (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	200,000,000	200,000,000
Common stock issued through various compensation and dividend reinvestment plans, including the Stock Purchase Savings Plan	$ 0	$ 14.3
SCE&G
Schedule of Capitalization, Equity [Line Items]
Retained Earnings, Appropriated	$ 79	$ 72.4
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

LONG-TERM AND SHORT-TERM DEBT43

LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2016	Jun. 30, 2016	Jun. 30, 2015
Debt Instrument [Line Items]
Medium-term Notes	$ 800	$ 800
Senior Notes	79	84
First Mortgage Bonds	4,840	4,340
GENCO Notes	213	220
Industrial and Pollution Control Bonds	122	122
Senior Notes, Noncurrent	450	350
Long Term Contract for Nuclear Fuel Purchase	0	100
Other Long-term Debt	27	18
Long-term Debt, Gross	6,531	6,034
Long-term Debt, Current Maturities	(17)	(116)
Debt Instrument, Unamortized Discount	1	0
Unamortized Debt Issuance Expense	(40)	(36)
Long-term Debt	6,473	$ 5,882
Long-term Debt Current Maturities in Next Twelve Months	17
Long-term Debt, Maturities, Repayments of Principal in Year Two	726
Long-term Debt, Maturities, Repayments of Principal in Year Three	15
Long-term Debt, Maturities, Repayments of Principal in Year Four	365
Long-term Debt, Maturities, Repayments of Principal in Year Five	$ 493
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	5.79%	5.78%
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	5.93%	5.92%
Debt Instrument, Redemption Period, Start Date	Feb. 1, 2017
Debt Instrument, Redemption Period, End Date	Feb. 1, 2024
Industrial and Pollution Control Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	3.51%	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	0.76%	0.03%
Senior Debentures [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.53%	5.93%
Debt Instrument, Redemption Period, Start Date	Mar. 30, 2020
Debt Instrument, Redemption Period, End Date	Dec. 15, 2046
Nuclear fuel purchase contract [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	0.00%	0.78%
Debt Instrument, Redemption Period, End Date	Nov. 1, 2016
Other Debt [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	2.76%	2.72%
Debt Instrument, Redemption Period, Start Date	Jan. 1, 2017
Debt Instrument, Redemption Period, End Date	Sep. 30, 2027
Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	1.63%	1.11%
Debt Instrument, Redemption Period, Start Date	Jun. 1, 2017
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]
Proceeds from Issuance of First Mortgage Bond		$ 500
First Mortgage Bonds	$ 4,840	4,340		$ 425
GENCO Notes	213	220
Industrial and Pollution Control Bonds	122	122
Long Term Contract for Nuclear Fuel Purchase	0	100
Debt Instrument, Interest Rate, Stated Percentage				4.10%	5.10%
Other Long-term Debt	26	17
Long-term Debt, Gross	5,201	4,799
Long-term Debt, Current Maturities	(12)	(110)
Debt Instrument, Unamortized Discount (Premium), Net	1	2
Unamortized Debt Issuance Expense	(36)	(32)
Long-term Debt	5,154	$ 4,659
Long-term Debt, Maturities, Repayments of Principal in Year Two	722
Long-term Debt, Maturities, Repayments of Principal in Year Three	11
Long-term Debt, Maturities, Repayments of Principal in Year Four	10
Long-term Debt, Maturities, Repayments of Principal in Year Five	$ 39
SCE&G | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.79%	5.78%
Debt Instrument, Redemption Period, End Date	Jun. 1, 2065
SCE&G | Genco Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.93%	5.92%
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	3.51%	3.51%
Debt Instrument, Redemption Period, End Date	Dec. 1, 2038
Long-term Debt, Percentage Bearing Variable Interest, Amount		$ 67.8
SCE&G | Nuclear fuel purchase contract [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	0.00%	0.78%
Debt Instrument, Redemption Period, End Date	Nov. 1, 2016
SCE&G | Other Debt [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	2.76%	2.63%
Debt Instrument, Redemption Period, Start Date	Jan. 31, 2017
Debt Instrument, Redemption Period, End Date	Sep. 30, 2027
SCEG including Fuel Company [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	1.04%	0.74%
Long-term Debt Current Maturities in Next Twelve Months	$ 12
PSNC Energy [Member]
Debt Instrument [Line Items]
Senior Notes				$ 100
Debt Instrument, Interest Rate, Stated Percentage				4.13%
Debt, Weighted Average Interest Rate	1.07%	0.77%
first mortgage bond issued May 2014 [Member] | SCE&G
Debt Instrument [Line Items]
First Mortgage Bonds			$ 300
Debt Instrument, Interest Rate, Stated Percentage			4.50%
First Mortgage Bonds [Member] | SCE&G
Debt Instrument [Line Items]
First Mortgage Bonds				$ 75
Debt Instrument, Interest Rate, Stated Percentage				4.50%

LONG-TERM AND SHORT-TERM DEBT44

LONG-TERM AND SHORT-TERM DEBT (Details 2) $ in Millions	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Debt Instrument, Redemption [Line Items]
Bond Ratio	5.12
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,000	$ 2,000
Commercial Paper	940.5	531.4
Letters of Credit Outstanding, Amount	3.3	3.3
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,056.2	1,465.4
long term debt lender	2
SCEG including Fuel Company [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,400	1,400
Commercial Paper	$ 804.3	$ 420.2
Debt, Weighted Average Interest Rate	1.04%	0.74%
Letters of Credit Outstanding, Amount	$ 0.3	$ 0.3
Line of Credit Facility, Remaining Borrowing Capacity	595.4	979.6
SCANA [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	400	400
Commercial Paper	$ 64.4	$ 37.4
Debt, Weighted Average Interest Rate	1.43%	1.19%
Letters of Credit Outstanding, Amount	$ 3	$ 3
Line of Credit Facility, Remaining Borrowing Capacity	332.6	359.6
Fuel Company [Member]
Debt Instrument, Redemption [Line Items]
Long-Term Line of Credit - SC Fuel Co only	500	500
SCE&G
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	700	700
Long-term Line of Credit - SCE&G only	200	200
PSNC Energy [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200	200
Commercial Paper	$ 71.8	$ 73.8
Debt, Weighted Average Interest Rate	1.07%	0.77%
Line of Credit Facility, Remaining Borrowing Capacity	$ 128.2	$ 126.2
Industrial and Pollution Control Bonds [Member]
Debt Instrument, Redemption [Line Items]
Debt, Weighted Average Interest Rate	3.51%	3.51%
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	0.76%	0.03%
Industrial and Pollution Control Bonds [Member] | SCE&G
Debt Instrument, Redemption [Line Items]
Debt, Weighted Average Interest Rate	3.51%	3.51%
Wells Fargo, National Association, Bank of America & Morgan Stanley [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	9.50%
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 Percentage of Credit Facilities Provided by Each Bank	7.90%
royal bank of canada [Domain]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	5.50%
3 Year Credit [Domain]
Debt Instrument, Redemption [Line Items]
Long-term Line of Credit - SCE&G only	$ 200	$ 200
five year credit [Domain]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,300	$ 1,300

LONG-TERM AND SHORT-TERM DEBT45

LONG-TERM AND SHORT-TERM DEBT (NARRATIVE) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
months preceding issuance of bonds	18
Unfunded property additions	70.00%
Consecutive months for bond ratio	12
Bond Ratio	5.12
SCE&G
Debt Instrument [Line Items]
Due to Related Parties	$ 29	$ 33
Related Party Transaction, Due from (to) Related Party, Current		$ 9

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($)	3 Months Ended		9 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Investments, Owned, Federal Income Tax Note [Line Items]
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards		$ 16,000,000		$ 350,000,000	$ 49,000,000	$ 16,000,000	$ 3,000,000
Decrease in Unrecognized Tax Benefits is Reasonably Possible				49,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate				17,000,000
Increase in Unrecognized Tax Benefits is Reasonably Possible				292,000,000
Unrecognized Tax Benefits, Interest Income on Taxes Accrued				1,800,000
Unrecognized Tax Benefits, Interest on Income Taxes Accrued				900,000
Unrecognized Tax Benefits, Income Tax Penalties Expense				$ 0
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent		6.00%	6.90%	4.00%	5.00%
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)				$ 36,000,000	$ 382,000,000	38,000,000
Current State and Local Tax Expense (Benefit)				13,000,000	57,000,000	(4,000,000)
Current Income Tax Expense (Benefit)				49,000,000	439,000,000	34,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)				203,000,000	(36,000,000)	184,000,000
Deferred State and Local Income Tax Expense (Benefit)				21,000,000	(7,000,000)	34,000,000
Deferred Income Tax Expense (Benefit)				224,000,000	(43,000,000)	218,000,000
Income Tax Reconciliation, Tax Credits, Investment [Abstract]
Amortization of Amounts Deferred Under State and Local Investment Tax Credits				0	(1,000,000)	(1,000,000)
Investment Tax Credit				(2,000,000)	(3,000,000)	(4,000,000)
Income Tax Expense (Benefit)				271,000,000	393,000,000	248,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic				866,000,000	1,139,000,000	786,000,000
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount				303,000,000	399,000,000	275,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount				27,000,000	38,000,000	24,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits				(5,000,000)	(6,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction				(10,000,000)	(9,000,000)	(11,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Dividends, Amount				(10,000,000)	(10,000,000)	(10,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits				(2,000,000)	(2,000,000)	(3,000,000)
Section41TaxCredit				0	1,000,000	3,000,000
Section 45 tax credit				(8,000,000)	(9,000,000)	(9,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent				(23,000,000)	(18,000,000)	(7,000,000)
Income Tax Reconciliation, Sale of Subsidiaries				0	7,000,000	0
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount				(1,000,000)	2,000,000	(3,000,000)
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities				148,000,000	135,000,000
Deferred tax Nuclear Decommissioning				213,000,000	199,000,000
Deferred Tax Assets, Financial Instruments				22,000,000	35,000,000
Deferred Tax Asset, Unamortized Investment, Tax Credits				15,000,000	16,000,000
Deferred Tax Asset, Deferred Fuel Cost				17,000,000	8,000,000
Deferred Tax Assets, Other				10,000,000	5,000,000
Deferred Tax Assets, Net				425,000,000	398,000,000
Deferred Tax Liabilities, Property, Plant and Equipment				2,159,000,000	1,906,000,000
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits				105,000,000	96,000,000
Deferred Tax Liabilities, Asset Retirement Obligation				143,000,000	135,000,000
Deferred tax asset unrecovered plant				45,000,000	49,000,000
Deferred Tax Liability, Demand Side Management				23,000,000	23,000,000
deferred tax liability, prepayments				32,000,000	31,000,000
Deferred Tax Liabilities, Other				77,000,000	65,000,000
Deferred Tax Liabilities, Net				2,584,000,000	2,305,000,000
Deferred Tax Liabilities, Net, Noncurrent				2,159,000,000	1,907,000,000
Unrecognized tax benefits				219,000,000	44,000,000
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions				94,000,000	33,000,000	0
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions				0	(2,000,000)	0
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions				207,000,000	2,000,000	13,000,000
SCE&G
Investments, Owned, Federal Income Tax Note [Line Items]
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards		$ 16,000,000		350,000,000	49,000,000	16,000,000	$ 3,000,000
Decrease in Unrecognized Tax Benefits is Reasonably Possible				49,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate				17,000,000
Increase in Unrecognized Tax Benefits is Reasonably Possible				292,000,000
Unrecognized Tax Benefits, Interest Income on Taxes Accrued				1,800,000
Unrecognized Tax Benefits, Interest on Income Taxes Accrued				900,000
Unrecognized Tax Benefits, Income Tax Penalties Expense				0
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)				50,000,000	208,000,000	39,000,000
Current State and Local Tax Expense (Benefit)				13,000,000	32,000,000	(6,000,000)
Current Income Tax Expense (Benefit)				63,000,000	240,000,000	33,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)				167,000,000	(3,000,000)	157,000,000
Deferred State and Local Income Tax Expense (Benefit)				(20,000,000)	(3,000,000)	32,000,000
Deferred Income Tax Expense (Benefit)				(187,000,000)	(6,000,000)	189,000,000
Income Tax Reconciliation, Tax Credits, Investment [Abstract]
Amortization of Amounts Deferred Under State and Local Investment Tax Credits				0	(1,000,000)	(1,000,000)
Investment Tax Credit				(2,000,000)	(3,000,000)	(4,000,000)
Income Tax Expense (Benefit)				248,000,000	231,000,000	218,000,000
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount				271,000,000	249,000,000	237,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount				26,000,000	24,000,000	21,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits				(5,000,000)	(6,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction				(9,000,000)	(9,000,000)	(10,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits				(2,000,000)	(2,000,000)	(3,000,000)
Section41TaxCredit				0	1,000,000	3,000,000
Section 45 tax credit				(8,000,000)	(9,000,000)	(9,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent				(23,000,000)	(18,000,000)	(7,000,000)
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount				(2,000,000)	1,000,000	(3,000,000)
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities				53,000,000	52,000,000
Deferred tax Nuclear Decommissioning				200,000,000	187,000,000
Deferred Tax Assets, Financial Instruments				0	2,000,000
Deferred Tax Asset, Unamortized Investment, Tax Credits				15,000,000	16,000,000
Deferred Tax Asset, Deferred Fuel Cost				17,000,000	7,000,000
Deferred Tax Assets, Other				8,000,000	2,000,000
Deferred Tax Assets, Net				293,000,000	266,000,000
Deferred Tax Liabilities, Property, Plant and Equipment				1,856,000,000	1,644,000,000
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits				93,000,000	85,000,000
Deferred Tax Liabilities, Asset Retirement Obligation				135,000,000	127,000,000
Deferred tax asset unrecovered plant				45,000,000	49,000,000
Deferred Tax Liability, Demand Side Management				23,000,000	23,000,000
deferred tax liability, prepayments				30,000,000	29,000,000
Deferred Tax Liabilities, Other				50,000,000	41,000,000
Deferred Tax Liabilities, Net				2,232,000,000	1,998,000,000
Deferred Tax Liabilities, Net, Noncurrent				1,939,000,000	1,732,000,000
Unrecognized tax benefits				236,000,000	44,000,000
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions				94,000,000	33,000,000	0
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions				0	(2,000,000)	0
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions				$ 207,000,000	$ 2,000,000	$ 13,000,000
Scenario, Forecast [Member]
Investments, Owned, Federal Income Tax Note [Line Items]
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	3.00%

INCOME TAXES INCOME TAXES (Deta

INCOME TAXES INCOME TAXES (Details 2) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
income tax [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent									35.00%
Income Available to Common Shareholders	$ 125,000,000	$ 189,000,000	$ 105,000,000	$ 176,000,000	$ 98,000,000	$ 149,000,000	$ 99,000,000	$ 400,000,000	$ 595,000,000	$ 746,000,000	$ 538,000,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate									303,000,000	399,000,000	275,000,000
Income Tax Expense (Benefit) Continuing Operations, Income Tax Reconciliation, Changes [Abstract]
Income Tax Reconciliation, State and Local Income Taxes									27,000,000	38,000,000	24,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits									(5,000,000)	(6,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction									(10,000,000)	(9,000,000)	(11,000,000)
Income Tax Reconciliation, Deductions, Dividends									10,000,000	10,000,000	10,000,000
Amortization of Amounts Deferred under Federal Investment Tax Credits									2,000,000	2,000,000	3,000,000
Section41TaxCredit									0	1,000,000	3,000,000
Section 45 tax credit									8,000,000	9,000,000	9,000,000
Income Tax Reconciliation, Other Adjustments									(1,000,000)	2,000,000	(3,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent									(23,000,000)	(18,000,000)	(7,000,000)
Income Tax Expense (Benefit)									271,000,000	393,000,000	248,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic									866,000,000	1,139,000,000	786,000,000
Income Tax Reconciliation, Sale of Subsidiaries									0	7,000,000	0
SCE&G
income tax [Line Items]
Net Income (Loss) Attributable to Parent	$ 89,000,000	$ 201,000,000	$ 110,000,000	$ 113,000,000	$ 73,000,000	$ 164,000,000	$ 107,000,000	$ 122,000,000	513,000,000	466,000,000	446,000,000
Net Income (Loss) Attributable to Noncontrolling Interest									13,000,000	14,000,000	12,000,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate									271,000,000	249,000,000	237,000,000
Income Tax Expense (Benefit) Continuing Operations, Income Tax Reconciliation, Changes [Abstract]
Income Tax Reconciliation, State and Local Income Taxes									26,000,000	24,000,000	21,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits									(5,000,000)	(6,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction									(9,000,000)	(9,000,000)	(10,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits									2,000,000	2,000,000	3,000,000
Section41TaxCredit									0	1,000,000	3,000,000
Section 45 tax credit									8,000,000	9,000,000	9,000,000
Income Tax Reconciliation, Other Adjustments									(2,000,000)	1,000,000	(3,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent									(23,000,000)	(18,000,000)	(7,000,000)
Income Tax Expense (Benefit)									248,000,000	231,000,000	218,000,000
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest									$ 774,000,000	$ 711,000,000	$ 676,000,000

INCOME TAXES INCOME TAXES (De48

INCOME TAXES INCOME TAXES (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	$ 148	$ 135
Deferred tax Nuclear Decommissioning	213	199
Deferred Tax Assets, Financial Instruments	22	35
Deferred Tax Asset, Unamortized Investment, Tax Credits	15	16
Deferred Tax Asset, Deferred Fuel Cost	17	8
Deferred Tax Assets, Other	10	5
Deferred Tax Assets, Net	425	398
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	2,159	1,906
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	105	96
Deferred Tax Liabilities, Asset Retirement Obligation	143	135
Deferred tax asset unrecovered plant	45	49
Deferred Tax Liability, Demand Side Management	23	23
deferred tax liability, prepayments	32	31
Deferred Tax Liabilities, Other	77	65
Deferred Tax Liabilities, Gross	2,584	2,305
Deferred Tax Liabilities, Net, Noncurrent	2,159	1,907
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	94	33	$ 0
Gross decreases tax positions in prior period	0	(2)	0
Gross increases current period tax positions	207	2	13
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards	350	49	16	$ 3
SCE&G
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	53	52
Deferred tax Nuclear Decommissioning	200	187
Deferred Tax Assets, Financial Instruments	0	2
Deferred Tax Asset, Unamortized Investment, Tax Credits	15	16
Deferred Tax Asset, Deferred Fuel Cost	17	7
Deferred Tax Assets, Other	8	2
Deferred Tax Assets, Net	293	266
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	1,856	1,644
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	93	85
Deferred Tax Liabilities, Asset Retirement Obligation	135	127
Deferred tax asset unrecovered plant	45	49
Deferred Tax Liability, Demand Side Management	23	23
deferred tax liability, prepayments	30	29
Deferred Tax Liabilities, Other	50	41
Deferred Tax Liabilities, Gross	2,232	1,998
Deferred Tax Liabilities, Net, Noncurrent	1,939	1,732
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	94	33	0
Gross decreases tax positions in prior period	0	(2)	0
Gross increases current period tax positions	207	2	13
Unrecognized Tax Benefits, gross of state deduction on federal return and certain operating loss and tax credit carryfowards	$ 350	$ 49	$ 16	$ 3

DERIVATIVE FINANCIAL INSTRUME49

DERIVATIVE FINANCIAL INSTRUMENTS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MMBTU		Dec. 31, 2015USD ($)MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	83,904,223	[1]	58,229,980
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	4,510,000		7,530,000
Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	79,394,223	[1]	50,699,980
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	67,447,223	[1]	38,857,480
Energy Related Derivative [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	67,447,223		38,857,480
Commodity Contract [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	16,457,000		19,372,500
Commodity Contract [Member] | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	4,510,000		7,530,000
Commodity Contract [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	11,947,000		11,842,500
Basis Swap [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	730,721		1,842,048
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 115.6		$ 120
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	1,285		1,235
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	$ 1,285		$ 1,235
[1]	(a) Includes amounts related to basis swap contracts totaling 730,721 MMBTU in 2016 and 1,842,048 MMBTU in 2015.

DERIVATIVE FINANCIAL INSTRUME50

DERIVATIVE FINANCIAL INSTRUMENTS FAIR VALUE ON BALANCE SHEET (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 67	$ 107
Derivative Liability	64	106
Derivative Asset	86	30
Derivative Asset, Fair Value, Gross Asset	90	31
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	72	8
Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	29	53
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability		3
Derivative Asset	5	22
Prepayments [Member]
Derivative [Line Items]
Derivative Asset	9
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	58	87
Derivative Liability	58	87
Derivative Asset	71	15
Derivative Asset, Fair Value, Gross Asset	71	15
Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		5
Derivative Liability	0	5
Derivative Asset	9	1
Derivative Asset, Fair Value, Gross Asset	9	1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	9	15
Derivative Liability	6	14
Derivative Asset	6	14
Derivative Asset, Fair Value, Gross Asset	10	15
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	28	37
Derivative Asset, Fair Value, Gross Asset	6
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	4	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	28
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		4
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 Asset, Fair Value, Gross Asset	5
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	39	69
Derivative Asset, Fair Value, Gross Asset	84	30
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	27	33
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	5
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	3	22
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		10
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	3	1
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	4	9
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	2	3
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	3
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	2
Derivative Asset, Fair Value, Gross Asset	2	11
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	2
Derivative Asset, Fair Value, Gross Asset	6
SCE&G
Derivative [Line Items]
Derivative Liability	39	65
Derivative Asset	71	15
SCE&G | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	71	5
SCE&G | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	11	31
SCE&G | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset		10
SCE&G | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	39	65
Derivative Liability	39	65
Derivative Asset	71	15
Derivative Asset, Fair Value, Gross Asset	71	15
SCE&G | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	9	10
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1	1
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	8	9
SCE&G | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	30	55
Derivative Asset, Fair Value, Gross Asset	71	15
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	27	33
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	5
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 3	22
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 10

DERIVATIVE FINANCIAL INSTRUME51

DERIVATIVE FINANCIAL INSTRUMENTS ON INCOME STATEMENT (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ 4	$ (12)	$ (14)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ (13)	$ (22)	$ (3)
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 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	6	15	(4)
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	(5.4)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(34)	(69)	(352)
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	$ 64
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(2)
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	$ 2.4
SCE&G
Derivative [Line Items]
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	$ (34)	$ (69)	$ (352)
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	64
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(2)
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)	(6)
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	0	(3)	(9)
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(2)	(3)	(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	5	(10)	(8)
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	(6)	(15)	4
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	1.8
Cash Flow Hedging [Member] | SCE&G | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	0	(3)	(9)
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)	$ (3)	$ (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	1.8
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	$ 2.4

DERIVATIVE FINANCIAL INSTRUME52

DERIVATIVE FINANCIAL INSTRUMENTS (CREDIT RISK) (Details 3) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	$ 29.2	$ 50.4
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	21.1	44.8
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	50.3	95.2
Cash collateral requested from counterparty	62.9	7.3
Derivative, net asset position	62.9	7.3
Letter of Credit Available Commodity Derivatives,asset position	1.5	3
Commodity Derivative, net asset position	9	14
SCE&G
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	9.2	13.4
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	21.1	43.6
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	30.3	57
Cash collateral requested from counterparty	62	7.3
Derivative, net asset position	$ 62	$ 7.3

DERIVATIVE FINANCIAL INSTRUME53

DERIVATIVE FINANCIAL INSTRUMENTS OFFSETTING ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Liability	$ 64	$ 106
Derivative Asset, Fair Value, Gross Liability	(4)	(1)
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	(9)	(8)
Derivative, Collateral, Obligation to Return Cash
Derivative Asset, Fair Value, Gross Asset	90	31
Derivative Liability, Fair Value, Gross Asset	(3)	(1)
Derivative Liabilities, Net Amount	26	48
Derivative Liability, Fair Value, Gross Liability	67	107
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	(9)	(8)
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	(29)	(50)
Derivative Assets, Net Amount	77	22
Derivative Asset	86	30
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	72	8
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability		3
Derivative Asset	5	22
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	35	50
Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	29	53
Prepayments [Member]
Derivative [Line Items]
Derivative Asset	9
SCE&G
Derivative [Line Items]
Derivative Liability	39	65
Derivative Asset	71	15
SCE&G | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	71	5
SCE&G | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset		10
SCE&G | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	28	34
SCE&G | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	11	31
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability	58	87
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	(9)	(8)
Derivative Asset, Fair Value, Gross Asset	71	15
Derivative Liabilities, Net Amount	20	43
Derivative Liability, Fair Value, Gross Liability	58	87
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	(9)	(8)
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	(29)	(36)
Derivative Assets, Net Amount	62	7
Derivative Asset	71	15
Interest Rate Contract [Member] | SCE&G
Derivative [Line Items]
Derivative Liability	39	65
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	(9)	(8)
Derivative Asset, Fair Value, Gross Asset	71	15
Derivative Liabilities, Net Amount	21	44
Derivative Liability, Fair Value, Gross Liability	39	65
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	(9)	(8)
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	(9)	(13)
Derivative Assets, Net Amount	62	7
Derivative Asset	71	15
Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability	0	5
Derivative Asset, Fair Value, Gross Asset	9	1
Derivative Liabilities, Net Amount	0	0
Derivative Liability, Fair Value, Gross Liability		5
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted		(5)
Derivative Assets, Net Amount	9	1
Derivative Asset	9	1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability	6	14
Derivative Asset, Fair Value, Gross Liability	(4)	(1)
Derivative Asset, Fair Value, Gross Asset	10	15
Derivative Liability, Fair Value, Gross Asset	(3)	(1)
Derivative Liabilities, Net Amount	6	5
Derivative Liability, Fair Value, Gross Liability	9	15
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted		(9)
Derivative Assets, Net Amount	6	14
Derivative Asset	$ 6	$ 14

FAIR VALUE MEASUREMENTS, INCL54

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 86	$ 30
Derivative Liability	$ 64	$ 106
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	$ 14	$ 11
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	7
Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	71	15
Derivative Liability	58	87
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	71	15
Financial and Nonfinancial Liabilities, Fair Value Disclosure	58	87
Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	9	1
Derivative Liability	0	5
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	8	1
Financial and Nonfinancial Liabilities, Fair Value Disclosure		1
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	1
Financial and Nonfinancial Liabilities, Fair Value Disclosure		4
Other Energy Management Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	6	14
Derivative Liability	6	14
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	6
Financial and Nonfinancial Liabilities, Fair Value Disclosure	2	4
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	14
Financial and Nonfinancial Liabilities, Fair Value Disclosure	10	12
SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	71	15
Derivative Liability	$ 39	$ 65
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 | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 71	$ 15
Derivative Liability	39	65
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	71	15
Financial and Nonfinancial Liabilities, Fair Value Disclosure	$ 39	$ 65

FAIR VALUE MEASUREMENTS, INCL55

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other Long-term Debt, Noncurrent	$ 6,489.8	$ 5,997.6
Long-term debt, Fair Value	7,183.3	6,445.7
SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other Long-term Debt, Noncurrent	5,166	4,769
Long-term debt, Fair Value	$ 5,752.3	$ 5,129.1

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year, Description		no
Defined Benefit Plan, Accumulated Benefit Obligation		$ 874,300,000	$ 829,300,000
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		$ 800,000	800,000
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation		$ 700,000	$ 700,000
Defined Benefit Plan Health Care Cost Trend Rate, Assumed		6.60%
Defined Benefit Plan, Target Allocation, Equity Securities		57.00%	57.00%
Defined Benefit Plan, Target Plan Asset Allocations		32.00%	32.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	11.00%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Adoption of modified mortality tables in 2015, gain			$ 2,400,000
Defined Benefit Plan, Benefit Obligation		$ 274,700,000	253,600,000	$ 268,200,000
Defined Benefit Plan, Service Cost		4,400,000	5,300,000	4,600,000
Defined Benefit Plan, Interest Cost		12,100,000	11,400,000	$ 12,000,000
Defined Benefit Plan, Contributions by Plan Participants		1,700,000	2,400,000
Defined Benefit Plan, Actuarial Net (Gains) Losses		(14,000,000)	21,200,000
Defined Benefit Plan, Benefits Paid		$ (11,100,000)	$ (12,500,000)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.30%	4.78%
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 Status of Plan		(274,700,000)	(253,600,000)
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities		(12,600,000)	(11,900,000)
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent		(262,100,000)	(241,700,000)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax		2,500,000	1,700,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax		0	0
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax		2,500,000	1,700,000
pension and other postretirement benefit plans, regulated assets, net gains, before tax		34,700,000	24,000,000
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		0	300,000
Pension and other postretirement benefit plans, regulatory assets, before tax		34,700,000	24,300,000
Defined Benefit Plan, Shared Costs Deferred		15.8	13.8
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		11,100,000	(18,000,000)	$ 19,400,000
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(400,000)	(1,800,000)	0
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		(300,000)	(300,000)	(300,000)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ 10,400,000	$ 20,100,000	$ 19,100,000
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.78%	4.30%	5.19%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.75%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year		7.00%	7.00%	7.40%
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Adoption of modified mortality tables in 2015, gain			$ 21,500,000
Defined Benefit Plan, Benefit Obligation		$ 904,300,000	855,400,000	$ 919,500,000
Defined Benefit Plan, Service Cost		20,700,000	24,100,000	20,000,000
Defined Benefit Plan, Interest Cost		39,400,000	38,200,000	40,400,000
Defined Benefit Plan, Contributions by Plan Participants		0	0
Defined Benefit Plan, Actuarial Net (Gains) Losses		(45,000,000)	62,400,000
Defined Benefit Plan, Benefits Paid		$ (56,200,000)	$ (64,000,000)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.22%	4.68%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.00%	3.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 793,600,000	$ 781,700,000	861,800,000
Defined Benefit Plan, Actual Return on Plan Assets		68,100,000	(16,100,000)
Defined Benefit Plan, Funded Status of Plan		(110,700,000)	(73,700,000)
Defined Benefit Pension Plan, Liabilities, Noncurrent		(110,700,000)	(73,700,000)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax		10,400,000	10,400,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax		100,000	200,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax		10,500,000	10,600,000
pension and other postretirement benefit plans, regulated assets, net gains, before tax		236,100,000	219,400,000
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		2,500,000	5,900,000
Pension and other postretirement benefit plans, regulatory assets, before tax		238,600,000	225,300,000
Defined Benefit Plan, Shared Costs Deferred		23.4	20.3
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		29,400,000	9,200,000	101,300,000
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(12,700,000)	(11,900,000)	(4,000,000)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		(3,400,000)	(3,700,000)	(3,200,000)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ 13,300,000	$ 6,400,000	$ 94,100,000
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		7.50%	7.50%	8.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.68%	4.20%	5.03%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in 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		$ 742,900,000	$ 702,000,000
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		$ 600,000	600,000
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation		$ 600,000	$ 600,000
Defined Benefit Plan Health Care Cost Trend Rate, Assumed		6.60%
Defined Benefit Plan, Target Allocation, Equity Securities		57.00%	57.00%
Defined Benefit Plan, Target Plan Asset Allocations		32.00%	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]
Adoption of modified mortality tables in 2015, gain			$ 2,000,000
Defined Benefit Plan, Benefit Obligation		$ 207,200,000	191,700,000	$ 204,100,000
Defined Benefit Plan, Service Cost		3,600,000	4,400,000	3,600,000
Defined Benefit Plan, Interest Cost		9,900,000	9,400,000	$ 9,400,000
Defined Benefit Plan, Contributions by Plan Participants		1,300,000	1,900,000
Defined Benefit Plan, Actuarial Net (Gains) Losses		(11,500,000)	15,700,000
Defined Benefit Plan, Benefits Paid		(9,100,000)	(10,300,000)
Defined Benefit Plan, Amounts Funded to Parent		$ (1,700,000)	$ (2,100,000)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.30%	4.78%
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 Status of Plan		(207,200,000)	(191,700,000)
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities		(10,400,000)	(9,800,000)
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent		(196,800,000)	(181,900,000)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax		1,000,000	700,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax		0	0
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax		1,000,000	700,000
pension and other postretirement benefit plans, regulated assets, net gains, before tax		29,300,000	20,400,000
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		0	200,000
Pension and other postretirement benefit plans, regulatory assets, before tax		29,300,000	20,600,000
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		9,200,000	(14,000,000)	$ 15,800,000
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(300,000)	(1,500,000)	0
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		(200,000)	(300,000)	(200,000)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ 8,700,000	$ 15,800,000	$ 15,600,000
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.78%	4.30%	5.19%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.75%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year		7.00%	7.00%	7.40%
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Adoption of modified mortality tables in 2015, gain			$ 18,200,000
Defined Benefit Plan, Benefit Obligation		$ 768,400,000	724,000,000	$ 773,700,000
Defined Benefit Plan, Service Cost		16,900,000	19,300,000	16,000,000
Defined Benefit Plan, Interest Cost		33,400,000	32,200,000	34,100,000
Defined Benefit Plan, Contributions by Plan Participants		0	0
Defined Benefit Plan, Actuarial Net (Gains) Losses		(41,800,000)	47,000,000
Defined Benefit Plan, Benefits Paid		(47,700,000)	(54,200,000)
Defined Benefit Plan, Amounts Funded to Parent		$ 0	$ 0
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.22%	4.68%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.00%	3.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 732,900,000	$ 720,100,000	783,600,000
Defined Benefit Plan, Actual Return on Plan Assets		60,500,000	(9,300,000)
Defined Benefit Plan, Funded Status of Plan		(35,500,000)	(3,900,000)
Defined Benefit Pension Plan, Liabilities, Noncurrent		(35,500,000)	(3,900,000)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax		1,900,000	2,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax		0	0
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax		1,900,000	2,000,000
pension and other postretirement benefit plans, regulated assets, net gains, before tax		208,800,000	193,700,000
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax		2,200,000	5,200,000
Pension and other postretirement benefit plans, regulatory assets, before tax		211,000,000	198,900,000
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax		26,300,000	12,200,000	87,700,000
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax		(11,200,000)	(10,400,000)	(3,500,000)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax		(3,000,000)	(3,100,000)	(2,800,000)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax		$ 12,100,000	$ 1,300,000	$ 81,400,000
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		7.50%	7.50%	8.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.68%	4.20%	5.03%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.00%
Pension Costs [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority		$ 14,000,000			$ 63,000,000
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 Return on Assets	7.25%
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 Return on Assets	7.25%
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, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities		57.00%	57.00%
Defined Benefit Plan, Target Plan Asset Allocations		32.00%	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		57.00%	57.00%
Defined Benefit Plan, Target Plan Asset Allocations		32.00%	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 EMPLOY58

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Mutual funds pension plan assets reclassified as Common collective trust		$ 413
Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		14
Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		22
Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		78
Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		14
Common collective trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investments, Fair Value Disclosure	$ 453	413
Joint venture interests [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investments, Fair Value Disclosure	86	83
Limited Partner [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investments, Fair Value Disclosure	0	33
Alternative investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investments, Fair Value Disclosure	794	782
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	255	253
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	125	$ 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	16
Fair Value, Inputs, Level 2 [Member] | Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	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	82
Fair Value, Inputs, Level 2 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 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
Mutual funds pension plan assets reclassified as Common collective trust		$ 381
SCE&G | Common collective trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investments, Fair Value Disclosure	$ 418	381
SCE&G | Joint venture interests [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investments, Fair Value Disclosure	79	77
SCE&G | Limited Partner [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investments, Fair Value Disclosure	0	30
SCE&G | Alternative investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Alternative Investments, Fair Value Disclosure	733	720
SCE&G | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	236	232
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	115	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	15	12
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	17	20
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	76	72
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	$ 13	$ 13

EMPLOYEE BENEFIT PLANS EMPLOY59

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 4) $ in Millions	Dec. 31, 2016USD ($)
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 63.1
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	65.1
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	64.5
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	64.7
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	67.1
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	324.4
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	12.9
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	13.7
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	14.5
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	15.3
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	15.9
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	86
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	63.1
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	65.1
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	64.5
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	64.7
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	67.1
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	324.4
SCE&G | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	10.6
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	11.2
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	11.9
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	12.5
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	13.1
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	$ 70.5

EMPLOYEE BENEFIT PLANS EMPLOY60

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax		$ 0	$ 0	$ 1
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax		$ 1	0	4
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 Recognized		$ 27.5	26.2	25.8
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax		0.6	2.7	3.1
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		(0.6)	(0.4)	(0.2)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax		(0.1)	(0.1)	(0.2)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax		(0.1)	2.2	2.7
Defined Benefit Plan, Service Cost		20.7	24.1	20
Defined Benefit Plan, Interest Cost		39.4	38.2	40.4
Defined Benefit Plan, Expected Return on Plan Assets		(55.9)	(62)	(66.7)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		3.9	4.1	4.1
Defined Benefit Plan, Amortization of Gains (Losses)		14.8	13.6	4.8
Defined Benefit Plan, Net Periodic Benefit Cost		$ 22.9	$ 18	$ 2.6
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.68%	4.20%	5.03%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		7.50%	7.50%	8.00%
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), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax		$ 0.8	$ (1.2)	$ 1.3
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax		0	(0.1)	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax		0	(0.1)	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax		0.8	(1.4)	1.3
Defined Benefit Plan, Service Cost		4.4	5.3	4.6
Defined Benefit Plan, Interest Cost		12.1	11.4	12
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0.3	0.4	0.3
Defined Benefit Plan, Amortization of Gains (Losses)		0.5	2.1	0
Defined Benefit Plan, Net Periodic Benefit Cost		$ 17.3	$ 19.2	$ 16.9
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.78%	4.30%	5.19%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.75%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year		7.00%	7.00%	7.40%
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), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of 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 Recognized		$ 22.9	21.8	20.7
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax		0	0.2	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	(0.1)	(0.1)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax		(0.1)	0	0
Defined Benefit Plan, Service Cost		16.9	19.3	16
Defined Benefit Plan, Interest Cost		33.4	32.2	34.1
Defined Benefit Plan, Expected Return on Plan Assets		(47.4)	(52.2)	(56.3)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		3.4	3.4	3.5
Defined Benefit Plan, Amortization of Gains (Losses)		12.5	11.4	4
Defined Benefit Plan, Net Periodic Benefit Cost		$ 18.8	$ 14.1	$ 1.3
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.68%	4.20%	5.03%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		7.50%	7.50%	8.00%
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), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax		$ 0.3	$ (0.3)	$ 0.4
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, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax		0.3	(0.3)	0.4
Defined Benefit Plan, Service Cost		3.6	4.4	3.6
Defined Benefit Plan, Interest Cost		9.9	9.4	9.4
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0.3	0.3	0.3
Defined Benefit Plan, Amortization of Gains (Losses)		0.4	1.7	0
Defined Benefit Plan, Net Periodic Benefit Cost		$ 14.2	$ 15.8	$ 13.3
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.78%	4.30%	5.19%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.00%	3.00%	3.75%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year		7.00%	7.00%	7.40%
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 Return on Assets	7.25%
Scenario, Forecast [Member] | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Amortization of Net Gains (Losses)	$ 0.6
Defined Benefit Plan, Amortization of Net Prior Service Cost (Credit)	0.1
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	0.7
Defined benefit plan, future amortization of gain or loss from regulatory assets	13.6
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	1.4
Defined benefit plan, amount to be amortized from regulatory assets next year	15
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, Amortization of Net Prior Service Cost (Credit)	0
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	0.1
Defined benefit plan, future amortization of gain or loss from regulatory assets	1.2
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	$ 1.2
Scenario, Forecast [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	7.25%
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	$ 12
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets	1.3
Defined benefit plan, amount to be amortized from regulatory assets next year	13.3
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
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

SHARE-BASED COMPENSATION (Detai

SHARE-BASED COMPENSATION (Details)	Dec. 31, 2016shares
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, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Liability Awards
Cash-Settled Liabilities		$ 18.4	$ 20.8	$ 11.8
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 23.4
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		$ 25.6	18	20.3
Capitalized Compensation Expense		$ 3.3	2.3	3.1
Restricted Stock Units
Liability Awards
Percentage of Performance Award Granted in Form of Restricted Stock Units (as a percent)		20.00%
Performance Shares [Member]
Liability Awards
Percentage of Performance Award Granted in Form of Performance Shares (as a percent)		80.00%
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%
SCE&G
Liability Awards
Cash-Settled Liabilities		$ 13.2	6.3	1.9
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		17.2
Compensation Expenses Recognized Resulting From Fair Value Adjustments of Performance Awards		17.3	12.2	12.6
Capitalized Compensation Expense		$ 3.1	$ 0.6	$ 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)		20.00%
SCE&G | Performance Shares [Member]
Liability Awards
Percentage of Performance Award Granted in Form of Performance Shares (as a percent)		80.00%
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]
Liability Awards
Cash-Settled Liabilities	$ 28
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
Liability Awards
Cash-Settled Liabilities	$ 20.2
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, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Commitments and contingencies
Operating Leases, Rent Expense	$ 10.2	$ 11.1	$ 12.3
Operating Leases, Future Minimum Payments Due, Next Twelve Months	31,000,000
Operating Leases, Future Minimum Payments, Due in Two Years	29,000,000
Operating Leases, Future Minimum Payments, Due in Three Years	28,000,000
Operating Leases, Future Minimum Payments, Due in Four Years	3,000,000
Operating Leases, Future Minimum Payments, Due in Five Years	3,000,000
Operating Leases, Future Minimum Payments, Due Thereafter	23,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	1,700,000,000
Asset Retirement Obligation Other Conditional Obligations	359,000,000
Asset Retirement Obligation	558,000,000	520,000,000	563,000,000
Asset Retirement Obligation, Liabilities Incurred	0	0
Asset Retirement Obligation, Liabilities Settled	(11,000,000)	(16,000,000)
Asset Retirement Obligation, Accretion Expense	23,000,000	25,000,000
Asset Retirement Obligation, Revision of Estimate	$ 26,000,000	$ (52,000,000)
Environmental
Emission Rate Standard For Coal Fired Power Plants Under Clean Air Act		1,400
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	$ 12.2	$ 12.3	12.1
Operating Leases, Future Minimum Payments Due, Next Twelve Months	25,000,000
Operating Leases, Future Minimum Payments, Due in Two Years	23,000,000
Operating Leases, Future Minimum Payments, Due in Three Years	22,000,000
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	323,000,000
Asset Retirement Obligation	522,000,000	488,000,000	$ 536,000,000
Asset Retirement Obligation, Liabilities Incurred	0	0
Asset Retirement Obligation, Liabilities Settled	(11,000,000)	(16,000,000)
Asset Retirement Obligation, Accretion Expense	22,000,000	23,000,000
Asset Retirement Obligation, Revision of Estimate	23,000,000	$ (55,000,000)
Nuclear Insurance
scg_Maximum Insurance Coverage for each Nuclear Plant by ANI	375,000,000
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	45,800,000
Maximum amount of coverage to nuclear facility for property damage and outage costs	2,750,000,000
Maximum amount of coverage for accidental property damage	500,000,000
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	1,800,000
Environmental
Environmental Remediation Expense	10,200,000
Deferred costs, net of costs previously recovered through rates and insurance settlements included in regulatory assets	25,700,000
Nuclear Generation
Asset Retirement Obligation Nuclear Decommissioning	199,000,000
SCE&G | SCE&G
Nuclear Insurance
Maximum yearly assessment per reactor	$ 12,600,000

COMMITMENTS AND CONTINGENCIES N

COMMITMENTS AND CONTINGENCIES Nuclear (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Mar. 31, 2017	Dec. 31, 2015
SCE&G
EPC Contract Amendment, Payment And Performance Bonds, Percentage of Billing	15.00%
EPC Contract Amendment, Payment And Performance Bonds, Maximum Aggregate Nominal Coverage	$ 55
EPC Contract Amendment, Payment and Performance Bonds	$ 25
Dispute Review Board Resolution Without Recourse	less than $5 million
Dispute Review Board Resolution Subject To Litigation	greater than $5 million
EPC Amendment, Fixed Price Option, Price for subcontractor and other supplier-related costs subject to Dec 2016 DRB order	$ 873
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
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	3,345
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	186
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus	83
November 2016 SCPSC Approved Project Costs above SCPSC 2015 order	831
Summer Station New Units and Transmission Assets [Domain]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	4,500
Summer Station New Units [Domain]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	4,200					$ 3,400
jointly owned utility plant ownership, construction financing cost	3,800
EPC Contract Amendment, Payment And Performance Bonds, Maximum Aggregate Nominal Coverage	100
EPC Contract Amendment, Payment and Performance Bonds	45
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	6,082
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	338
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus	150
Nuclear Production Tax Credits	$ 1,400
Nuclear Production Tax Credit realization period	8
Scenario, Forecast [Member]
Estimated Toshiba impairment loss					$ 6,000
Scenario, Forecast [Member] | SCE&G
Additional ownership in new units		2.00%	2.00%	1.00%
Maximum [Member] | SCE&G
Additional ownership in new units, dollars	$ 850

AFFILIATED TRANSACTIONS - SCEG

AFFILIATED TRANSACTIONS - SCEG (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Affiliated Transaction [Line Items]
Proceeds from Equity Method Investment, Dividends or Distributions	$ 3.7	$ 4	$ 7.8
Equity Method Investments	5.5	4.1	5.7
Related Party Transaction, Expenses from Transactions with Related Party	337.7	300	292.2
Canadys Refined Coal LLC [Member]
Affiliated Transaction [Line Items]
Related Party Transaction Purchases from Related Party	161.8	233.2	260.3
Sales to Affiliate	$ 160.8	232	259
Equity Method Investment, Ownership Percentage	40.00%
Related Party Tax Expense, Due from Affiliates, Current	$ 16	12.8
Related Party Tax Expense, Due to Affiliates, Current	16.1	12.9
SCE&G
Affiliated Transaction [Line Items]
Due to Affiliate, Current	122	113
Due from Affiliate, Current	16	22
Related Party Transaction, Due from (to) Related Party, Current		9
Accounts Payable, Related Parties, Current	63.5	57
CGT [Member]
Affiliated Transaction [Line Items]
Related Party Transaction Purchases from Related Party		3.4	30
Retail Gas and Energy Marketing Segment [Member]
Affiliated Transaction [Line Items]
Due to Affiliate, Current	8.8	7.5
Cost of Natural Gas Purchases	$ 111.5	$ 128.5	$ 195.7

SEGMENT OF BUSINESS INFORMATI66

SEGMENT OF BUSINESS INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Gain (Loss) On Disposition Of Regulated Business Net Of Transaction Costs										$ 234
Total	$ 18,707				$ 17,146				$ 18,707	17,146	$ 16,818
Additions to Other Assets, Amount									1,579	1,153	1,092
Deferred Tax Assets, Gross	0				0				0	0	0
Electric Domestic Regulated Revenue									2,614	2,551	2,622
Regulated and Unregulated Operating Revenue	1,057	$ 1,093	$ 905	$ 1,172	956	$ 1,068	$ 967	$ 1,389	4,227	4,380	4,951
Intersegment Revenue									0	0	0
Operating Income	253	348	221	331	214	292	216	586	1,153	1,308	1,007
Interest Expense									342	318	312
Depreciation, Depletion and Amortization									371	358	384
Income Tax Expense (Benefit)									271	393	248
Income Available to Common Shareholders	125	189	105	176	98	149	99	400	595	746	538
Regulated Operating Revenue, Gas									788	811	1,028
Electric Operations
Segment Reporting Information [Line Items]
Total	11,929				10,883				11,929	10,883	10,182
Additions to Other Assets, Amount									1,275	1,087	936
Deferred Tax Assets, Gross	(9)				(5)				(9)	(5)	(11)
Electric Domestic Regulated Revenue									2,614
Intersegment Revenue									5	6	7
Operating Income									957	876	768
Interest Expense									17	17	19
Depreciation, Depletion and Amortization									287	277	300
Income Tax Expense (Benefit)									8	9	7
Gas Distribution
Segment Reporting Information [Line Items]
Total	2,892				2,606				2,892	2,606	2,487
Additions to Other Assets, Amount									276	203	200
Deferred Tax Assets, Gross	(32)				(29)				(32)	(29)	(29)
Regulated and Unregulated Operating Revenue									788	810	1,012
Intersegment Revenue									2	2	2
Operating Income									148	152	159
Interest Expense									25	23	22
Depreciation, Depletion and Amortization									82	77	72
Income Tax Expense (Benefit)									32	32	33
Gas Marketing [Member]
Segment Reporting Information [Line Items]
Total	230				201				230	201	290
Additions to Other Assets, Amount									2	2	2
Deferred Tax Assets, Gross	(11)				(15)				(11)	(15)	(20)
Regulated and Unregulated Operating Revenue									825	1,018	1,301
Intersegment Revenue									111	128	196
Interest Expense									1	1	1
Depreciation, Depletion and Amortization									2	2	2
Income Tax Expense (Benefit)									19	18	19
Income Available to Common Shareholders									30	28	31
All Other [member]
Segment Reporting Information [Line Items]
Total	1,124				998				1,124	998	1,474
Additions to Other Assets, Amount									11	15	52
Deferred Tax Assets, Gross	0				0				0	0	(15)
Regulated and Unregulated Operating Revenue									0	5	37
Intersegment Revenue									414	413	437
Operating Income									0	236	27
Interest Expense									0	1	5
Depreciation, Depletion and Amortization									16	16	24
Income Tax Expense (Benefit)									0	1	12
Income Available to Common Shareholders									(18)	185	(6)
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Total	2,532				2,458				2,532	2,458	2,385
Additions to Other Assets, Amount									15	(154)	(98)
Deferred Tax Assets, Gross	52				49				52	49	75
Regulated and Unregulated Operating Revenue									0	(4)	(21)
Intersegment Revenue									(532)	(549)	(642)
Operating Income									48	44	53
Interest Expense									299	276	265
Depreciation, Depletion and Amortization									(16)	(14)	(14)
Income Tax Expense (Benefit)									212	333	177
Income Available to Common Shareholders									583	533	513
SCE&G
Segment Reporting Information [Line Items]
Total	16,091				14,765				16,091	14,765	14,078
Additions to Other Assets, Amount									1,399	1,008	934
Deferred Tax Assets, Gross	0				0				0	0	0
Electric Domestic Regulated Revenue									2,614	2,551	2,621
Regulated Operating Revenue	695	882	692	717	643	806	709	772	2,986	2,930	3,091
Operating Income	196	$ 359	$ 222	$ 236	172	$ 307	$ 218	$ 237	1,013	934	830
Interest Expense									270	248	228
Depreciation, Depletion and Amortization									302	294	315
Income Tax Expense (Benefit)									248	231	218
Regulated Operating Revenue, Gas									366	372	461
SCE&G | Electric Operations
Segment Reporting Information [Line Items]
Total	11,929								11,929		10,182
Additions to Other Assets, Amount									1,275		936
Deferred Tax Assets, Gross	(9)								(9)		(11)
Operating Income									957		768
Interest Expense									17	17	19
Depreciation, Depletion and Amortization									287	277	300
SCE&G | Gas Distribution
Segment Reporting Information [Line Items]
Total	825				757				825	757	721
Additions to Other Assets, Amount									78	57	55
Regulated and Unregulated Operating Revenue									367	373	462
Operating Income									56	58	62
Depreciation, Depletion and Amortization									28	28	27
SCE&G | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Total	3,337				3,125				3,337	3,125	3,175
Additions to Other Assets, Amount									46	(136)	(57)
Deferred Tax Assets, Gross	$ 9				$ 5				9	5	11
Operating Income											0
Interest Expense									253	231	209
Depreciation, Depletion and Amortization									(13)	(11)	(12)
External revenue [Member] | SCE&G
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue									$ 2,619	$ 2,557	$ 2,629

DISPOSITIONS (Details)

DISPOSITIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016
Public Utilities, Property, Plant and Equipment, Net	$ 13,145	$ 14,324
Nonutility Property and Investments, Net	466	475
Assets, Current	1,378	1,506
Regulated Entity, Other Assets, Noncurrent	2,157	2,402
Liabilities, Current	1,952	2,065
Liabilities, Noncurrent	3,869	$ 4,444
Pre-tax gain on sale of CGT and SCI	$ 342

QUARTERLY FINANCIAL INFORMATI68

QUARTERLY FINANCIAL INFORMATION (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Regulated and Unregulated Operating Revenue	$ 1,057	$ 1,093	$ 905	$ 1,172	$ 956	$ 1,068	$ 967	$ 1,389	$ 4,227	$ 4,380	$ 4,951
Operating Income (Loss)	253	348	221	331	214	292	216	586	1,153	1,308	1,007
Income Available to Common Shareholders	$ 125	$ 189	$ 105	$ 176	$ 98	$ 149	$ 99	$ 400	$ 595	$ 746	$ 538
Earnings Per Share, Basic and Diluted	$ 0.87	$ 1.32	$ 0.74	$ 1.23	$ 0.69	$ 1.04	$ 0.69	$ 2.80	$ 4.16	$ 5.22	$ 3.79
SCE&G
Regulated Operating Revenue	$ 695	$ 882	$ 692	$ 717	$ 643	$ 806	$ 709	$ 772	$ 2,986	$ 2,930	$ 3,091
Operating Income (Loss)	196	359	222	236	172	307	218	237	1,013	934	830
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	93	204	113	116	76	167	111	126	526	480	458
Net Income (Loss) Attributable to Parent	$ 89	$ 201	$ 110	$ 113	$ 73	$ 164	$ 107	$ 122	$ 513	$ 466	$ 446

Schedule II (Details)

Schedule II (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	$ 6	$ 5	$ 7	$ 6
Valuation Allowances and Reserves, Charged to Cost and Expense	12	12	16
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	11	14	15
General Liability [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	9	6	5	6
Valuation Allowances and Reserves, Charged to Cost and Expense	5	11	7
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	2	10	8
SCE&G | Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	3	3	4	3
Valuation Allowances and Reserves, Charged to Cost and Expense	6	6	8
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	6	7	7
SCE&G | General Liability [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	8	5	3	$ 5
Valuation Allowances and Reserves, Charged to Cost and Expense	5	11	1
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	$ 2	$ 9	$ 3